10-K

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, 2022

OR

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	x
		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, 2022 was approximately $102.2 million.

The total number of shares of common stock, par value $0.001 per share, outstanding as of March 1, 2023 was 20,158,934.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of this 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 2023, 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, 2022
TABLE OF CONTENTS
		Page
Part I
Items 1 and 2.	Business and Properties	8
Item 1A.	Risk Factors	28
Item 1B.	Unresolved Staff Comments	57
Item 3.	Legal Proceedings	57
Item 4.	Mine Safety Disclosures	57
Part II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	58
Item 6.	Selected Financial Data	59
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	59
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	70
Item 8.	Financial Statements and Supplementary Data	70
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	70
Item 9A.	Controls and Procedures	70
Item 9B.	Other Information	73
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	74
Item 11.	Executive Compensation	74
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	74
Item 13.	Certain Relationships and Related Transactions, and Director Independence	74
Item 14.	Principal Accountant Fees and Services	74
Part IV
Item 15.	Exhibits and Financial Statements Schedules	75
Item 16.	Form 10-K Summary	78
Signatures		79

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DEFINITIONS

As used in this Annual Report on Form 10-K (the "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
MMBtu	One million British thermal units
MMcf	One million cubic feet of gas
Abbreviations.
ARO	Asset Retirement Obligation
BLM	Bureau of Land Management
CO2	Carbon Dioxide
CWA	Clean Water Act
DD&A	Depreciation, depletion and amortization
EOR	Enhanced Oil Recovery
EPA	Environmental Protection Agency
ESG	Environmental, social, and governance
FERC	Federal Energy Regulatory Commission
GHG	Greenhouse Gas
IRS	Internal Revenue Service
LIBOR	London Interbank Offered Rate
NGA	Natural Gas Act of 1938
NGL	Natural gas liquids
NGPA	Natural Gas Policy Act of 1978
NSAI	Netherland, Sewell & Associates, Inc.
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
Oil	Crude oil and condensate
RRC	Railroad Commission of Texas
SEC	Securities and Exchange Commission
SOFR	Secured Overnight Financing Rate
SWD	Saltwater Disposal Well.
U.S. GAAP	Accounting principles generally accepted in the United States of America
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.
Estimated ultimate recovery (EUR)	Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
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 reserve additions	The sum of additions to proved reserves from extensions, discoveries, improved recovery, acquisitions, and revisions of previous estimates.
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. 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. In light 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

•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 projects, which could lead to a decline in our reserves.

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

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

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

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

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

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

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

•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 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.

Risks Related to the Oil and Natural Gas Industry

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

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

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

Risks Related to COVID-19, Acts of God, and Cyber Security

•Our business and operations may be adversely affected by the recent COVID-19 pandemic or other similar outbreaks.

•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.

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Risks Related to Legal, Regulatory, and Tax Matters

•Regulations related to environmental and occupational health and safety issues 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 could cause our revenues to decline and operating expenses to increase.

•Regulatory initiatives relating to hydraulic fracturing, regulation of greenhouse gases, weatherization, or protection of certain species of wildlife 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.

•The Board 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 the acquisition, exploration, development and production of oil, natural gas and NGLs in Texas and New Mexico. Our activities primarily target the horizontal development of the San Andres formation, a shelf margin deposit on the Northwest Shelf of the Permian Basin. The majority of our acreage is located on large, contiguous blocks in Yoakum County, Texas (the "Champions Assets").

We were formed as a Delaware limited liability company, Riley Exploration – Permian, LLC ("REP LLC"), in 2016. On February 26, 2021 (the “Closing Date”), Riley Exploration Permian, Inc., a Delaware corporation (f/k/a Tengasco, Inc. (“Tengasco”)), consummated a merger pursuant to that certain Agreement and Plan of Merger (“Merger Agreement”), dated as of October 21, 2020, by and among Tengasco, Antman Sub, LLC, a newly formed Delaware limited liability company and wholly-owned subsidiary of Tengasco (“Merger Sub”), and REP LLC, as amended by Amendment No. 1 to Agreement and Plan of Merger, dated as of January 20, 2021, by and among Tengasco, Merger Sub and REP LLC. Pursuant to the terms of the Merger Agreement, a business combination between Tengasco and REP LLC was effected through the merger of Merger Sub with and into REP LLC, with REP LLC as the surviving company and as a wholly-owned subsidiary of Tengasco (collectively, with the other transactions described in the Merger Agreement, the “Merger”). On the Closing Date, Tengasco changed its name to Riley Exploration Permian, Inc. Our organizational structure includes wholly-owned consolidated subsidiaries through which our operations are conducted, including without limitation, REP LLC and Riley Permian Operating Company, LLC.

The Merger was accounted for as a reverse merger and, as such, REP LLC is considered the Company’s accounting predecessor and its historical operations are deemed to be those of the Company.

On August 16, 2022, the Company's Board of Directors (the "Board") acting by written consent resolved to amend and restate the Company's Second Amended and Restated Bylaws to change the Company's fiscal year period from October 1st through September 30th each year to January 1st through December 31st each year commencing with the 2022 calendar year (the "Bylaws Restatement"). On August 19, 2022, the holders of approximately 75% of our outstanding Common Stock acting by written consent approved the Bylaws Restatement and adopted the Third Amended and Restated Bylaws. In accordance with Rule 14c-2 under the Exchange Act, the aforementioned actions taken by written consent became effective on September 23, 2022. As a result, the Company's 2022 fiscal year was the period from January 1, 2022 to December 31, 2022.

Acquisition in 2023

On February 22, 2023, the Company entered into a purchase and sale agreement (the "Purchase Agreement") to acquire interests in oil and natural gas leases and related property with Pecos Oil & Gas, LLC (“Pecos”) for a purchase price of approximately $330 million, subject to customary closing adjustments, (the “New Mexico Acquisition”). The oil and natural gas leases are located in the Yeso trend of the Permian Basin in Eddy County of New Mexico. On February 22, 2023, in connection with the Purchase Agreement, REP deposited $33 million in cash into a third party escrow account, which will be credited against the purchase price upon closing. See Note 15 - Subsequent Events for further discussion.

In connection with the Purchase Agreement, the Company entered into a commitment letter dated February 22, 2023 (the "Commitment Letter") with EOC Partners Advisors L.P. and/or one of its affiliates (collectively, "EOC") in which EOC and/or one of its affiliates will purchase $200 million of unsecured senior notes ("Senior Notes") from the Company as of the closing date of the New Mexico Acquisition. The proceeds of the Senior Notes will be used to fund a portion of the purchase price of the New Mexico Acquisition and to pay fees, costs and expenses related to the New Mexico Acquisition and the related financing transactions. The funding of the Senior Notes is contingent on the satisfaction or waiver of certain conditions set forth in the Commitment Letter. See Note 15 - Subsequent Events for further discussion.

Developments in 2022

EOR Project. The Company continued development of its EOR project, which seeks to lower decline rates and ultimately increase recovery of oil by injecting a combination of water and CO2 through vertical wells, applied to horizontal producing wells in Yoakum County, Texas (the "EOR Project"). These wells are directly adjacent to several of the largest EOR projects in the U.S., which have employed EOR techniques for many decades. See "—Development Opportunities" below for additional information.

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Market Conditions, Commodity Prices and Interest Rates. Commodity prices experienced exceptional volatility during 2022 due to ongoing geopolitical events and fluctuating supply/demand factors. In addition, global markets experienced supply shortages and corresponding significant inflation across a wide variety of products, services and wages. As a result, the U.S. Federal Reserve and other international central banks began tightening monetary policies during 2022, including increasing short-term borrowing rates. This changing monetary policy has impacted credit and capital markets with generally increased costs of borrowing and heightened volatility in capital markets.

Our Business Strategy

Our strategy is to create and deliver long-term shareholder value through the following:

•Steadily grow cash flow from operations through development of our existing assets and continuous improvement of our operating capabilities. We intend to grow our production and reserves through development of our multi-year drilling inventory, which we believe offers economically attractive investment opportunities in the current environment. We believe such growth and corresponding increase in scale can lead to operating cost efficiencies and may further expand margins. Our management, operating and technical teams strive to continually improve our operating capabilities and cost structure, with an objective of reducing per unit costs and enhancing returns. We seek to grow within the limits of conservative capital allocation, often reinvesting less than our operating cash flows.

•Identify attractive new opportunities for capital investment. Our business produces one of the most highly demanded and valuable commodities in the world, which society uses across many fundamental aspects of everyday life. We believe investing in oil and natural gas assets continues to represent an attractive opportunity. Concurrently, we acknowledge a growing discussion for decarbonizing economies and the associated potential impacts on our business. We believe opportunities may arise in the oil and natural gas business as capital allocation priorities shift at some larger oil and natural gas companies, or restrict at other oil and natural gas companies, potentially providing for value-creating opportunities for Riley Permian. We believe our business could benefit from increased scale, and we will seek out attractive merger and acquisition opportunities. Further, we believe it is prudent to monitor the transitioning energy landscape and identify arising investment opportunities in which the Company may have competitive strengths and opportunities. One example of such potential opportunity includes the Company’s investigative efforts into carbon capture, utilization and sequestration ("CCUS") projects, for which we believe we may be well-positioned based on the characteristics of our assets.

•Distribute excess returns to stockholders in the form of dividends. We believe we can often grow production and cash flow in excess of required capital and operating costs. We believe that distributing a meaningful portion of our cash generated by operating activities provides stockholders the combination of a current return and increased certainty for a portion of long-term value. Because the oil and natural gas business is capital intensive, and because we recognize many benefits of growth, management will strive to seek an appropriate balance of reinvesting for growth versus other capital allocation choices, such as reducing debt or returning capital back to stockholders.

Our Competitive Strengths

We believe that the following strengths will allow us to successfully execute our business strategies:

•Proven and incentivized management team with substantial expertise and long-term perspective. Our executive team has a proven track record of operating and managing oil and natural gas companies across industry cycles. We have successfully managed development programs across various basins, including significant experience in the Northwest Shelf region of the Permian Basin, among other basins. Our Chief Executive Officer, Bobby Riley, was one of the original designers of systems for down-hole data acquisition in gravel pack and frack pack operations and has more than 40 years of experience in the independent oil and natural gas sector. We believe the executive management team has a vested and aligned interest in creating value for stockholders, with equity ownership in the Company. Management prioritizes corporate sustainability, including positioning the Company for success in both the near-term and long-term with initiatives focused on existing business and the transitioning energy landscape.

•Premier, low-decline asset in one of North America’s leading oil resource plays. Our acreage is primarily characterized by a multi-year, oil-weighted inventory of horizontal drilling locations that we believe provides attractive growth and return opportunities. We believe that investments in our core assets are capable of producing returns that are competitive with many of the top-performing oil and natural gas basins in the U.S. We believe this positions our business to perform well across a range of commodity price environments. Further, the conventional nature of the San Andres, the producing reservoir of our core assets, allows for a lower base decline rate as compared to most

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unconventional or shale basins in the U.S. A lower base decline rate leads to less new production needed in order to maintain or grow production.

•High degree of operational control. We control, and intend to maintain control, of a substantial majority of our producing properties and drilling inventory. We believe this practice best leverages the experience of our management and technical teams and can lead to improvements in our operating cost structure, selection of drilling and completion techniques, greater flexibility to react to market changes and overall enhanced long-term returns. We also made the strategic decision to own and operate the salt water disposal systems and electricity distribution infrastructure necessary to support operations. This has allowed us to significantly reduce our operating costs and keep pace with our expected development program.

•Financial flexibility. We strive to maintain financial flexibility that will allow us to execute our business strategies on existing and potentially new businesses. We expect to continue our oil and natural gas development activities by funding the majority of capital expenditures with operating cash flow. From time to time we may seek outside sources of capital for acquisitions and new ventures. As of December 31, 2022, the borrowing base of our revolving credit facility was $225 million and we had $169 million available for borrowing. We also have the ability to scale up or drawback on our commodity hedging program that seeks to reduce our exposure to downside commodity price fluctuations as part of our maintenance of a conservative financial management program.

Our Properties

As of December 31, 2022, we had approximately 30,470 net acres and a total of 100 net producing wells. We operated 93% of our net production for the year ended December 31, 2022, and have an average working interest of 95% in our operated wells. Our average net daily production during the year ended December 31, 2022 was approximately 11,505 Boe/d.

Our acreage is primarily located on large contiguous blocks in Yoakum County, Texas with additional acreage located in Lea and Roosevelt Counties, New Mexico. Riley Permian’s acreage in Yoakum County offsets legacy Permian Basin San Andres fields, including the Wasson and Brahaney Fields, which have produced more than 2.1 billion barrels of oil equivalent and 108 million barrels of oil equivalent, respectively, from the San Andres Formation since development in the area began in the 1930’s and 1940’s. Based on the close proximity to these productive fields, combined with the horizontal San Andres wells we have drilled to date and the wells drilled by offset operators, we believe we have significantly delineated our acreage.

The Permian Basin is an oil and natural gas producing area located in West Texas and the adjoining area of southeastern New Mexico covering an area approximately 250 miles wide and 300 miles long, and encompasses several sub-basins, including the Delaware Basin, Midland Basin, Central Basin Platform and Northwest Shelf. The San Andres Formation is a shelf margin deposit composed of dolomitized carbonates.

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Oil, Natural Gas and NGL Reserves

Summary of Oil, Natural Gas and NGL Reserves

The following table summarizes the Company's estimated proved reserves as of December 31, 2022, September 30, 2021, and September 30, 2020 based on the reserve reports prepared by NSAI in accordance with rules and regulations of the SEC.

	December 31,	September 30,
	2022	2021	2020
Proved Developed Producing Reserves:(1)
Oil (MBbls)	29,632	25,820	19,149
Natural Gas (MMcf)	59,314	45,712	31,137
Natural Gas Liquids (MBbls)	9,604	7,530	5,847
Proved Developed Producing Reserves (MBoe)	49,122	40,968	30,186
Proved Developed Non-Producing Reserves:
Oil (MBbls)	—	350	—
Natural Gas (MMcf)	—	461	—
Natural Gas Liquids (MBbls)	—	120	—
Proved Developed Non-Producing Reserves (MBoe)	—	548	—
Proved Undeveloped Reserves:
Oil (MBbls)	19,250	20,093	18,009
Natural Gas (MMcf)	26,704	29,846	22,546
Natural Gas Liquids (MBbls)	4,850	5,579	4,834
Proved Undeveloped Reserves (MBoe)	28,551	30,647	26,601
Total Proved Reserves:
Oil (MBbls)	48,882	46,263	37,158
Natural Gas (MMcf)	86,018	76,019	53,683
Natural Gas Liquids (MBbls)	14,454	13,229	10,681
Total Proved Reserves (MBoe)	77,673	72,163	56,787

_____________________

(1)Total proved reserves were comprised of 63%, 57%, and 53%, respectively, of total proved developed producing reserves as of December 31, 2022, September 30, 2021, and September 30, 2020.

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, 2022, September 30, 2021, and September 30, 2020 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 16 - Supplemental Information on Oil and Natural Gas Operations to the Company's consolidated financial statements included herein for further discussion of our reserve estimates and pricing.

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Proved Undeveloped Reserves (PUDs)

The following table summarizes changes in the Company's estimated PUDs for the year ended December 31, 2022 (in MBoe):

Proved undeveloped reserves at December 31, 2021	30,366
Conversions	(1,441)
Extensions and discoveries	7,037
Revisions	(7,411)
Proved undeveloped reserves at December 31, 2022	28,551

During the year ended December 31, 2022, we incurred costs of approximately $20.8 million to convert 1,441 MBoe of proved undeveloped reserves to proved developed reserves. Our extensions and discoveries comprised of 7,037 MBoe were primarily due to the result of drilling activity during the year, which allowed for offset PUDs. Additionally, our downward revisions of 7,411 MBoe were primarily attributable to increases in operating costs and capital expenditures, as well as decreases in well-level projections in certain undeveloped areas.

PUDs will be converted from undeveloped to developed with successful development and as the applicable wells begin production. As of December 31, 2022, 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, 2022 are approximately $324.4 million, which we expect to finance through cash flow from operations, borrowings under our revolving credit facility and other sources of capital.

Evaluation and Review of Reserves

Our historical reserve estimates as of December 31, 2022 were prepared based on a report by NSAI, our independent petroleum engineers, which we refer to as the NSAI Report. The technical person primarily responsible for overseeing the preparation of the estimates is our SVP Operations and Engineering. Our SVP Operations and Engineering has been with the Company since 2016 and is the head of the reservoir engineering department. He holds a bachelor's degree in Petroleum Engineering and a Master of Business Administration with an emphasis in Energy from the University of Oklahoma. He is a member of the Society of Petroleum Engineers with over 15 years of experience in the oil and natural gas industry. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI Report is Mr. Michael B. Begland, a Licensed Professional Engineer in the State of Texas (No. 104898). Mr. Begland has been a practicing petroleum engineering consultant at NSAI since 1993 and has over 8 years of prior industry experience. He graduated from Ohio State University in 1983 with a Bachelor of Science Degree in Chemical Engineering. The technical principal 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. NSAI does not own an interest in any of the Company's properties, nor is it employed by us on a contingent basis.

Internal Controls

We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate the Company's reserves. Our internal technical team members meet with our independent reserve engineers periodically during the period covered by the NSAI Report to discuss the assumptions and methods used in the proved reserve estimation process. The qualifications of the technical persons primarily responsible for overseeing the preparation of the estimates of our reserves are set forth in “— Evaluation and Review of Reserves” above. We provided historical information to the independent reserve engineers for the Company's properties, such as ownership interest, oil and natural gas production, well test data, commodity prices, and operating and development costs.

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

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

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

•preparation of reserve estimates by the Company's SVP Operations and Engineering or under his 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, 2022 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, NSAI considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

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

Drilling, Acreage, and Development Activities

Drilling Results

The following table sets forth information with respect to the number of total gross and net oil wells drilled by us during the periods indicated. We do not have any natural gas wells, therefore the information set forth in the table below only pertains to oil wells. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate

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of return. The following table presents our development and exploratory drilling results for the years ended December 31, 2022, September 30, 2021, and September 30, 2020 :

	Year Ended December 31,		Year Ended September 30,
	2022		2021		2020
	Gross	Net(1)	Gross	Net(1)	Gross	Net(1)
Development Wells:
Productive	17	14	18	13	11	3
Dry(2)	—	—	—	—	—	—
Exploratory Wells:
Productive	—	—	2	1	—	—
Dry(2)	—	—	—	—	—	—
Total Wells:
Productive	17	14	20	14	11	3
Dry(2)	—	—	—	—	—	—

_____________________

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

(2)Does not include a wellbore temporarily abandoned due to mechanical failure.

We operated 93% of our horizontal production for the year ended December 31, 2022. 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, 2022:

Developed Acreage(1)		Undeveloped Acreage(2)		Total Acreage
Gross(3)	Net(4)	Gross(3)	Net(4)	Gross(3)	Net(4)
37,984	27,107	6,024	3,363	44,008	30,470

_____________________

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

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

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

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

Approximately 89% of our total net acreage is held by production and 4% is held by obligations. For acreage that is not held by production, unless production is established within the spacing units covering the remaining acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates, the leases will expire in accordance with their respective terms. Substantially all of the leases governing our acreage have continuous development clauses that permit us to continue to hold the acreage under such leases after the expiration of the primary term if we initiate additional development within 120 to 180 days after the completion of the last well drilled on such lease, without the requirement of a lease extension payment. Thereafter, the lease is held with additional development every 120 to 240 days, and generally 180 days, until the entire lease is held by production. None of the Company's horizontal drilling locations associated with proved undeveloped reserves are scheduled for drilling outside of a lease term that is not accounted for with a continuous development schedule or primary term.

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The following table sets forth the net undeveloped acreage, as of December 31, 2022 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
2023	2024	2025
1,847	556	764

Based on our current development plans, we expect to maintain substantially all of the core acreage that would otherwise expire during 2023 either through drilling and establishing production, making lease extension payments, or lease renewal efforts. Approximately 79% of our net undeveloped acreage for 2023 is currently held by continuous drilling and established production. We intend to extend or renew any core lease we plan to develop or are still assessing for development that is set to expire in 2023 and expect to incur $0.6 million to extend or renew those leases, after taking into account the drilling of wells and holding leases by production. Given our currently planned drilling activities, we do not expect the amount of any such lease extension payments to be material. Additionally, our Champions Assets acreage is 100% fee leasehold and New Mexico acreage is approximately 68% fee and state leasehold with the remaining 32% of New Mexico 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.

The Company began initial planning, permitting and drilling operations during 2021 on its EOR Project, which seeks to lower decline rates and ultimately increase recovery of oil by injecting a combination of water and CO2 through vertical wells, applied to horizontal producing wells in Yoakum County, Texas. In October 2021, the Company entered into an agreement for both supply of CO2 product and for the CO2 pipeline connection. In 2022, the Company drilled and completed six injector wells and began CO2 injection after completing the water injection phase. We maintain the optionality to potentially switch to using anthropogenic CO2 with this or subsequent project areas as sources become available at attractive economics.

The Company continues to investigate numerous anthropogenic source possibilities in conjunction with CCUS efforts, including ongoing discussions with several counterparties. At the same time, we are monitoring potential changes to regulations currently being discussed at the national and Texas state levels. We continue to believe that a possible CCUS project, with Riley Permian participating as a developer, has the potential to be an attractive opportunity by itself, as well as a synergistic opportunity with our core upstream business.

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

Production and Operating Data

The following table sets forth information regarding the Company's production, realized prices and production costs for the years ended December 31, 2022, September 30, 2021, and September 30, 2020.

	Year Ended December 31,		Year Ended September 30,
	2022		2021		2020
Production Data:
Oil (MBbls)	3,217		2,340		2,060
Natural gas (MMcf)	3,229		2,602		1,628
Natural gas liquids (MBbls)	444		380		260
Total (MBoe)	4,199		3,154		2,592
Daily combined volumes (Boe/d)	11,505		8,640		7,081
Daily oil volumes (Bbls/d)	8,814		6,411		5,630
Average Prices:
Oil ($ per Bbl)	$	92.86	$	58.29	$	36.35
Natural gas ($ per Mcf)(1)	3.33		2.88		(0.78)
Natural gas liquids ($ per Bbl)(1)	22.22		12.41		(1.90)
Combined ($ per Boe)	$	76.05	$	47.12	$	28.22
Average Prices, including derivative settlements:
Oil ($ per Bbl)	$	71.75	$	51.47	$	49.41
Natural gas ($ per Mcf)(1)	1.06		2.75		(0.78)
Natural gas liquids ($ per Bbl)(1)	22.22		12.41		(1.90)
Combined ($ per Boe)	$	58.13	$	41.95	$	38.61
Average Operating Costs per Boe:
Lease operating expenses	$	7.73	$	6.97	$	7.81
Production and ad valorem taxes	$	4.59	$	2.74	$	1.65

_____________________

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

As a result of our drilling and completion activity, we increased our average net production from 8,640 Boe/d for the year ended September 30, 2021 to an average net production of 11,505 Boe/d for the year ended December 31, 2022. During the year ended December 31, 2022, our production was approximately 77% oil, 13% natural gas and 10% NGLs.

The U.S. and global markets have been disrupted and adversely affected by the COVID-19 pandemic since March 2020 and the full-scale military invasion of Ukraine by Russian troops since February 2022, which has created significant volatility in the financial markets. Commodity prices began to increase in 2021 and have continued to remain high during 2022 due to OPEC+ and other oil and natural gas producers not rapidly increasing production levels, as well as the recovery in demand related to the COVID-19 pandemic, but volatility still remains in commodity prices. Economic sanctions imposed on Russia have further exacerbated supply shortages, leading to further disruptions in the credit and capital markets, including significant uncertainty in commodity prices, during 2022.

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In addition, global markets are experiencing significant inflation attributable to a number of factors. Costs for oilfield equipment and services have been affected by general inflation and we expect those costs for 2023 to continue to be a function of supply and demand.

The Company cannot estimate the length or gravity of the future impact these events will have on the Company's results of operations, financial position, and liquidity.

Productive Wells

As of December 31, 2022, we produced from 170 gross (100 net) total wells, which includes both operated and non-operated wells.

Producing Wells	Gross Wells	Average Working Interest
Operated	96	95	%
Non-Operated	74	12	%

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

Title to Properties

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

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

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 20% to 25%, resulting in a net revenue interest generally ranging from 75% to 80%.

Marketing and Customers

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

We sell our production at market prices and to a relatively small number of purchasers, as is customary in the exploration, development and production business. Our purchaser contracts include marketing provisions with our purchasers to market our production. For the years ended December 31, 2022, September 30, 2021, and September 30, 2020, one purchaser accounted for 89%, 87%, and 86%, respectively, of our revenue purchased, with two end customers each accounting for more than 10% of

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our revenues. During such periods, no other purchaser accounted for 10% or more of our revenues. The loss of this purchaser could materially and adversely affect our revenues in the short-term. However, the end customers include companies with lower credit risk. Further, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of any of our purchasers would not have a long-term material adverse effect on our financial condition and results of operations because oil and natural gas are fungible products with well-established markets.

Transportation

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

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

Competition

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Some of our competitors possess and employ financial resources substantially greater than ours and some competitors employ more technical personnel. These factors can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects, and to evaluate, bid for, and purchase a greater number of properties and prospects than what our financial or technical resources permit. Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to identify, evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

Seasonality of Business

Weather conditions affect the demand for, and prices of, oil, natural gas and NGLs. Demand for oil, natural gas and NGLs is typically higher in the fourth and first calendar quarters resulting in higher prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

Regulation of the Oil and Natural Gas Industry

REPX’s operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which REPX owns or operates producing oil and natural gas properties have statutory provisions regulating the development and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of wells. REPX’s operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. State laws including in Texas govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that REPX can produce from its wells and to limit the number of wells or the locations at which REPX can drill, although REPX can apply for exceptions to

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such regulations or to have reductions in well spacing or density. Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

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

Regulation Affecting Production

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

The failure to comply with the rules and regulations of oil and natural gas production and related operations can result in substantial penalties. REPX’s competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect REPX’s operations.

Regulation of Sales and Transportation of Oil

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

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

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all

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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 to: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (ii) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of natural gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

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

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities are done on a case by case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, and depending on the scope of that decision, REPX’s costs of getting natural gas to point of sale locations may increase. REPX believes that the natural gas pipelines in the gathering systems REPX uses meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of the gathering facilities REPX owns and uses are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Natural gas gathering may receive greater regulatory scrutiny at the state level. State

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regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities.

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

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

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

Regulation of Environmental and Occupational Safety and Health Matters

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

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

Hazardous Substances and Waste Handling

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance”

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

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

Water Discharges

The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near navigable 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 “Corps”). In May 2015, the EPA and the Corps issued a new rule to revise the definition of “Waters of the United States” for all Clean Water Act Programs ("WOTUS"). The 2015 rule made additional waters expressly “Waters of the United States” and, therefore, subject to the jurisdiction of the Clean Water Act, rather than subject to a case-specific evaluation. Legal challenges to this rule followed and the rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015. In response to this decision, the EPA and the Corps resumed nationwide use of the agencies’ prior regulations defining the term “Waters of the United States.” On February 1, 2018, the EPA officially delayed implementation of the 2015 rule until early 2020. The EPA and the Corps also issued a supplemental rulemaking in July 2018 requesting additional comment on the proposed repeal of the 2015 rule’s definition of “Waters of the United States.” However, as the result of an order by the U.S. District Court for the District of South Carolina on August 16, 2018, and subsequent state filings,

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the 2015 rule was in effect in 23 states, including in Texas. On February 14, 2019, the EPA and the Corps issued a proposed rule to revise the definition of “Waters of the United States.” The proposed rule, known as the Navigable Waters Protection Rule, narrowed the definition, excluding, for example, streams that do not flow year-round and wetlands without a direct surface connection to other jurisdictional waters. In September 2019, EPA finalized the repeal of the 2015 WOTUS rule, and the repeal became effective in December 2019. On June 22, 2020, the Navigable Waters Protection Rule became effective. However, on August 30, 2021, the U.S. District Court for the District of Arizona issued an order vacating and remanding the Navigable Waters Protection Rule. In response, the EPA and the Corps issued a joint statement indicating that the agencies are halting implementation of the Navigable Waters Protection Rule, and are reverting back to the pre-2015 definition of "waters of the United States." On November 18, 2021, the EPA and the Department of the Army released a pre-publication version of their proposed rule to reinstate the pre-2015 definition of "waters of the United States," updated to reflect consideration of Supreme Court Decisions. This proposed rule was published in the Federal Register on December 7, 2021. Due to the administrative procedures required to establish the rule and potential litigation, the new definition of “Waters of the United States” may not be implemented, if at all, for several years. To the extent any litigation or future amendments to the rule expand the scope of the Clean Water Act’s jurisdiction, REPX could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas or in connection with stream crossings and preparation and implementation of oil spill prevention, control, and countermeasure plans. 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 in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

Pursuant to CWA laws and regulations, REPX may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water. Spill prevention, control and countermeasure (“SPCC”) requirements imposed under the CWA 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 SPCC plans. REPX has undertaken a review of REPX’s properties to determine the need for new or updated SPCC plans and, where necessary, REPX has developed or upgraded such plans and has implemented the physical and operation controls imposed by these 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 Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses a substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect REPX’s operations.

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’s (“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, have imposed more stringent permitting and operating requirements for produced water disposal wells. In 2014, the RRC published a final rule 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 may deny, modify, suspend or terminate the permit application or existing operating permit for that well. Additionally, legal disputes may arise based on allegations that disposal well operations have caused damage to neighboring properties or otherwise violated state or federal rules regulating waste disposal. These developments could result in additional regulation, restriction on the use of injection wells by REPX or by commercial disposal well vendors whom REPX may use from time to time to dispose of

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wastewater, and increased costs of compliance, which could have a material adverse effect on REPX’s capital expenditures and operating costs, financial condition, and results of operations.

In addition, several cases have recently put a spotlight on the issue of whether injection wells may be regulated under the CWA if a direct hydrological connection to a jurisdictional surface water can be established. The split among federal circuit courts of appeals that decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, one of which was granted in February 2019. The EPA has also brought attention to the reach of the CWA’s jurisdiction in such instances by issuing a request for comment in February 2018 regarding the applicability of the CWA permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered “direct,” and whether such discharges would be better addressed through other federal or state programs. The EPA followed up its Request for Comments with an Interpretative Statement and additional Request for Comment in April 2019 stating that the agency does not believe indirect discharges from a point source through a hydrological groundwater connection to surface water are regulated under the CWA, although the agency indicated that this guidance may be amended pending the Supreme Court’s decision. 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. On January 14, 2021, the EPA issued a guidance on the ruling, which emphasized that discharges to groundwater are not necessarily the “functional equivalent” of a direct discharge based solely on proximity to jurisdictional waters. However, on September 16, 2021, the EPA rescinded its prior guidance. The U.S. Supreme Court’s ruling in County of Maui, Hawaii v. Hawaii Wildlife Fund could result in increased operational costs for REPX if permits are required under the CWA for disposal of REPX’s flowback and produced water in disposal wells.

Air Emissions

The Federal Clean Air Act (“CAA”) and comparable state laws restrict the emission of air pollutants from many sources, such as tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require REPX to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly 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. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit REPX’s ability to obtain such 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”). These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, pneumatic controllers, storage vessels, and well-site components (fugitive emissions). In September 2020, the EPA scaled back these rules by removing the transmission and storage sectors of the oil and natural gas industry from regulation under the New Source Performance Standards (“NSPS”) and rescinding methane-specific standards for the production and processing segments of the industry. However, in June 2021, Congress partially overturned the rollback using the Congressional Review Act, leaving the original regulations largely in place. Furthermore, in November 2021, the EPA issued a proposed rule which would update, strengthen, and expand the 2016 regulations for methane and volatile organic compound ("VOC") emissions from new, modified, and reconstructed sources, and, significantly, also includes emissions guidelines to assist states in the development of plans to regulate methane emissions from certain existing sources. In May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities located in areas where air permitting is implemented by the EPA, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. 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 New Mexico Oil Conservation Commission 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

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a qualified engineer, perform enhanced checks for leaks, and repair them within 15 days of discovery, and maintain records to demonstrate continuous compliance.

Regulation of GHG Emissions

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the federal CAA that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions are also required to meet “best available control technology” standards that are being established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements could adversely affect REPX’s operations and restrict or delay REPX’s ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of REPX’s operations. Furthermore, in May 2016, the EPA finalized the NSPS Subpart OOOOa standards that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rules include 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 methane and other 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. For example, the EPA published two new rules on September 14 and 15, 2020 that remove the transmission and storage sectors of the oil and natural gas industry from regulation under the NSPS and rescind methane-specific standards for the production and processing segments of the industry. However, states and environmental groups brought suit challenging the new rules almost immediately, and in June 2021, Congress partially overturned the rollback. Furthermore, in November 2021 and November 2022, EPA issued proposed rules which would update, strengthen, and expand the NSPS Subpart OOOOa regulations for methane and VOC emissions from new, modified, and reconstructed sources. Notably, the proposed rules also include emissions guidelines to assist states in the development of plans to regulate methane emissions from certain existing sources. Legal challenges to the proposed rules are likely to follow, and thus, the ultimate scope of these regulations remains uncertain. Compliance with these rules requires enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks and increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance. The BLM also finalized similar rules regarding the control of methane emissions in November 2016 that apply to oil and natural gas exploration and development activities on federal and Indian lands. The rules sought to minimize venting and flaring of emissions from storage tanks and other equipment, and also impose leak detection and repair requirements. However, due to subsequent BLM revisions and multiple legal challenges, the rules were never fully implemented, and in October 2020, the November 2016 rules were struck down by the District Court of Wyoming as the result of one such challenge. New Mexico and California have since filed an appeal of the Wyoming Court's decision in the Tenth Circuit. These new and proposed rules could result in increased compliance costs on REPX’s operations.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. REPX regularly uses hydraulic fracturing as part of its operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but federal agencies have asserted jurisdiction over certain aspects of the process. The EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The EPA has also taken the following actions: issued final regulations under the federal CAA establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; although final rules have not yet been issued, proposed a rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; and, in June 2016, published an effluent limitation guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In addition, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands, including requirements for chemical disclosure, wellbore integrity, and handling of flowback water. However, following years of litigation, the BLM rescinded the rule in December 2017. BLM’s repeal of the rule was challenged in court, and in April 2020, the Northern District of California issued

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a ruling in favor of the BLM. This ruling is now being appealed; thus, the future of the rule remains uncertain. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect REPX’s operations.

Certain governmental reviews have recently been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level. More recently, the EPA initiated a study of Oil and Gas Extraction Wastewater Management in 2018 that the agency characterizes as a “holistic look” at how produced water is regulated and managed by the EPA, states, and tribes, and has sought input on these issues from other stakeholders such as academics, non-governmental organizations, and industry. A primary focus of the study is to evaluate whether federal regulations allowing for more discharge options would be beneficial, for example, in addressing areas with concerns over scarcity of water and/or injection options. The EPA released a draft of the study in May 2019 and sought public input until July 1, 2019. The EPA’s final report was issued in May 2020, which found mixed support from stakeholders regarding additional produced water discharge options. The EPA is still determining what, if any, next steps are appropriate regarding produced water management in light of the report. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA, CWA or other regulatory mechanisms.

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. 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 had a material adverse effect on REPX’s operations or financial position, but if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where REPX operates, REPX could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.

Protected Species

The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or that species’ habitat. REPX may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service 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 Interior under the Trump administration has determined that such “incidental takes” of migratory birds do not violate the Act, this position was overruled by a federal district court in New York in August 2020. Nevertheless, on January 7, 2021, the Department of the Interior issued a rule which excluded incidental takes from the definition of prohibited activities under the Act. This rule was short-lived, however, and in October 2021, the Department of the Interior issued a rule to reverse the agency's position on incidental takes. The reversal took effect on December 3, 2021. The identification or designation of previously unprotected species as threatened

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or endangered in areas where underlying property operations are conducted could cause REPX to incur increased costs arising from species protection measures or could result in limitations on REPX’s development activities that could have an adverse impact on REPX’s ability to develop and produce reserves. If REPX were to have a portion of its leases designated as critical or suitable habitat, it could adversely impact the value of REPX’s leases.

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

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

Related Permits and Authorizations

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

Related Insurance

REPX maintains insurance against some risks associated with above or underground contamination that may occur as a result of REPX’s exploration and production activities. However, this insurance is limited to activities 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. Further, REPX has no coverage for gradual, long-term pollution events.

Facilities

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

Human Capital

As of December 31, 2022, we employed 65 people. We operate in a technical industry and depend on a highly skilled workforce in multiple disciplines including engineering, geology, operations, land, information technology, accounting and various other corporate functions.The Company supports its employees in pursuing training opportunities to enhance their professional skills. We are not a party to any collective bargaining agreements with our employees. We understand that employee recruiting, retention and development plays a critical role to our business activities and our ability to achieve our long-term strategy. We believe our relations with our employees to be satisfactory. From time to time we utilize the services of independent contractors to perform various field and other services.

Compensation and Benefits Program

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

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Diversity and Inclusion

We believe that diversity of backgrounds, experience and perspectives contributes to an innovative workforce and an enriching environment for our employees. We are committed to fostering an inclusive, respectful environment and providing equal opportunity to all qualified persons in our hiring, development, and compensation practices.

Community Involvement

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

Health, Safety and Environment

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

Available Information

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. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and/or 10-QT, current reports on Form 8-K and all amendments to those reports are available free of charge on our website, www.rileypermian.com, as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.

Item 1A. Risk Factors

The Company is subject to various risks and uncertainties in the ordinary course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. Other risks are described in Item 1 and 2. Business and Properties, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures About Market Risk. We could also face additional risks and uncertainties not currently known to us or that we currently deem to be immaterial. If any of these risks actually occurs, it could materially harm our business, financial condition or results of operations and the trading price of our shares could decline. Investors should carefully consider each of the following risk factors and all of the other information set forth in this Form 10-K.

Risks Related to our Business, Operations, and Strategy

Recent regulatory restrictions on use of produced water and a moratorium on new produced water disposal wells in the Permian Basin to stem rising seismic activity and earthquakes could increase our operating costs and adversely impact our business, results of operations and financial condition.

In September 2021, the RRC curtailed the amount of produced water companies were permitted to inject into some wells near Midland and Odessa in the Permian Basin, and has since indefinitely suspended some permits there and expanded the restrictions to other areas. These actions were taken in an effort to control induced seismic activity and recent increases in earthquakes in the Permian Basin, which have been linked by the U.S. and local seismologists to wastewater disposal in oil fields. These restrictions on the disposal of produced water and a moratorium on new produced water disposal wells could result in increased operating costs, requiring us or our service providers to truck produced water, recycle it or dispose of it by other means, all of which could be costly. We or our service providers may also need to limit disposal well volumes, disposal rates and pressures or locations, or require us or our service providers to shut down or curtail the injection of produced water into disposal wells. These factors may make drilling activity in the affected parts of the Permian Basin less economical and adversely impact our business, results of operations and financial condition.

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Enhanced scrutiny on ESG matters could have an adverse effect on the Company’s operations.

Enhanced scrutiny on ESG matters related to, among other things, concerns raised by advocacy groups about climate change, hydraulic fracturing, natural gas flaring, GHG emissions, waste disposal, oil spills, and explosions of natural gas transmission pipelines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines, and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens, increased risk of litigation, and adverse impacts on the Company’s access to capital. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance, and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits the Company requires to conduct its operations to be withheld, delayed, or burdened by requirements that restrict the Company’s ability to profitably conduct its business.

We may be unable to quickly adapt to changes in market/investor priorities.

Historically, one of the key drivers in the unconventional resource industry has been growth in production and reserves. With historical volatility in oil and natural gas prices and the likelihood that rising interest rates will increase the cost of borrowing, capital efficiency and free cash flow from earnings have become the key drivers for energy companies, particularly shale producers. Such shifts in focus sometimes require changes in planning and resource management, which may not occur instantaneously. Any delay in responding to such changes in market sentiment or perception may result in the investment community having a negative sentiment regarding our business plan, potential profitability and our ability to operate in a manner deemed "efficient," which may have a negative impact on the price of our common stock.

Oil, natural gas, and NGL prices are volatile. An extended decline in commodity prices may adversely affect our business, financial condition, or results of operations and our ability to meet our capital expenditure obligations and financial commitments. Additionally, the value of our reserves calculated using SEC pricing may be higher than the fair market value of our reserves calculated using current market prices.

The prices we receive for our oil, natural gas, and NGL production heavily influence our revenue, profitability, access to capital, and future rate of growth. Oil, natural gas, and NGLs are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. For example, during the period from January 1, 2016 to December 31, 2022, NYMEX West Texas Intermediate (referred to as WTI) oil prices ranged from a high of $123.64 per Bbl on March 8, 2022 to a low of $(36.98) per Bbl on April 20, 2020. During 2022, WTI prices ranged from a high of $123.64 to a low of $71.05 per Bbl. Average daily prices for NYMEX Henry Hub gas ranged from a high of $9.85 per MMBtu to a low of $3.46 per MMBtu during 2022. If the prices of oil and natural gas continue to be volatile, reverse their recent increases, or decline, our operations, financial condition, cash flows and level of expenditures may be materially and adversely affected. Moreover, the duration and magnitude of any decline in oil, natural gas or NGL prices cannot be predicted with accuracy, and this market will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

•worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas, and NGLs;

•the price and quantity of foreign imports, including foreign oil;

•the actions by members of OPEC+;

•political, economic, and military conditions in or affecting other producing countries, including embargoes or conflicts in the Middle East, Africa, South America and Russia;

•the level of global oil and natural gas exploration and production activity;

•the level of global oil and natural gas inventories;

•prevailing prices on local price indices in the areas in which we operate;

•the cost of producing and delivering oil and natural gas and conducting other operations;

•the recovery rates of new oil, natural gas and NGL reserves;

•lead times associated with acquiring equipment and products, and availability of qualified personnel;

•late deliveries of supplies;

•technical difficulties or failures;

•the proximity, capacity, cost, and availability of gathering and transportation facilities;

•localized and global supply and demand fundamentals and transportation availability;

•localized and global weather conditions;

•public health concerns such as pandemic diseases;

•technological advances affecting energy consumption, including advances in exploration, development and production technologies;

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•shareholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil, natural gas, and NGLs;

•uncertainty in capital and commodities markets and the ability of companies in our industry to raise equity capital and debt financing;

•the price and availability of alternative fuels; and

•domestic, local, and foreign governmental regulation and taxes.

Lower commodity prices will reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in the present value of our reserves and our ability to develop future reserves. Lower commodity prices may also reduce the amount of oil, natural gas and NGLs that we can produce economically. We have historically been able to hedge our oil and natural gas production at prices that are significantly higher than current strip prices. However, in the current commodity price environment, our ability to enter into comparable derivative arrangements may be limited, and, in the future, we will not be under an obligation to hedge a specific portion of our oil or natural gas production.

Using lower prices in estimating proved reserves would likely result in a reduction in proved reserve volumes due to economic limits. While it is difficult to project future economic conditions and whether such conditions will result in impairment of proved property costs, we consider several variables including specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors. In addition, sustained periods with oil and natural gas prices at levels lower than current West Texas Intermediate strip prices and the resultant effect such prices may have on our drilling economics and our ability to raise capital may require us to re-evaluate and postpone or eliminate our development drilling, which could result in the reduction of some of our proved undeveloped reserves and related standardized measure. If we are required to curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity, or ability to finance planned capital expenditures.

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write down constitutes a non-cash charge to earnings. If market or other economic conditions deteriorate or if oil, natural gas and NGL prices decline, we may incur impairment charges, which may have a material adverse effect on our results of operations.

Our exploration and development projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the exploitation, development, and acquisition of oil and natural gas reserves. We expect to fund our growth primarily through cash flow from operations, availability under our revolving credit facility, and subsequent equity or debt offerings when appropriate. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

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Our cash flow from operations and access to capital are subject to a number of variables, including: 

•our proved reserves;

•the level of hydrocarbons we are able to produce from existing wells and the timing of such production;

•the prices at which our production is sold;

•operating costs and other expenses;

•the availability of takeaway capacity;

•credit facility and/or investor requirements;

•our ability to acquire, locate and produce new reserves; and

•our ability to borrow under our revolving credit facility.

If our revenue or the borrowing base under our revolving credit facility decreases as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves, or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and would adversely affect our business, financial condition, and results of operations.

Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

We have acquired unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our results of operations over time. However, we cannot provide assurance that all prospects will be economically viable or that we will not abandon our undeveloped acreage. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such unproved property or wells.

Properties that we decide to drill may not yield oil, natural gas or NGLs in commercially viable quantities.

Our prospects are in various stages of evaluation, ranging from prospects that are currently being drilled, to prospects that will require substantial additional seismic data processing and interpretation. Properties that we decide to drill that do not yield oil, natural gas or NGLs in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

•unexpected drilling conditions;

•title problems;

•pressure or lost circulation in formations;

•equipment failure or accidents;

•adverse weather conditions;

•compliance with environmental and other governmental or contractual requirements; and

•increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire, or obtain protection from sellers against such liabilities.

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs, and potential liabilities, including environmental liabilities. Such

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assessments are inexact and inherently uncertain. For these reasons, the properties we have acquired or will acquire in the future may not produce as projected or may be more costly to operate than projected. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.

In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds.

Actual future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may revise reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.

The present value of future net revenues from our reserves should not be assumed to represent the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. For example, our estimated proved reserves as of December 31, 2022 were calculated under SEC rules using the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months of $94.14 per Bbl for oil and NGL volumes and $6.36 per MMBtu for natural gas volumes. Using lower prices in estimating proved reserves would likely result in a reduction in proved reserve volumes due to economic limits.

There is a limited amount of production data from horizontal wells completed in the Permian Basin and its San Andres Formation. As a result, reserve estimates associated with horizontal wells in this area are subject to greater uncertainty than estimates associated with reserves attributable to vertical wells in the same area.

Reserve engineers rely in part on the production history of nearby wells in establishing reserve estimates for a particular well or field. Horizontal drilling in the San Andres Formation of the Permian Basin is a relatively recent development, whereas vertical drilling has been utilized by producers in this area for over 50 years. As a result, the amount of production data from horizontal wells available to reserve engineers is relatively small compared to that of production data from vertical wells. Until a greater number of horizontal wells have been completed in the San Andres Formation, and a longer production history from these wells has been established, there may be a greater variance in our proved reserves on a year-over-year basis due to the transition from vertical to horizontal reserves in both the proved developed and proved undeveloped categories. Such variance could be material and any such variance could have a material and adverse impact on our cash flows and results of operations.

Part of our strategy involves drilling using the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. As of December 31, 2022, we have drilled and completed 170 gross operated horizontal wells on our West Texas and New Mexico acreage, and therefore are subject to increased risks associated with horizontal drilling as compared to companies that have greater experience in horizontal drilling activities. Risks that we face while drilling include, but are not limited to, failing to land our wellbore in the desired drilling zone, not staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length of the wellbore and not being able to run tools and other equipment

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consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages, not being able to run tools the entire length of the wellbore during completion operations and not successfully cleaning out the wellbore after completion of the final fracture stimulation stage.

Additionally, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficient time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or commodity prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.

Approximately 11% of our net leasehold acreage is undeveloped and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.

Oil and natural gas leases generally must be drilled before the end of the lease term or the leaseholder will lose the lease and any capital invested therein. In addition, leases may also be lost due to legal issues relating to the ownership of leases. Any delays in drilling or legal issues causing us to lose leases on properties could have a material adverse effect on our results of operations and reserve growth.

As of December 31, 2022, approximately 11% 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. Unless production is established on the undeveloped acreage covered by our leases, such leases will expire. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

Our drilling plans are subject to change based upon various factors, including factors that are beyond our control. Such factors include drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals. If our leases expire, we will lose our right to develop such properties.

Substantially all of our producing properties are located in the Northwest Shelf within the Permian Basin of West Texas, making us vulnerable to risks associated with operating in one major geographic area. Specifically, as the Permian Basin is an area of high industry activity, we may be unable to hire, train, or retain qualified personnel needed to manage and operate our assets.

Substantially all of our producing properties are geographically concentrated in the Northwest Shelf sub-basin within the Permian Basin of West Texas, an area in which industry activity has increased rapidly. At December 31, 2022, the majority of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, a number of our properties could experience any of the same conditions at the same time and, when compared to other companies that have a more diversified portfolio of properties, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages or other drought or extreme weather related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.

Specifically, demand for qualified personnel in this area, and the cost to attract and retain such personnel, may increase substantially in the future. Moreover, our competitors, including those operating in multiple basins, may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could have a negative effect on production volumes or significantly increase costs, which could have a material adverse effect on our results of operations, liquidity and financial condition.

In addition, the geographic concentration of our assets including our total estimated proved reserves as of December 31, 2022, exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.

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Our drilling and production programs may not be able to obtain access on commercially reasonable terms or otherwise to truck transportation, pipelines, gas gathering, transmission, storage and processing facilities to market our oil and natural gas production, certain of which we do not control, and our initiatives to expand our access to midstream and operational infrastructure may be unsuccessful.

The marketing of oil and natural gas production depends in large part on the capacity and availability of pipelines and storage facilities, trucks, gas gathering systems and other transportation, processing and refining facilities. Access to such facilities is, in many respects, beyond our control. If these facilities are unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. We rely (and expect to rely in the future) on facilities developed and owned by third parties in order to store, process, transmit, and sell our oil and natural gas production. Our plans to develop and sell our oil and natural gas reserves, the expected results of our drilling program and our cash flow and results of operations could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise. The amount of oil and natural gas that can be produced is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, damage to the gathering, transportation, refining or processing facilities, or lack of capacity on such facilities. For example, increases in activity in the Permian Basin could contribute to bottlenecks in processing and transportation that may negatively affect our results of operations, and these adverse effects could be disproportionately severe to us compared to our more geographically diverse competitors.

Similarly, the concentration of our assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules, which could adversely affect development activities or production relating to those formations. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Permian Basin, we are subject to increasing competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages or delays. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we may be provided only limited, if any, notice as to when these circumstances will arise and their duration.

While we have undertaken initiatives to expand our access to midstream and operational infrastructure, these initiatives may be delayed or unsuccessful. As a result, our business, financial condition, and results of operations could be adversely affected.

The prices we receive for our production may be affected by local and regional factors.

The prices we receive for our production will be determined to a significant extent by factors affecting the local and regional supply of and demand for oil and natural gas, including the adequacy of the pipeline and processing infrastructure in the region to process and transport our production and that of other producers. Those factors result in basis differentials between the published indices generally used to establish the price received for regional oil and natural gas production and the actual price we receive for our production, which may be lower than index prices. If the price differentials pursuant to which our production is subject were to widen due to oversupply or other factors, our revenue could be negatively impacted.

An increase in the differential between NYMEX WTI and the reference or regional index price used to price our oil and natural gas would reduce our cash flows from operations.

Our oil and natural gas is priced in the local markets where it is produced based on local or regional supply and demand factors. The prices we receive for our oil and natural gas are typically lower than the relevant benchmark prices, such as NYMEX WTI. The difference between the benchmark price and the price we receive is called a differential. Numerous factors may influence local pricing, such as pipeline capacity and processing infrastructure. Additionally, insufficient pipeline or transportation capacity, lack of demand in any given operating area or other factors may cause the differential to increase in a particular area compared with other producing areas. For example, production increases from competing Permian Basin producers, combined with limited pipeline and transportation capacity in the area, have gradually widened differentials in the Permian Basin.

For the year ended December 31, 2022, our realized oil differential to NYMEX WTI averaged $(2.05) per Bbl of oil and our realized natural gas differential to NYMEX Henry Hub averaged $(3.12) per Mcf of gas. Given that a significant amount of our production is from the Permian Basin, if the negative price differential in the Permian Basin increases, we expect that the effect of our price differential on our revenues will also increase. Increases in the differential between the benchmark prices for

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oil and natural gas, such as the NYMEX WTI and NYMEX Henry Hub, and the realized price we receive could significantly reduce our revenues and our cash flow from operations.

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

At December 31, 2022, approximately 37% of our total estimated proved reserves were classified as proved undeveloped. Our approximate 28,551 MBoe of estimated proved undeveloped reserves are estimated to require $324.4 million of development capital. Our development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. We expect to fund our growth primarily through cash flow from operations, availability under our revolving credit facility, and subsequent equity or debt offerings when appropriate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.

We participate in oil and natural gas leases with third parties who may not be able to fulfill their commitments to our projects.

We own less than 100% of the working interest in the oil and natural gas leases on which we conduct operations, and other parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, may be unable to access debt or equity financing, and, in some cases, may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position.

We own non-operating interests in properties developed and operated by third parties and, as a result, we are unable to control the operation and profitability of such properties.

We participate in the drilling and completion of wells with third-party operators that exercise exclusive control over such operations. As a participant, we rely on the third-party operators to successfully operate these properties pursuant to joint operating agreements and other similar contractual arrangements.

As a participant in these operations, we may not be able to maximize the value associated with these properties in the manner we believe appropriate, or at all. For example, we cannot control the success of drilling and development activities on properties operated by third parties, which depend on a number of factors under the control of a third-party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology. In addition, the third-party operator’s operational expertise and financial resources and its ability to gain the approval of other participants in drilling wells will impact the timing and potential success of drilling and development activities in a manner that we are unable to control. A third-party operator’s failure to adequately perform operations, breach of the applicable agreements or failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our financial condition and results of operations.

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploitation, development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent

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on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil, natural gas and NGLs we produce.

The availability of a ready market for any oil, natural gas and NGLs we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.

We have exposure to credit risk through receivables from purchasers of our oil, natural gas and NGL production. One purchaser accounted for 89% of our revenues for the year ended December 31, 2022. This concentration of purchasers may impact our overall credit risk in that this purchaser may be similarly affected by changes in economic conditions or commodity price fluctuations. We do not require our customers to post collateral. The inability or failure of our significant purchaser to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial condition and results of operations.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

Our operations are subject to inherent risks, some of which are beyond our control. We are not insured against all risks. Losses and liabilities arising from uninsured and under insured events could materially and adversely affect our business, financial condition or results of operations.

Our exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering or other cratering, uncontrollable flows of natural gas, oil, well fluids and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses, reservoir damage and environmental hazards such as oil, produced water or chemical spills, natural gas leaks, ruptures or discharges of toxic gases.

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for: 

•injury or loss of life;

•employee/employer liabilities and risks, including wrongful termination, discrimination, labor organizing, retaliation claims, and general human resource related matters;

•damage to and destruction of property, natural resources and equipment;

•pollution and other environmental hazards or damage;

•abnormally pressured formations, fires or explosions or natural disasters;

•mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;

•regulatory investigations and penalties;

•landowner claims for property damage and restoration costs;

•suspension of our operations; and repair and remediation costs;

•repair and remediation costs.

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. Claims for loss of oil and natural gas production and damage to formations can occur in our industry. Litigation arising from a catastrophic occurrence at a location where our systems are deployed may result in our being named as a defendant in lawsuits asserting large claims.

Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Also, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not covered

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or fully covered by insurance and any delay in the payment of insurance proceeds for covered events could have a material adverse effect on our business, financial condition and results of operations.

We may be unable to make accretive acquisitions or successfully integrate acquired businesses or assets, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of oil and natural gas properties or businesses that complement or expand our current business. The successful acquisition of oil and natural gas properties requires an assessment of several factors, including:

•recoverable reserves;

•future oil, natural gas and NGL prices and their applicable differentials;

•estimates of operating costs;

•estimates future development costs;

•estimates of the costs and timing of plugging and abandonment; and

•environmental and other liabilities.

The accuracy of these assessments is inherently uncertain, and we may not be able to identify accretive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Reviews may not always be performed on every well, and environmental problems, such as subsurface or groundwater contamination, are not necessarily observable even when a review is performed. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Even if we do identify accretive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, our revolving credit facility imposes certain limitations on our ability to enter into mergers or combination transactions as well as limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of lease brokers or land men who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we do typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

Our operations could be impacted by burdens and encumbrances on title to our properties.

Our leasehold and other acreage may be subject to existing oil and natural gas leases, liens for current taxes and other burdens, including other mineral encumbrances and restrictions customary in the oil and natural gas industry. Such liens and burdens could materially interfere with the use or otherwise affect the value of such properties. Additionally, any cloud on the title of the working interests, leases and other rights owned by us could have a material adverse effect on our operations.

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Our undeveloped acreage must be drilled before lease expirations to hold the acreage by production or by other operations. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire. As of December 31, 2022, 61% of our net undeveloped acreage is set to expire through 2023, before taking into account the expected drilling of wells and holding leases by production, while 12% of our net undeveloped acreage is set to expire through 2023, after taking into account the expected drilling of wells and holding leases by production. We intend to extend or renew any core lease we plan to develop or are still assessing for development that is set to expire in 2023 and expect to incur $0.6 million to extend or renew those leases, after taking into account the expected drilling of wells and holding leases by production. Where we do not have the option to extend a lease, however, we may not be successful in negotiating extensions or renewals. Our ability to drill and develop our core acreage and establish production to maintain our leases depends on a number of uncertainties, including oil, natural gas and NGL prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. These risks are greater at times and in areas where the pace of our exploration and development activity slows.

We plan to use CO2 for our EOR projects. Our production from these EOR operations may decline if we are not able to obtain sufficient amounts of CO2.

Oil production from our EOR projects depends on, among other factors, having access to sufficient amounts of CO2 from our third party suppliers of CO2. Our ability to produce oil from our EOR projects would be hindered if the supply of CO2 was limited due to, among other things, physical limitations on CO2 supply or the ability to economically procure CO2 at costs low enough to ensure the economic viability of our EOR projects. This could have a material adverse effect on our financial condition, results of operations or cash flows. Future oil production from the Company’s EOR projects is dependent on the timing, volumes and location of CO2 injections and, in particular, our ability to obtain sufficient volumes of CO2. Market conditions may cause the delay or cancellation of the development of naturally occurring CO2 sources or construction of plants that produce anthropogenic CO2 as a byproduct that can be purchased, thus limiting the amount of CO2 available for use in our EOR projects.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

Our acquisition strategy will subject us to certain risks associated with the inherent uncertainty in evaluating properties for which we have limited information.

We intend to continue to expand our operations in part through acquisitions. Our decision to acquire properties will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, our reviews of acquired properties are inherently incomplete because it generally is not economically feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections are often not performed on properties being acquired, and environmental matters, such as subsurface contamination, are not necessarily observable even when an inspection is undertaken.

Any acquisition involves other potential risks, including, among other things:

•the validity of our assumptions about reserves, future production, revenues and costs;

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•a decrease in our liquidity by using a significant portion of our cash from operations or borrowing capacity to finance acquisitions;

•a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

•the ultimate value of any contingent consideration agreed to be paid in an acquisition;

•dilution to stockholders if we use equity as consideration for, or to finance, acquisitions;

•the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

•an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and

•an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes, or other litigation encountered in connection with an acquisition.

Our future results will suffer if we do not effectively manage our expanded operations.

As a result of our recent acquisitions, the size and geographic footprint of our business has increased. Our future success will depend, in part, upon our ability to manage this expanded business, which may pose substantial challenges for management, including challenges related to the management and monitoring of new operations and basins and associated increased costs and complexity. We may also face increased scrutiny from governmental authorities as a result of the increase in the size of our business. There can be no assurances that we will be successful or that we will realize the expected benefits currently anticipated from our recent and future acquisitions.

Acquisitions of assets or businesses may reduce, rather than increase, our distributable cash flow or may disrupt our business.

Even if we make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in our cash flow. Any acquisition involves potential risks that may disrupt our business, including the following, among other things:

•mistaken assumptions about volumes or the timing of those volumes, revenues or costs, including synergies;

•an inability to successfully integrate the acquired assets or businesses;

•the assumption of unknown liabilities;

•exposure to potential lawsuits;

•limitations on rights to indemnity from the seller;

•the diversion of management’s and employees’ attention from other business concerns;

•unforeseen difficulties operating in new geographic areas; and

•customer or key employee losses at the acquired businesses.

We may need to access funding through capital market transactions. Due to our small public float, low market capitalization, limited operating history, ESG, and climate change restrictions, it may be difficult and expensive for us to raise additional funds.

We may need to raise funds through the issuance of shares of our common stock or securities linked to our common stock. Our ability to raise these funds may be dependent on a number of factors, including the risk factors further described herein and the low trading volume and volatile trading price of our shares of common stock. The stocks of small cap companies tend to be highly volatile. We expect that the price of our common stock will be highly volatile for the next several years.

As a result, we may be unable to access funding through sales of our common stock or other equity-linked securities. Even if we were able to access funding, the cost of capital may be substantial due to our low market cap and small public float. The terms of any funding we are able to obtain may not be favorable to us and may be highly dilutive to our stockholders. We may be unable to access capital due to unfavorable market conditions or other market factors outside of our control such as ESG and/or climate change restrictions. There can be no assurance that we will be able to raise additional capital when needed. The failure to obtain additional capital when needed would have a material adverse effect on our business.

Our revolving credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to declare dividends.

The operating and financial restrictions and covenants in our revolving credit facility restrict, and any future financing agreements likely will restrict, our ability to finance future operations or capital needs, engage, expand or pursue our business

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activities or pay dividends. Our revolving credit facility restricts, and any future financing agreements likely will restrict, its ability to, among other things:

•incur indebtedness;

•issue certain equity securities, including preferred equity securities;

•incur certain liens or permit them to exist;

•engage in certain fundamental changes, including mergers or consolidations;

•make certain investments, loans, advances, guarantees and acquisitions;

•sell or transfer assets;

•enter into sale and leaseback transactions;

•redeem or repurchase shares from our stockholders;

•pay dividends to our stockholders unless the net leverage ratio, after giving effect to pro forma adjustments, does not exceed 2.0 to 1.0, the total revolving credit exposures under our revolving credit facility are not greater than 80% of the total revolving commitments, and no default or event of default then exists or would exist upon the payment of the dividend;

•make certain payments of junior indebtedness;

•enter into certain types of transactions with our affiliates;

•enter into certain restrictive agreements; and

•enter into swap agreements and hedging arrangements.

Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of free cash flow and events or circumstances beyond our control, such as a downturn in our business or the economy in general or reduced oil, natural gas and NGL prices. A failure to comply with the provisions of our revolving credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. Further, our ability to pay dividends to our stockholders will be restricted and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments, and our common stock holders could experience a partial or total loss of their investment. In addition, our obligations under our revolving credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our revolving credit facility, the lenders can seek to foreclose on our assets.

Our indebtedness could reduce our financial flexibility.

The level of our indebtedness could affect our operations in several ways, including the following: 

•a significant portion of our cash flow could be used to service the indebtedness;

•a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

•the covenants contained in our revolving credit facility limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments; and

•a high level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes, or other purposes.

Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine in accordance with the terms of the agreement. The borrowing base depends on, among other things, projected revenues from, and asset values of, the proved oil and natural gas properties securing our loan. The value of our proved reserves is dependent upon, among other things, the prevailing and expected market prices of the underlying commodities in our estimated reserves. A further reduction or sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations, and our ability to meet our capital expenditure obligations and financial commitments. Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. We could be forced to repay a portion of our bank borrowings or transfer to the lenders additional collateral due to redeterminations of our borrowing base that result in a reduction of the available revolving commitments. If we are forced to do so, we may not have sufficient funds to make such repayments or provide such collateral. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings, provide additional collateral or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

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In the future, we may not be able to access adequate funding under our revolving credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a redetermination and reduction of the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the reduced borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our debt arrangements, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital, or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of our existing revolving credit facility or future debt arrangements may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our revolving credit facility currently restricts our ability to dispose of assets and our use of the proceeds from such dispositions. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

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

We enter or may enter into commodity derivative contracts for a portion of our production, primarily consisting of swaps, put options and call options. We purchase such derivatives to achieve more predictable cash flows, to reduce our exposure to adverse fluctuations in the prices of oil, natural gas, and NGLs, and in order to remain in compliance with covenants in our revolving credit facility. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

Derivative instruments also can expose us to the risk of financial loss in some circumstances, including when:

•production is less than the volume covered by the derivative instruments;

•the counterparty to the derivative instrument defaults on its contractual obligations;

•there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

•there are issues with regard to legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil, natural gas, and NGL prices and interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil, natural gas, and NGLs, which could also have an adverse effect on our financial condition.

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Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the contract and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

During periods of declining commodity prices, our derivative contract receivable positions could generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.

Risks Related to the Oil and Natural Gas Industry

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our exploitation, development, and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production.

Our decisions to purchase, explore, develop, or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing, and operating wells is often uncertain before drilling commences.

Further, many factors may curtail, delay, or cancel our scheduled drilling projects, including the following:

•delays and increased costs imposed by or resulting from compliance with environmental and other regulatory requirements including limitations on or resulting from wastewater discharge and disposal, subsurface injections, greenhouse gas emissions, and hydraulic fracturing;

•pressure or irregularities in geological formations;

•increases in the cost of, or shortages or delays in availability of drilling rigs and qualified personnel for hydraulic fracturing activities;

•shortages of or delays in obtaining water resources, suitable proppant, and chemicals in sufficient quantities for use in hydraulic fracturing activities;

•equipment failures or accidents;

•lack of available gathering facilities or delays in construction of gathering facilities;

•lack of available capacity on interconnecting transmission pipelines;

•adverse weather conditions, such as tornadoes, droughts, ice storms, and extreme freeze events;

•lack of available treatment or disposal options for oil and natural gas waste, including produced water;

•environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

•issues related to permitting under and compliance with environmental and other governmental regulations;

•declines or volatility in oil, natural gas, and NGL prices;

•limited availability of financing at acceptable terms;

•title problems or legal disputes regarding leasehold rights; and

•limitations in the market for oil, natural gas, and NGLs.

Conservation measures and technological advances could reduce demand for oil, natural gas and NGLs.

Our industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. Fuel and other energy conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil, natural gas and NGLs, technological advances in fuel economy and energy generation devices could reduce demand for oil, natural gas and NGLs. As competitors and others use or develop new technologies or technologies comparable to ours in the future, we may lose market share or be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources than we do, which may allow them to gain technological

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advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or services at all, on a timely basis or at an acceptable cost. Limits on our ability to effectively use, implement or adapt to new technologies may have a material adverse effect on our business, financial condition and results of operations. Similarly, the impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Limitation or restrictions on our ability to obtain water may have an adverse effect on our operating results.

Water is an essential component of shale and conventional oil and natural gas development during both the drilling and hydraulic fracturing processes. Our access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, private, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. In addition, treatment and disposal of flowback and produced water is becoming more highly regulated and restricted. Thus, our costs for obtaining and disposing of water could increase significantly. Our inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact our exploration and production operations and have a corresponding adverse effect on our business, results of operations and financial condition.

The unavailability or high cost of equipment, supplies, personnel and oilfield services used to drill and complete wells could adversely affect our ability to execute our development plans within our budget and on a timely basis.

The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Our operations are concentrated in areas in which activity has increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, has increased, as have the costs for those items. In addition, to the extent our suppliers source their products or raw materials from foreign markets, the cost of such equipment could be impacted if the United States imposes tariffs on imported goods from countries where these goods are produced. Such shortages or cost increases 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.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties and market oil or natural gas.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, and raising additional capital, which could have a material adverse effect on our business.

Declining general economic, business or industry conditions have, and will continue to have, a material adverse effect on our results of operations, liquidity and financial condition, and are expected to continue having a material adverse effect for the forseeable future.

Concerns over global economic conditions, the threat of pandemic diseases and the results thereof, energy costs, geopolitical issues, inflation, the availability and cost of credit have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil and natural gas, declining business and consumer confidence, and increased unemployment, have precipitated an economic slowdown and a recession, which could expand to a global depression. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices and are expected to continue having a material adverse effect for the foreseeable future. If the economic climate in the United States or abroad continues to deteriorate, demand for petroleum products could diminish, which could further impact the price at which our operators can sell oil, natural gas, and NGLs, affect the ability of our vendors, suppliers and customers to continue operations, and ultimately adversely impact our results of operations, liquidity and financial condition to a greater extent than it has already. In addition, a decline in consumer confidence or changing patterns in the availability and use of disposable income by consumers can negatively affect the demand for oil and natural gas as a result of our results of operations.

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Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise.

Inflation has been an ongoing concern in the U.S. since 2021. Ongoing inflationary pressures have resulted in and may result in additional increases to the costs of goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation caused the U.S. Federal Reserve and other central banks to increase interest rates multiple times in 2022 in an effort to curb inflationary pressure on the costs of goods and services, which could have the effects of raising the cost of capital and depressing economic growth, either of which (or the combination thereof) could hurt the financial and operating results of our business. We may experience further cost increases for our operations to the extent that elevated inflation remains.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

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

Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, oil spills, seismic activity, greenhouse gas emissions, and explosions of natural gas transmission lines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.

Risks Related to Acts of God and Cyber Security

Power outages, limited availability of electrical resources, and increased energy costs could have a material adverse effect on us.

Our operations are subject to electrical power outages, regional competition for available power, and increased energy costs. Power outages, which may last beyond our backup and alternative power arrangements, would harm our operations and our business.

We also may be subject to risks and unanticipated costs associated with obtaining power from various utility companies. Such utilities may be dependent on, and sensitive to price increases for, a particular type of fuel, such as coal, oil or natural gas. The price of these fuels and the electricity generated from them could increase as a result of proposed legislative measures related to climate change or efforts to regulate carbon or other greenhouse gas emissions.

Extreme weather conditions could adversely affect our ability to conduct drilling activities in the areas where we operate.

Our exploration, exploitation and development activities and equipment could be adversely affected by extreme weather conditions, such as floods, lightening, drought, ice and other storms, prolonged freeze events, and tornadoes, which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment. Such extreme weather conditions could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of, and our access to, necessary third-party services, such as electrical power, water, gathering, processing, compression and transportation services. These constraints and the resulting shortages or

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high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

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

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations. For example, the industry depends on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. As an oil and natural gas producer, our technologies, systems, networks, and those of our business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, misuse, loss or destruction of proprietary and other information, or other disruption of business operations that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. We face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability.

Loss of our information and computer systems could adversely affect our business.

We are dependent on our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

A Terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Risks Related to Legal, Regulatory, and Tax Matters

We are subject to stringent federal, state and local laws and regulations related to environmental and occupational health and safety issues that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Our operations are subject to stringent federal, state and local laws and regulations governing occupational safety and health aspects of our operations, the discharge of materials into the environment and environmental and human health protection. These laws and regulations may impose numerous obligations applicable to our operations including (i) the acquisition of a permit before conducting drilling, production, and other regulated activities; (ii) the restriction of types, quantities and concentration of materials that may be released into the environment; (iii) the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, protected species habitat, and other protected areas; (iv) the

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application of specific health and safety criteria addressing worker protection; (v) the imposition of substantial liabilities for pollution resulting from our operations; (vi) the installation of costly emission monitoring and/or pollution control equipment; and (vii) the reporting of the types and quantities of various substances that are generated, stored, processed, or released in connection with our properties. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or EPA, the U.S. Fish and Wildlife Service, and analogous state agencies, and state oil and natural gas commissions, such as the Railroad Commission of Texas, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations or specific projects and limit our growth and revenue.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons and other hazardous substances and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices at our leased and owned properties, as well as locations where waste from our operations is transported offsite for disposal. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be subject to strict, joint and several liability for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. We may not be able to recover some or any of these costs from insurance. Changes in environmental laws and regulations occur frequently and tend to become more stringent over time, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities, air emissions control or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition. For example, on October 1, 2015, the EPA issued a final rule under the CAA, lowering the NAAQS, for ground-level ozone from the current standard of 75 parts per billion, or ppb, for the current 8-hour primary and secondary ozone standards to 70 ppb for both standards. Subsequently, the EPA designated over 200 counties across the U.S. as “nonattainment” for these standards, meaning that new and modified stationary emissions sources in these areas are subject to more stringent permitting and pollution control requirements. On December 23, 2021, the EPA announced its decision to retain, without changes, the 2015 NAAQs. If our operations become subject to these more stringent standards, compliance with these and other environmental regulations could delay or prohibit our ability to obtain permits for operations or require us to install additional pollution control equipment, the costs of which could be significant.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.

Exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation include: 

•permits for drilling operations;

•drilling bonds;

•reports concerning operations;

•the spacing of wells;

•the rates of production;

•the plugging and abandoning of wells;

•unitization and pooling of properties; and

•taxation.

Under these laws, we could be liable for property damage and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations.

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

We are responsible for compliance with all applicable laws and regulations regarding the decommissioning, plugging, abandonment, and reclamation of our facilities at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with certainty since they will be a function of regulatory requirements at the time of decommissioning, plugging, abandonment, and reclamation. We may, in the future, determine it prudent or be required by applicable laws or regulations to establish and fund one or more decommissioning, plugging, abandonment, and reclamation reserve funds to provide for payment of future decommissioning, plugging, abandonment, and reclamation costs, which could decrease funds available to service debt obligations. In addition, such reserves, if established, may not be sufficient to satisfy such future decommissioning, plugging, abandonment, and reclamation costs and we will be responsible for the payment of the balance of such costs.

SEC rules could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves, or PUDs, may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write down our PUDs if we do not drill or plan on delaying those wells within the required five-year timeframe.

Should we fail to comply with all applicable regulatory agency administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation. FERC may also impose administrative and criminal remedies and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and regulations pertaining to those and other matters may be considered or adopted by FERC from time to time. Additionally, the Federal Trade Commission (the “FTC”) has regulations intended to prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civil penalties of up to $1.0 million per day, and the CFTC, prohibits market manipulation in the markets regulated by the CFTC, including similar anti-manipulation authority with respect to oil swaps and futures contracts as that granted to the CFTC with respect to oil purchases and sales. The CFTC rules subject violators to a civil penalty of up to the greater of $1.0 million or triple the monetary gain to the person for each violation. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Business—Regulation of the Oil and Gas Industry.”

A change in the jurisdictional characterization of our natural gas assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our natural gas assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC. We believe that our natural gas gathering pipelines meet the traditional test that FERC has used to determine whether a pipeline is a gathering pipeline and is, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and gathering services not subject to the jurisdiction of FERC, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by FERC, the courts or Congress. If FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the NGPA.

Such regulation could decrease revenue and increase operating costs. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by FERC.

FERC regulation may indirectly impact gathering services not directly subject to FERC regulation. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on interstate open access

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transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets. In recent years, FERC has pursued procompetitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the natural gas gathering services.

Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, our natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Our gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities.

We may be involved in legal proceedings that could result in substantial liabilities.

We may, from time to time, be a claimant or defendant to various legal proceedings, disputes and claims arising in the course of our business, including those that arise from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of our current operations. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process.

For example, in February 2014, the EPA asserted regulatory authority pursuant to the SDWA UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. Also, beginning in 2012, the EPA issued a series of regulations under the federal CAA that include NSPS, known as Subpart OOOO, for completions of hydraulically fractured natural gas wells and certain other plants and equipment and, in May 2016, published a final rule establishing new emissions standards, known as Subpart OOOOa, for methane and volatile organic compounds (“VOCs”) from certain new, modified and reconstructed equipment and processes in the oil and natural gas source category. The NSPS Subpart OOOO and OOOOa rules have since been subject to numerous legal challenges as well as EPA reconsideration proceedings and subsequent amendment proposals. Most recently, on September 14 and 15, 2020, EPA published two new rules in the Federal Register that remove the transmission and storage sectors of the oil and natural gas industry from regulation under the NSPS and rescind methane-specific standards for the production and processing segments of the industry. However, states and environmental groups brought suit challenging the new rules almost immediately, and in June 2021, Congress partially overturned the rollback. Furthermore, in November 2021 and November 2022, EPA issued proposed rules which would update, strengthen, and expand the NSPS Subpart OOOOa regulations for methane and VOC emissions from new, modified, and reconstructed sources. Notably, the proposed rules also include emissions guidelines to assist states in the development of plans to regulate methane emissions from certain existing sources. Legal challenges to the proposed rules are likely to follow, and accordingly, legal uncertainty exists with respect to the future scope and extent of implementation of the methane rule; however, even as currently implemented, these rules apply to our operations, including requirements for the installation of equipment to control VOC emissions from certain hydraulic fracturing of wells and fugitive emissions from well site and other production equipment, and additional regulation, which could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact or delay oil and natural gas production activities, which could have a material adverse effect on our business.

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The BLM published a final rule in March 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands. However, following years of litigation, the BLM rescinded the rule in December 2017. The BLM and the Secretary of the U.S. Department of the Interior are now being sued for the decision to rescind the rule. In April 2020, the Northern District of California issued a ruling in favor of the BLM and the Department of the Interior. This ruling is now being appealed; thus, the future of the rule remains uncertain. Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances.

From time to time, legislation has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process but, to date, such legislation has not been adopted. At the state level, Texas, where we conduct our operations, is among the states that has adopted regulations that impose new or more stringent permitting, including the requirement for hydraulic-fracturing operators to complete and submit a list of chemicals used during the fracking process. We may incur significant additional costs to comply with such existing state requirements and, in the event additional state level restrictions relating to the hydraulic-fracturing process are adopted in areas where we operate, we may become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.

Moreover, we typically dispose of flowback and produced water or certain other oilfield fluids gathered from oil and natural gas producing operations in underground disposal wells. This disposal process has been linked to increased induced seismicity events in certain areas of the country, particularly in Oklahoma, Texas, Colorado, Kansas, New Mexico and Arkansas. These and other states have begun to consider or adopt laws and regulations that may restrict or otherwise prohibit oilfield fluid disposal in certain areas or underground disposal wells, and state agencies implementing these requirements may issue orders directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations or impose standards related to disposal well construction and monitoring. For example, in 2014, the RRC published a final rule 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 TRRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. Any one or more of these developments may result in our having to limit disposal well volumes, disposal rates or locations, or to cease disposal well activities, which could have a material adverse effect on our business, financial condition, and results of operations.

In addition, several cases have recently put a spotlight on the issue of whether injection wells may be regulated under the Federal Water Pollution Control Act (the “Clean Water Act” or “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 a statement issued by EPA in April 2019, the agency concluded that the CWA should not be interpreted to require permits for discharges of pollutants that reach surface waters via groundwater. However, 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. On January 14, 2021, EPA issued guidance on the ruling, which emphasized that discharges to groundwater are not necessarily the “functional equivalent” of a direct discharge based solely on proximity to jurisdictional waters. However, on September 16, 2021, EPA rescinded its prior guidance. The U.S. Supreme Court’s ruling in County of Maui, Hawaii v. Hawaii Wildlife Fund could result in increased operational costs if permits are required under the CWA for disposal of our flowback and produced water in underground disposal wells.

Increased regulation and attention given to the hydraulic fracturing process and associated processes could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells and an associated increase in compliance costs and time, which could have a material adverse effect on our liquidity, results of operations, and financial condition.

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Climate change legislation and regulations restricting or regulating emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil, natural gas and NGLs that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional, and state levels of government to monitor and limit emissions of GHGs. While no comprehensive climate change legislation has been implemented at the federal level, the EPA and states or groupings of states have pursued legal initiatives in recent years that seek to reduce GHG emissions through efforts that include consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In particular, the EPA has adopted rules under authority of the CAA that, among other things, establish certain permit reviews for GHG emissions from certain large stationary sources, which reviews could require securing permits at covered facilities emitting GHGs and meeting defined technological standards for those GHG emissions. The EPA has also adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore production.

Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published a final rule establishing NSPS Subpart OOOOa, which requires certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and VOC emissions. Although much of the initial rules remain intact and effective, the rules have been subject to legal challenges, reconsideration by EPA, stays, and proposed amendments. For example, on September 14 and 15, 2020, EPA published two new final rules in the Federal Register that remove the transmission and storage sectors of the oil and natural gas industry from regulation under the NSPS and rescind methane-specific standards for the production and processing segments of the industry. However, states and environmental groups brought suit challenging the new rules almost immediately, and in June 2021, Congress partially overturned the rollback. Furthermore, in November 2021 and November 2022, the EPA issued proposed rules which would update, strengthen, and expand the NSPS Subpart OOOOa regulations for methane and VOC emissions from new, modified, and reconstructed sources. Notably, the proposed rules also include emissions guidelines to assist states in the development of plans to regulate methane emissions from certain existing sources. The BLM also finalized rules regarding the control of methane emissions in November 2016 that applied to oil and natural gas exploration and development activities on public and tribal 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. New Mexico and California have since filed an appeal of the Wyoming Court's decision in the Tenth Circuit. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions. Nevertheless, President Biden has set ambitious targets for GHG reduction, including to achieve at least a 50 percent reduction from 2005 levels in economy-wide net GHG pollution by 2030.

The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

In addition, spurred by increasing concerns regarding climate change, the oil and natural gas industry faces growing demand for corporate transparency and a demonstrated commitment to sustainability goals. ESG goals and programs, which typically include extralegal targets related to environmental stewardship, social responsibility, and corporate governance, have become an increasing focus of investors and shareholders across the industry. While reporting on ESG metrics remains voluntary, access to capital and investors is likely to favor companies with robust ESG programs in place.

Finally, increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such climatic events were to occur, they could have an adverse effect on our financial condition and results of operations and the financial condition and operations of our customers.

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Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling, and place us at a competitive disadvantage. Potential disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

Restrictions on drilling or other operational activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate.

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened or endangered species and their habitats could prohibit drilling in certain areas or require the implementation of expensive mitigation or conservation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have a material adverse impact on our ability to develop and produce our reserves.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and of entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. In December 2016, the CFTC re-proposed regulations implementing limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The Dodd-Frank Act and CFTC rules also will require us, in connection with certain derivatives activities, to comply with clearing and trade-execution requirements (or to take steps to qualify for an exemption to such requirements). In addition, the CFTC and certain banking regulators have adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception to the mandatory clearing, trade-execution and margin requirements for swaps entered to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, if any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flow. It is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us or the timing of such effects. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and CFTC rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil, natural gas and NGL prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and NGLs. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and CFTC rules is to lower commodity prices. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations.

Future federal, state or local legislation also may impose new or increased taxes or fees on oil and natural gas extraction or production.

Future changes in U.S. federal income tax laws, or the introduction of a carbon tax, as well as any similar changes in state law, could eliminate or postpone certain tax deductions that currently are available with respect to oil and natural gas development, or increase costs, and any such changes could have an adverse effect on our financial position, results of operations, and cash flows. Additionally, future legislation could be enacted that increases the taxes or fees imposed on oil and

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natural gas extraction or production. Any such legislation could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil, natural gas or NGLs.

Anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us.

We typically enter into agreements with our customers governing the use and operation of our systems, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Louisiana, New Mexico, Texas and Wyoming have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, prospects and results of operations.

Our effective tax rate may change in the future, which could adversely impact us.

The TCJA significantly changed the U.S. federal income taxation of U.S. corporations, including by reducing the U.S. corporate income tax rate, limiting interest deductions and certain deductions for executive compensation, permitting immediate expensing of certain capital expenditures, and revising the rules governing net operating losses. The TCJA remains unclear in some respects and continues to be subject to potential amendments and technical corrections. The United States Treasury Department and the IRS have issued significant guidance since the TCJA was enacted, interpreting the TCJA and clarifying some of the uncertainties, and are continuing to issue new guidance. There are still significant aspects of the TCJA for which further guidance is expected, and both the timing and contents of any such future guidance are uncertain.

Further, changes to the U.S. federal income tax laws are proposed regularly and there can be no assurance that, if enacted, any such changes would not have an adverse impact on us. For example, President Biden has suggested the reversal or modification of some portions of the TCJA and certain of these proposals, if enacted, could increase our effective tax rate. There can be no assurance that any such proposed changes will be introduced as legislation or, if introduced, later enacted, and, if enacted, what form such enacted legislation would take. Such changes could potentially have retroactive effect.

In light of these factors, there can be no assurance that our effective income tax rate will not change in future periods. If the effective tax rate were to increase as a result of the future legislation, our business could be adversely affected.

Risks Related to Our Common Stock

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

The stock markets have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. The market price of our common stock may also fluctuate significantly in response to the following factors, some of which are beyond our control:

•our operating and financial performance and drilling locations, including reserve estimates;

•actual or anticipated fluctuations in our quarterly results of operations, and financial indicators, such as net income, cash flow and revenues;

•our failure to meet revenue, reserves or earnings estimates by research analysts or other investors;

•sales of our common stock by the Company or other stockholders, or the perception that such sales may occur;

•the public reaction to our press releases, other public announcements, and filings with the SEC;

•strategic actions by our competitors or competition for, among other things, capital, acquisition of reserves, undeveloped land and skilled personnel;

•publication of research reports about us or the oil and natural gas exploration and production industry generally;

•changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

•speculation in the press or investment community;

•the failure of research analysts to cover our common stock;

•increases in market interest rates or funding rates, which may increase our cost of capital;

•changes in market valuations of similar companies;

•changes in accounting principles, policies, guidance, interpretations or standards;

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•additions or departures of key management personnel;

•actions by our stockholders;

•commencement or involvement in litigation;

•general market conditions, including fluctuations in commodity prices;

•political conditions in oil and natural gas producing regions;

•domestic and international economic, legal and regulatory factors unrelated to our performance; and

•the realization of any risks described under this “Risk Factors” section.

Moreover, the stock markets in general have experienced substantial volatility that has often been unrelated to the operating performance of individual companies. These broad market fluctuations may also adversely affect the trading price of our common stock.

In the past, following periods of volatility in the market price of a company’s securities, stockholders have often instituted class action securities litigation against those companies. Such litigation, if instituted, could result in substantial costs and diversion of management attention and resources, which could significantly harm our business, financial condition, results of operations and reputation.

Future sales or the possibility of future sales of a substantial amount of our common stock may depress the price of shares of our common stock.

Future sales or the availability for sale of substantial amounts of our common stock in the public market could adversely affect the prevailing market price of our common stock and could impair our ability to raise capital through future sales of equity securities.

We may issue shares of our common stock or other securities from time to time as consideration for future acquisitions and investments. If any such acquisition or investment is significant, the number of shares of our common stock, or the number or aggregate principal amount, as the case may be, of other securities that we may issue may in turn be substantial. We may also grant registration rights covering those shares of our common stock or other securities in connection with any such acquisitions and investments.

We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares of our common stock issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices for our common stock.

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

Our common stock is listed for quotation on the NYSE American and we are required to meet specified financial requirements, including requirements for a minimum amount of capital, a minimum price per share, a minimum public float, and continued business operations so that we are not delisted or characterized as a “public shell company.” If we are unable to comply with the NYSE American stock exchange’s listing standards, NYSE may determine to delist our common stock from the NYSE American stock exchange or other of NYSE’s trading markets. If our common stock is delisted for any reason, it could reduce the value of our common stock and liquidity.

If securities analysts do not publish research or reports about our business or if they publish negative evaluations of our stock, the price of our stock could decline.

The trading market for our common stock relies, in part, on the research and reports that industry or financial analysts publish about us or our business. Equity research analysts may elect not to provide research coverage of our common stock, and such lack of research coverage may adversely affect the market price of our common stock. In the event we do have equity research analyst coverage, we will not have any control over the analysts or the content and opinions included in their reports. The price of our common stock could decline if one or more equity research analysts downgrade our stock or issue other unfavorable commentary or research. If one or more equity research analysts ceases coverage of us or fails to publish reports on us regularly, demand for our common stock could decrease, which in turn could cause our stock price or trading volume to decline.

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We may not generate sufficient cash to support any dividend to our common stockholders.

The amount of any dividend will depend on the amount of cash we generate from operations, which will fluctuate from quarter to quarter based on, among other things:

•the volumes of crude oil, natural gas and NGLs that we produce;

•market prices of crude oil, natural gas and NGLs and their effect on our drilling and development plan;

•the levels of our operating expenses, maintenance expenses and general and administrative expenses;

•regulatory action affecting:

•the supply of, or demand for, crude oil, natural gas and NGLs;

•our operating costs or our operating flexibility;

•prevailing economic conditions; and

•adverse weather conditions.

In addition, the actual amount of cash we will have available for dividends will depend on other factors, some of which are beyond our control, including:

•our debt service requirements and other liabilities;

•our ability to borrow under our debt agreements to fund our capital expenditures and operating expenditures and to pay dividends;

•fluctuations in our working capital needs;

•restrictions on dividends contained in any of our debt agreements;

•the cost of acquisitions, if any; and

•other business risks affecting our cash levels.

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

Investors who are looking for an investment that will pay regular and predictable quarterly dividends should not invest in our common stock. Our business performance may be more volatile, and our cash flow may be less stable, than other business models that pay dividends. The amount of our quarterly dividends will generally depend on the performance of our business, which has a limited operating history.

The Board may modify or revoke our dividend policy at any time at its discretion.

We are not required to pay any dividends on our common stock at all. Accordingly, the Board may change our dividend policy at any time at its discretion and could elect not to pay dividends on our common stock for one or more quarters. Any modification or revocation of our cash dividend policy could substantially reduce or eliminate the amounts of dividends to our common stockholders. The amount of dividends we make, if any, and the decision to make any dividend at all will be determined by our Board, whose interests may differ from those of our common stockholders.

The amount of cash we have available for dividends to our common stockholders 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.

The amount of cash we have available for dividends depends primarily upon our cash flow and not solely on our profitability, which will be affected by non-cash items. As a result, we may pay cash dividends during periods when we record a net loss for financial accounting purposes and, conversely, we might fail to pay cash dividends on our common stock during periods when we record net income for financial accounting purposes.

Delaware law imposes restrictions on our ability to pay cash dividends on our common stock.

Our common stockholders do not have a right to dividends on such shares unless declared or set aside for payment by our Board. Under Delaware law, cash dividends on capital stock may only be paid from “surplus” or, if there is no “surplus,” from the corporation’s net profits for the then-current or the preceding fiscal year. Unless we operate profitably, our ability to pay dividends on our common stock would require the availability of adequate “surplus,” which is defined as the excess, if any, of net assets (total assets less total liabilities) over capital. Our business may not generate sufficient surplus or net profits from operations to enable us to pay dividends on our common stock.

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We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our shareholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our Board may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

Risks Related to the Company

If we fail to maintain an effective system of internal control over financial reporting, we may not be able to accurately report our financial results or prevent fraud. As a result, stockholders could lose confidence in our financial and other public reporting, which would harm our business and the trading price of our common stock.

Effective internal control over financial reporting is necessary for us to provide reliable financial reports and, together with adequate disclosure controls and procedures, is designed to prevent fraud. Any failure to implement required new or improved controls, or difficulties encountered in their implementation, could cause us to fail to meet our reporting obligations. In addition, any testing, as and when required, conducted in connection with Section 404 of the Sarbanes-Oxley Act, or Section 404, or any subsequent testing by our independent registered public accounting firm, as and when required, may reveal deficiencies in our internal control over financial reporting that are deemed to be significant deficiencies or material weaknesses or that may require prospective or retroactive changes to our financial statements or identify other areas for further attention or improvement. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock.

We are a smaller reporting company and we cannot be certain if the reduced disclosure requirements applicable to smaller reporting companies will make our common stock less attractive to investors.

We are currently a “smaller reporting company” as defined by Rule 12b-2 of the Exchange Act. As a “smaller reporting company,” we are subject to reduced disclosure obligations in our SEC filings compared to other issuers, including, among other things, an exemption from the requirement to present five years of selected financial data, being required to provide only two years of audited financial statements in annual reports and being subject to simplified executive compensation disclosures. Until such time as we cease to be a “smaller reporting company,” such reduced disclosure in our SEC filings may make it harder for investors to analyze our operating results and financial prospects. If some investors find our common stock less attractive as a result of any choices to reduce disclosure we may make, there may be a less active trading market for our common stock and our stock price may be more volatile.

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

We depend to a large extent on the services of our officers, including Bobby Riley, our Chief Executive Officer, Kevin Riley, our President, Philip Riley, our Chief Financial Officer, Corey Riley, our Executive Vice President – Business Intelligence, Michael Palmer, our Executive Vice President Corporate – Land. These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties and developing and executing financing strategies. The loss of any of these individuals could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any management personnel. Our success will be dependent on our ability to continue to retain and utilize skilled technical personnel. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition, and results of operations.

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.

As of December 31, 2022, our executive officers, directors and principal stockholders, in the aggregate, own 77.3% of the fully diluted common stock of the Company. As a result, if these stockholders were to choose to act together, they would be able to control or significantly influence all matters submitted to the Company’s stockholders for approval, as well as the Company’s management and affairs. For example, these persons, if they choose to act together, would control or significantly influence the election of directors and approval of any merger, consolidation or sale of all or substantially all of the Company’s

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assets. This concentration of voting power could delay or prevent an acquisition of the Company on terms that other stockholders may desire.

Provisions in our corporate charter documents and under Delaware law could make an acquisition of the Company, which may be beneficial to our stockholders, more difficult and may prevent attempts by our stockholders to replace or remove current management.

Provisions in our corporate charter and by-laws may discourage, delay or prevent a merger, acquisition or other changes in control that stockholders may consider favorable, including transactions in which stockholders might otherwise receive a premium for their shares. These provisions also could limit the price that investors might be willing to pay in the future for shares of our common stock, thereby depressing the market price of our common stock. In addition, because our Board is responsible for appointing the members of the management team, these provisions may frustrate or prevent any attempts by our stockholders to replace or remove current management by making it more difficult for stockholders to replace members of our board of directors. Among other things, these provisions:

•allow the authorized number of directors to be changed only by resolution of the Board;

•after a certain date, limit the manner in which stockholders can remove directors from the Board;

•establish advance notice requirements for stockholder proposals that can be acted on at stockholder meetings and nominations to the Board;

•after a certain date, require that stockholder actions must be effected at a duly called stockholder meeting and prohibit actions by written consent;

•limit who may call stockholder meetings;

•authorize the Board to issue preferred stock without stockholder approval, which could be used to institute a shareholder rights plan, or so-called “poison pill,” that would work to dilute the stock ownership of a potential hostile acquirer, effectively preventing acquisitions that have not been approved by the Board; and

•after a certain date, require the approval of the holders of at least 66 2/3% of the votes that all the stockholders would be entitled to cast to amend or repeal certain provisions of our charter or bylaws.

Our bylaws provide that the Court of Chancery of the State of Delaware will be the exclusive forum for substantially all disputes between the Company and its stockholders, which could limit stockholders’ ability to obtain a favorable judicial forum for disputes with the Company or its directors, officers, employees or stockholders.

Our bylaws provide that, unless the Company consents in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware is the exclusive forum for any derivative action or proceeding brought on the Company’s behalf, any action asserting a breach of fiduciary duty owed by Company’s directors, officers, other employees or stockholders to the Company or its stockholders, any action asserting a claim against the Company arising pursuant to the Delaware General Corporation Law or as to which the Delaware General Corporation Law confers jurisdiction on the Court of Chancery of the State of Delaware, or any action asserting a claim arising pursuant to the Company’s certificate of incorporation or bylaws or governed by the internal affairs doctrine.

Our bylaws provide that, unless the Company consents in writing to the selection of an alternative forum, the federal district courts of the United States of America shall, to the fullest extent permitted by law, be the sole and exclusive forum for any actions arising under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended.

These provisions may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with the Company or its directors, officers, employees or stockholders, which may discourage such lawsuits against the Company and its directors, officers, employees or stockholders. Alternatively, if a court were to find these provisions in our bylaws to be inapplicable or unenforceable in an action, the Company may incur additional costs associated with resolving such action in other jurisdictions, which could adversely affect our business and financial condition.

Conflicts of interest could arise in the future between us, on the one hand, and certain of our stockholders and their respective affiliates, including their funds and their respective portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities.

Investment funds managed by certain of our stockholders are in the business of making investments in entities in the U.S. energy industry. As a result, certain of our stockholders may, from time to time, acquire interests in businesses that directly or indirectly compete with our business, as well as businesses that are significant existing or potential customers. Certain of our stockholders and their respective portfolio companies may acquire or seek to acquire assets that we seek to acquire and, as a

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result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue. Under our certificate of incorporation, certain of our stockholders and/or one or more of their respective affiliates are permitted to engage in business activities or invest in or acquire businesses which may compete with our business or do business with any client of ours. Any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on the trading price of our common stock.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

We may, from time to time, be a claimant or defendant to various legal proceedings, disputes and claims arising in the course of our business, including those that arise from interpretation of federal and state laws and regulations affecting the oil and natural gas industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of our current operations. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on us, cannot be predicted with certainty, we believe that none of these matters, if ultimately decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

The Company was named as a defendant in an adversary proceeding (the "Adversary Proceeding") commenced on October 25, 2021 in the United States Bankruptcy Court for the Northern District of Texas, Dallas Division (the "Bankruptcy Court"), by the Trustee of the Chapter 7 bankruptcy of the Hoactzin Partners, L.P. ("Hoactzin"). The complaint in the Adversary Proceeding alleges that in October of 2018, one year prior to the Hoactzin bankruptcy filing in October of 2019, Peter Salas ("Salas"), Chairman of the Board of Tengasco during the period of the purported fraudulent transfers, caused Hoactzin to transfer its working interests in certain wells on its Kansas acreage (the “Kansas Working Interests”) to the Company for an amount the complaint alleges was purportedly less than the reasonable equivalent value of such Kansas Working Interests. The complaint includes avoidance actions and other causes of action in connection with the transfer of the Kansas Working Interests, as well as other causes of action alleged related to certain transactions to which the Company was not a party.

On October 13, 2022, the Company entered into a Compromise Settlement Agreement and Mutual General Release (the “Settlement Agreement”) with the Trustee for the bankruptcy estate for Hoactzin to resolve certain claims against the Company in the Adversary Proceeding. Under the terms of the Settlement Agreement, the Company agreed to pay $80 thousand to the Trustee in full settlement and satisfaction of (a) all claims, causes of action, and damages that have been asserted against the Company or could be asserted against the Company in the Adversary Proceeding; and (b) all claims which might arise from or relate to any actions taken by the Company while acting in connection with Debtor.

In November 2022, the Bankruptcy Court approved the Settlement Agreement, and the Company made the settlement payment to the Trustee in accordance with the Settlement Agreement. Subsequently, the Bankruptcy Court entered an Order Granting the Joint Motion to Dismiss resulting in the dismissal of the Adversary Proceeding with prejudice (the "Dismissal Order"), as contemplated by the Settlement Agreement.

Neither the Settlement Agreement nor the Dismissal Order has any effect on the Trustee’s claims against any of the other defendants in the Adversary Proceeding, including without limitation, those claims against Peter Salas, our former Chief Executive Officer.

For additional information regarding contingencies, see Note 14 - Commitments and Contingencies included in notes to the consolidated financial statements included elsewhere in this Annual Report.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

Shares of our Common Stock are listed on the NYSE American under the symbol "REPX". There were approximately 121 holders of record of our Common Stock as of March 1, 2023.

Dividends

The Company declared quarterly dividends totaling approximately $25.3 million, $6.2 million, and $10.6 million, respectively, for the year ended December 31, 2022, three months ended December 31, 2021, and year ended September 30, 2021. The cash dividends were declared for all issued and outstanding common shares including unvested restricted stock issued under the Company's 2021 Long-Term Incentive Plan adopted on February 26, 2021.

The Company declared quarterly dividends totaling approximately $7.6 million for the year ended September 30, 2021. The cash dividends were declared for all issued and outstanding common units including unvested units issued under the Company's 2018 Long-Term Incentive Plan.

The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our Board. Our Board's determination of any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the Board deems relevant at the time of such determination. The Company's revolving credit facility can limit the dividends the Company is able to pay unless the Company meets certain covenants in accordance with its credit agreement.

Outstanding Equity Awards

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights	Weighted Average Exercise Price of Outstanding Options, Warrants and Rights	Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (excluding securities in Column (a))
	(a)	(b)	(c)
Equity Compensation Plans Approved by Security Holders	—	—	440,784
Equity Compensation Plans Not Approved by Security Holders	—	—	—
Total	—	—	440,784

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Unregistered Sales of Equity Securities

None.

Issuer Repurchases of Equity Securities

Our common stock repurchase activity for the year ended December 31, 2022 was as follows:

Quarter Ending	Total Number of Shares Purchased(1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plan or Programs	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plan or Programs
Q1	12,640	$	26.81	—	—
Q2	8,576	$	25.08	—	—
Q3	341	$	25.02	—	—
Q4	23,181	$	18.98	—	—

_____________________

(1)These amounts reflect the shares received by us from employees for the payment of personal income tax withholding on vesting transactions. The acquisition of the surrendered shares was not part of a publicly announced program to repurchase shares of our Common Stock. Any shares repurchased by the Company for personal tax withholdings are immediately retired upon repurchase.

Item 6. Selected Financial Data

[Reserved]

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of the Company’s financial condition and results of operations should be read in conjunction with the Company’s consolidated financial statements and related notes thereto presented in this Annual Report. The following discussion contains “forward-looking statements” that reflect the Company’s future plans, estimates, beliefs and expected performance. The Company’s actual results could differ materially from those discussed in these forward-looking statements. See "Cautionary Statement Regarding Forward-Looking Statements" and "Part I. Item 1A. Risk Factors."

Overview

We operate in the upstream segment of the oil and natural gas industry and are focused on steadily growing conventional reserves, production and cash flow through the acquisition, exploration, development and production of oil, natural gas and NGLs primarily in the Permian Basin in West Texas. The Company’s activities are primarily focused on the San Andres Formation, a shelf margin deposit on the Northwest Shelf of the Permian Basin. We intend to continue to develop our reserves and increase production through development drilling and exploration activities and through acquisitions that meet our strategic and financial objectives.

Financial and Operating Highlights

Financial and operating results reflect the following:

•Increased total net equivalent production by 33% to 11.5 MBoe/d for the year ended December 31, 2022, as compared to the year ended September 30, 2021

•During the year ended December 31, 2022, 15 gross (11.8 net) horizontal wells brought online to production

•Realized average combined price on production sold of $76.05 per Boe, before derivative settlements, during the year ended December 31, 2022, including $92.86 per barrel for oil

•Generated cash flow from operations of $170.3 million for the year ended December 31, 2022

•Incurred total accrual (activity based) capital expenditures before acquisitions of $123.1 million for the year ended December 31, 2022 as compared to $71.3 million for the year ended September 30, 2021

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•Paid cash dividends on common shares of $25.1 million during the year ended December 31, 2022, and announced latest dividend of $0.34 per share with a record date of January 25, 2023, which was paid on February 8, 2023, for a total of $6.7 million

•Exited the year with $13.3 million in cash and $56.0 million drawn on our revolving credit facility

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Recent Developments

Fiscal Year Change

On August 16, 2022, the Company's Board acting by written consent resolved to amend and restate the Company's Second Amended and Restated Bylaws to change the Company's fiscal year period from October 1st through September 30th each year to January 1st through December 31st each year commencing with the 2022 calendar year. On August 19, 2022, the holders of approximately 75% of our outstanding Common Stock acting by written consent approved Bylaws Restatement and adopted the Third Amended and Restated Bylaws. In accordance with Rule 14c-2 under the Exchange Act, the aforementioned actions taken by written consent became effective on September 23, 2022. As a result, the Company's 2022 fiscal year was the period from January 1, 2022 to December 31, 2022.

Market Conditions, Commodity Prices and Interest Rates

U.S. and global markets are experiencing heightened volatility following impactful geopolitical events, consistent evidence of widespread inflation, as well as increased fears of an economic recession. However, commodity prices have continued to remain high during 2022 due to OPEC+ and other oil and natural gas producers not rapidly increasing production levels, as well as from the recovery in demand related to the COVID-19 pandemic. The full-scale military invasion of Ukraine by Russian troops has continued unabated since February 2022 coupled with related economic sanctions imposed on Russia further exacerbating supply shortages, leading to disruptions in the credit and capital markets, including significant uncertainty in commodity prices, during 2022.

In addition, global markets are experiencing significant inflation attributable to a number of factors. Certain of our capital expenditures and expenses are affected by general inflation and we expect costs for 2023 to continue to be a function of supply and demand. Specifically, costs for oilfield equipment and services continue to experience impacts from significant inflation, which we expect to continue for the foreseeable future.

In response to inflation concerns, the U.S. Federal Reserve initiated a monetary tightening policy in 2022, increasing interest rates in June, July, September and November 2022 with public estimates of potential further increases in the future. The Company's floating-rate credit facility is impacted by such rate increases.

The combination of geopolitical events, inflation and the rising rate environment has led to increasing forecasts of a U.S. or global recession. Any such recession could prolong market volatility or cause a decline in commodity prices, among other potential impacts.

The Company cannot estimate the length or gravity of the future impact these events will have on the Company's results of operations, financial position, liquidity and the value of oil and natural gas reserves.

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Results of Operations

Comparison for the years ended December 31, 2022 and September 30, 2021.

The following table sets forth selected operating data for the years ended December 31, 2022 and September 30, 2021:

	Year Ended
	December 31, 2022		September 30, 2021
Revenues (in thousands):
Oil sales	$	298,723	$	136,421
Natural gas sales	10,755		7,500
Natural gas liquids sales	9,865		4,715
Oil and natural gas sales, net	$	319,343	$	148,636
Production Data, net:
Oil (MBbls)	3,217		2,340
Natural gas (MMcf)	3,229		2,602
Natural gas liquids (MBbls)	444		380
Total (MBoe)	4,199		3,154
Daily combined volumes (Boe/d)	11,505		8,640
Daily oil volumes (Bbls/d)	8,814		6,411
Average Realized Prices:
Oil ($ per Bbl)	$	92.86	$	58.29
Natural gas ($ per Mcf)	3.33		2.88
Natural gas liquids ($ per Bbl)	22.22		12.41
Combined ($ per Boe)	$	76.05	$	47.12
Average Realized Prices, including derivative settlements:(1)
Oil ($ per Bbl)	$	71.75	$	51.47
Natural gas ($ per Mcf)	1.06		2.75
Natural gas liquids ($ per Bbl)	22.22		12.41
Combined ($ per Boe)	$	58.13	$	41.95

_____________________

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

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Oil and Natural Gas Revenues

Our revenues are derived from the sale of our oil and natural gas production, including the sale of NGLs that are extracted from our natural gas during processing. Revenues from product sales are a function of the volumes produced, product quality, market prices, and gas Btu content. Our revenues from oil, natural gas and NGL sales do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. The Company’s total oil and natural gas revenue, net increased $170.7 million, or 115%, for the year ended December 31, 2022 compared to the year ended September 30, 2021. The Company’s realized average combined price on its production for the year ended December 31, 2022 increased by $28.93 per Boe, or 61% compared to the year ended September 30, 2021.

Oil revenues

•For the year ended December 31, 2022, oil revenues increased by $162.3 million, or 119%, compared to the year ended September 30, 2021. Of the increase, $111.2 million was attributable to an increase in our realized price and $51.1 million was attributable to an increase in volume. Volumes increased by 37%, while realized prices increased by 59% compared to the year ended September 30, 2021.

•Oil volumes increased during the year ended December 31, 2022 due to production from new wells and workovers performed on existing wells. During the year ended December 31, 2022, we brought online 15 gross (11.8 net) horizontal wells.

•The average WTI price increased by $35.50 per Bbl during the year ended December 31, 2022 when compared to the year ended September 30, 2021, respectively.

Natural gas revenues

•For the year ended December 31, 2022, natural gas revenues increased by $3.3 million, compared to the year ended September 30, 2021, to $10.8 million from $7.5 million. Volumes increased by 24%, while realized prices increased by $0.45 per Mcf compared to the year ended September 30, 2021.

•Natural gas sales volumes increased during the year ended December 31, 2022 compared to the year ended September 30, 2021 due to production from new wells and workovers performed on existing wells.

•The average Henry Hub price increased by $3.11 per Mcf during the year ended December 31, 2022 compared to the year ended September 30, 2021.

Natural gas liquids revenues

•For the year ended December 31, 2022, NGL revenues increased by $5.2 million, compared to the year ended September 30, 2021, to $9.9 million from $4.7 million. Volumes increase by 17%, while realized prices increased $9.81 per Bbl compared to the year ended September 30, 2021.

•NGL sales volumes increased during the year ended December 31, 2022 compared to the year ended September 30, 2021 due to production from new wells and workovers performed on existing wells.

Contract Services - Related Party

The following table presents the Company's revenue and costs associated with its contract services - related party transactions:

	Year Ended December 31, 2022		Year Ended September 30, 2021
	(In thousands)
Contract services - related parties(1)	$	2,400	$	2,400
Cost of contract services - related parties(2)	450		477
Gross profit from contract services	$	1,950	$	1,923

_____________________

(1)The Company’s contract services - related parties revenue is derived from master services agreements with related parties to provide certain administrative support services.

(2)The Company's cost of contract services - related parties represents costs specifically attributable to the master service agreements the Company has in place with the respective related parties.

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Costs and Expenses

The following table presents the Company's operating costs and expenses and other (income) expenses:

	Year Ended December 31, 2022		Year Ended September 30, 2021
Costs and Expenses:	(In thousands)
Lease operating expenses	$	32,458	$	21,975
Production and ad valorem taxes	$	19,273	$	8,636
Exploration costs	$	2,032	$	9,566
Depletion, depreciation, amortization and accretion	$	32,113	$	26,015
Impairment of oil and natural gas properties	$	7,325	$	—
Administrative costs	$	18,496	$	13,966
Equity-based compensation	3,439		6,793
General and administrative expense	$	21,935	$	20,759
Transaction costs	$	2,638	$	3,732
Interest expense, net	$	1,090	$	4,534
Loss on derivatives	$	51,574	$	89,195
Income tax expense	$	32,844	$	13,016

Lease Operating Expenses ("LOE")

LOE are the costs incurred in the operation and maintenance of producing properties. Expenses for compression, direct labor, saltwater disposal and materials and supplies comprise the most significant portion of our lease operating expenses. Certain operating cost components, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities or subsurface maintenance result in increased production expenses in periods during which they are performed. Certain operating cost components, such as compression and saltwater disposal associated with completion water, are variable and increase or decrease as hydrocarbon production levels and the volume of completion water disposal increases or decreases.

The Company’s LOE increased by $10.5 million for the year ended December 31, 2022 compared to the year ended September 30, 2021. For the year ended December 31, 2022, $5.4 million of the increase was due to higher workover expense as additional workovers were performed in the 2022 period, and $4.2 million of the increase was due to electricity and chemical rate increases, increase in field payroll, saltwater disposal charges, and new wells coming online.

Production and Ad Valorem Tax Expense

Production taxes are paid on produced oil, natural gas and NGLs based on a percentage of revenues at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to changes in our oil, natural gas and NGL revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties, which also trend with oil and natural gas prices and vary across the different counties in which we operate.

Production and ad valorem taxes increased by $10.6 million for the year ended December 31, 2022 compared to the year ended September 30, 2021. Production taxes increased primarily due to increases in our oil and natural gas sales, net, as discussed above. Ad valorem taxes increased for the year ended December 31, 2022 based on higher estimated property values for the current taxable period.

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Exploration Expense

Exploration expense consists of expiration of unproved leasehold and geological and geophysical costs which include seismic survey costs. The following table presents exploration expense by area for the year ended December 31, 2022 and the year ended September 30, 2021:

	Year Ended December 31, 2022		Year Ended September 30, 2021
	(In thousands, except acreage data)
Exploration expense(1)	$	1,953	$	9,347
Geological and geophysical costs	79		219
Total exploration expense	$	2,032	$	9,566
Expired net acres - Texas	857		1,651
Expired net acres - New Mexico	518		16,239
Net acres renewed after expiration(2)	72		505

_____________________

(1)For the year ended December 31, 2022, exploration expense includes $1.8 million and $0.2 million related to expiration of unproved leasehold costs in Texas and New Mexico, respectively. For the year ended September 30, 2021, exploration expense included $3.5 million and $5.8 million related to expiration of unproved leasehold costs in Texas and New Mexico, respectively.

(2)The Company did not renew any net acreage after expiration in New Mexico during the year ended December 31, 2022 and the year ended September 30, 2021.

Depletion, Depreciation, Amortization and Accretion Expense

Depletion, depreciation and amortization is the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil, natural gas and NGLs. All costs incurred in the acquisition, exploration and development of properties (excluding costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration activities) are capitalized. Capitalized costs are depleted using the units of production method.

Accretion expense relates to ARO. We record the fair value of the liability for ARO in the period in which the liability is incurred (at the time the wells are drilled or acquired) with the offset to property cost. The liability accretes each period until it is settled or the well is sold, at which time the liability is removed.

Depletion, depreciation, amortization and accretion expense increased by $6.1 million for the year ended December 31, 2022, respectively, compared to the year ended September 30, 2021. The increase for the year ended December 31, 2022 was primarily due to higher production, partially offset by a lower depletion rate. The depletion rate is a function of capitalized cost and related underlying reserves. The lower depletion rate was primarily driven by an increase in reserves as a result of the Company's drilling activity and improved commodity prices.

Impairment of Oil and Natural Gas Properties

The cost of proved oil and natural gas properties are assessed on a field-by-field basis for impairment at least annually or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We compare the expected undiscounted future cash flows of the oil and natural gas properties to the carrying amount of the oil, natural gas and NGL properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we adjust the carrying amount of the oil and natural gas properties to estimated fair value.

The Company recognized an impairment loss on proved properties of $7.3 million for the year ended December 31, 2022. The impairment loss relates to the New Mexico field and was driven by the Company focusing its drilling efforts on its acreage in Yoakum County. No impairment loss was recognized for the year ended September 30, 2021.

General and Administrative Expense ("G&A")

G&A expenses include corporate overhead such as payroll and benefits for our corporate staff, equity-based compensation expense, office rent for our headquarters, audit and other fees for professional services and legal compliance. G&A expenses are reported net of overhead recoveries.

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Total G&A expense increased by $1.2 million for the year ended December 31, 2022 compared to the year ended September 30, 2021. Administrative costs, which include payroll, benefits and non-payroll costs, increased by $4.5 million for the year ended December 31, 2022 compared to the year ended September 30, 2021. The increase in administrative costs was primarily attributable to increased employee count, professional services, insurance, technology, investor relations, and costs related to transitioning fiscal year-ends. Equity-based compensation expense decreased by $3.3 million for the year ended December 31, 2022 compared to the year ended September 30, 2021. The higher equity-based compensation during the year ended September 30, 2021 relates to restricted shares awarded to certain employees following completion of the Merger that immediately vested.

Transaction Costs

Transaction costs represent costs incurred on successful or unsuccessful business combinations or unsuccessful property acquisitions. The transaction costs of $2.6 million for the year ended December 31, 2022 primarily relate to a potential business combination and related financing that the Company pursued but ultimately chose not to consummate due to changing market conditions. During the year ended September 30, 2021, the transaction costs of $3.7 million primarily relate to costs incurred on the Merger with Tengasco in February 2021.

Interest Expense

Interest expense decreased by $3.4 million during the year ended December 31, 2022 when compared to the year ended September 30, 2021. The Company had a lower outstanding average balance on the revolving credit facility as well as an increase in the capitalized interest related to the Company's EOR project, partially offset by an increase in interest rates, during the year ended December 31, 2022 when compared to the year ended September 30, 2021. Additionally, interest expense decreased due to the Company settling the remaining open position on its interest rate swap resulting in a settlement of $1.5 million during 2022.

Gain/Loss on Derivatives

The Company recognizes settlements and changes in the fair value of its derivative contracts as a single component within other income (expense) on its consolidated statements of operations. We have oil and natural gas derivative contracts, including fixed price swaps, basis swaps and collars, that settle against various indices. The following table presents the components of the Company's loss on derivatives for the year ended December 31, 2022 and the year ended September 30, 2021:

	Year Ended December 31, 2022		Year Ended September 30, 2021
	(In thousands)
Settlements on derivative contracts	$	(75,257)	$	(16,304)
Non-cash gain (loss) on derivatives	23,683		(72,891)
Loss on derivatives	$	(51,574)	$	(89,195)

Our earnings are affected by the changes in value of our derivative portfolio between periods and the related cash received or paid upon settlement of our derivatives. To the extent the future commodity price outlook declines between periods, we will have mark-to-market gains, while future commodity price increases between measurement periods result in mark-to-market losses.

The loss on derivatives for the year ended December 31, 2022 was $51.6 million, which decreased by $37.6 million compared to the year ended September 30, 2021. The change in the non-cash gain (loss) on derivatives was impacted by the decrease in total contract volumes for our open derivative contracts and the change in the estimated forward-looking oil and natural gas prices used at the end of the period to calculate the fair value of the open derivative contracts for the year ended December 31, 2022 compared to the year ended September 30, 2021. The increase in the loss on settlements on derivatives was due to the increase in oil and natural gas prices for the year ended December 31, 2022 compared to the year ended September 30, 2021. For example, the average WTI price was $94.90 per Bbl for the year ended December 31, 2022 compared to $59.40 per Bbl for the year ended September 30, 2021.

Income Tax Expense

The Company became a taxable entity as a result of its Merger with Tengasco on February 26, 2021. See further discussion in Note 4 - Acquisitions and Divestitures to the Company's consolidated financial statements included herein. While REP LLC was organized as a limited liability company, taxable income passed through to its unitholders. Accordingly, a provision for

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federal and state corporate income taxes has been made for the operations of the Company beginning February 27, 2021 in the accompanying consolidated financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon consummation of the Merger in February 2021, the Company established a $13.6 million provision for deferred income taxes with the conversion to a C-corporation. The majority of this deferred tax liability was established by a change in tax status which primarily was attributable to the oil and natural gas properties. See Note 11 - Income Taxes to the Company's consolidated financial statements included herein for further discussion of income taxes.

	Year Ended December 31, 2022			Year Ended September 30, 2021
	(In thousands)
Current income tax expense	$	4,472		$	54
Deferred income tax expense (benefit)	28,372			12,962
Total income tax expense (benefit)	$	32,844		$	13,016
Effective income tax rate	21.7		%	(38.4)		%

Liquidity and Capital Resources

The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, like all upstream operators, we must make capital investments to grow and even sustain production. The Company’s principal liquidity requirements are to finance its operations, fund capital expenditures and acquisitions, make cash distributions and satisfy any indebtedness obligations. Cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and the significant capital expenditures required to more fully develop the Company’s oil and natural gas properties. Historically, our primary sources of capital funding and liquidity have been our cash on hand, cash flow from operations and borrowings under our revolving credit facility. At times and as needed, we may also issue debt or equity securities, including through transactions under our shelf registration statement filed with the SEC. We estimate the combination of the sources of capital discussed above will continue to be adequate to meet our short and long-term liquidity needs.

Cash on hand and operating cash flow can be subject to fluctuations due to trends and uncertainties that are beyond our control. Likewise, our ability to issue equity and obtain credit facilities on favorable terms may be impacted by a variety of market factors as well as fluctuations in our results of operations. For further discussion of risks related to our liquidity and capital resources, see "Item 1A. Risk Factors."

Working Capital

Working capital is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements is driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from customers, the level and timing of spending for expansion activity, and the timing of debt maturities. As of December 31, 2022, we had a working capital deficit of $25.3 million compared to a deficit of $32.8 million as of December 31, 2021. The working capital deficit at December 31, 2022 reflects $16.5 million in current derivative liabilities compared to $31.0 million in current derivative liabilities at December 31, 2021. As of December 31, 2022, we had an increase of $14.1 million in accrued capital expenditures and ad valorem tax. We utilize our revolving credit facility and cash on hand to manage the timing of cash flows and fund short-term working capital deficits. Our current derivative assets and liabilities represent the mark-to-market value as of December 31, 2022 of future commodity production which will settle on a monthly basis through the end of their contractual terms. This aligns with the receipt of oil and natural gas revenues on a monthly basis.

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Cash Flows

The following table summarizes the Company’s cash flows from continuing operations:

	Year Ended December 31, 2022		Year Ended September 30, 2021
	(In thousands)
Statement of Cash Flows Data from Continuing Operations:
Net cash provided by operating activities	$	170,288	$	86,073
Net cash used in investing activities	$	(128,256)	$	(59,628)
Net cash used in financing activities	$	(37,048)	$	(14,937)

Operating Activities

The Company’s net cash provided by operating activities increased by $84.2 million or 98% to $170.3 million for the year ended December 31, 2022 from $86.1 million for the year ended September 30, 2021. The increase was primarily driven by an increase in revenues of $170.7 million, partially offset by an increase of $59.0 million on settlements for commodity derivative contracts and an increase in operating expenses of $24.4 million, which excludes non-cash expenses such as equity-based compensation, expiration of unproved leasehold costs, impairment of oil and natural gas properties and depreciation, depletion, accretion and amortization expense.

Investing Activities

The Company's cash flows used in investing activities increased by $68.6 million or 115% to $128.3 million for the year ended December 31, 2022 from $59.6 million for the year ended September 30, 2021. The increase was primarily due to higher capital spending of $53.3 million related to the Company's increased drilling and completion activity and activity on its EOR Project during the year ended December 31, 2022 compared to the year ended September 30, 2021, in addition to $15.3 million for the purchase of land during the year ended December 31, 2022.

Financing Activities

Net cash flow used in financing activities increased by $22.1 million or 148% to $37.0 million for the year ended December 31, 2022 from $14.9 million for the year ended September 30, 2021. During the year ended September 30, 2021, the Company issued $46.7 million of equity, net of offering costs. These proceeds were primarily used to paydown amounts outstanding on the revolving credit facility. There was no equity issued in 2022. During the year ended December 31, 2022, the Company had a net paydown on its revolving credit facility of $9.0 million, which compares to a net paydown of $41.0 million for the same period in 2021. In addition, the Company distributed an additional $6.8 million of dividends on common stock during the year ended December 31, 2022 compared to the same period in 2021.

Revolving Credit Facility

The Company's borrowing base was $225 million with outstanding borrowings of $56 million on December 31, 2022, representing available borrowing capacity of $169 million. See further discussion in Note 9 - Revolving Credit Facility to the Company's consolidated financial statements included herein.

On April 29, 2022, the Company amended its Credit Agreement to, among other things, increase the borrowing base from $175 million to $200 million, extend the maturing date to April 2026, replace LIBOR with the SOFR and change the requirements for hedging to be based on utilization of the borrowing base and the Company's leverage ratio. On October 25, 2022, the Company subsequently amended its Credit Agreement to, among other things, increase the borrowing base from $200 million to $225 million and change the semi-annual redeterminations to April 1 and October 1 to align with the Company's new fiscal year end of December 31st.

Distributions

For the year ended December 31, 2022, the Company authorized and declared a quarterly dividend totaling approximately $25.3 million, with $24.7 million paid in cash and $0.6 million payable to restricted shareholders upon vesting.

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Contractual Obligations

The Company has commitments with its primary midstream counterparty and has entered into purchase commitments throughout the year ended December 31, 2022. See Note 14 - Commitments and Contingencies in our notes to the consolidated financial statements.

Critical Accounting Estimates

The discussion and analysis of the Company’s financial condition and results of operations are based upon the Company’s consolidated financial statements and accompanying notes included herein, which have been prepared in accordance with U.S. GAAP. The preparation of financial statements requires the Company to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

Changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates and assumptions used in preparation of the Company’s consolidated financial statements and it is at least reasonably possible these estimates could be revised in the near term and these revisions could be material.

Method of Accounting for Oil and Natural Gas Properties

We utilize the successful efforts method of accounting for our oil and natural gas exploration and development activities which requires management's assessment of the proper designation of wells and associated costs as developmental or exploratory. This classification assessment is dependent on the determination and existence of proved reserves, which is a critical estimate discussed in the section below. The classification of developmental and exploratory costs has a direct impact on the amount of costs we initially recognize as exploration expense or capitalize, then subject to DD&A calculations and impairment assessments and valuations.

Once a well is drilled, the determination that proved reserves have been discovered may take considerable time and requires both judgment and application of industry experience. Development wells are always capitalized. Costs associated with drilling an exploratory well are initially capitalized, or suspended, pending a determination as to whether proved reserves have been found. At the end of each quarter, the status of all suspended exploratory drilling costs are reviewed to determine whether the costs should continue to remain capitalized or shall be expensed. When making this determination, current activities, near-term plans for additional exploratory or appraisal drilling and the likelihood of reaching a development program is considered. If future development activities and the determination of proved reserves are unlikely to occur, the associated suspended exploratory well costs are recorded as dry hole expense and reported in exploration expense in the consolidated statements of operations. Otherwise, the costs of exploratory wells remain capitalized.

Similar to the evaluation of suspended exploratory well costs, costs for unproved leasehold, for which reserves have not been proven, must also be evaluated for continued capitalization or impairment. At the end of each quarter, unproved leasehold costs are assessed for impairment by considering future drilling plans, drilling activity results, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. At December 31, 2022, the Company had approximately $12.8 million of unproved leasehold. Of the remaining unproved leasehold costs at December 31, 2022, approximately $0.6 million is scheduled to expire in 2023. The Company will renew or extend the lease if the leasehold expiring in 2023 relates to areas in which the Company is actively drilling. If our drilling is not successful, this leasehold could become partially or entirely impaired.

Once a well is drilled, capitalized well costs for drilling and completion activities must be evaluated at least yearly or whenever facts and circumstances indicate a decline in the recoverability of their carrying value may have occurred. At the end of each year, the undiscounted future cash flows are compared to the carrying value on a field basis to evaluate if the carrying value is recoverable. If the carrying value is not recoverable, the Company will compare the carrying value of the asset to its fair value and recognize any impairment loss in the period. Significant inputs and judgements are used in determining the fair value of the assets. The Company utilizes a discounted cash flow model in order to estimate fair value by modeling the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with the expected cash flow projected. During the year ended December 31, 2022, the Company recognized a proved property impairment of $7.3 million related to the oil and natural gas properties in New Mexico.

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Oil and Natural Gas Reserves

Our estimates of proved and proved developed reserves are a major component of our depletion calculation. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, natural gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. A third-party consulting firm prepares our reserve report which the estimates are based off of technical and economic data including, but not limited to, well test data, production data, historical price and cost information, and property ownership interests.

The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

Goodwill

We test goodwill for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. If the fair value is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. Because quoted market prices are not available, the fair value is estimated based upon a valuation analyses including comparable companies and transactions and premiums paid. An impairment loss is recognized if the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill.

The Company recognized goodwill of $19.0 million from the result of the Merger, all of which was allocated to the oil and natural gas properties acquired from the Merger. The Company bypassed the qualitative analysis to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying value amount, including goodwill, since the Company entered into a PSA shortly after acquiring the oil and natural gas properties. The Company compared the reporting unit fair value of $3.5 million with its carrying amount, including goodwill, of $19.0 million and recognized a goodwill impairment of $18.5 million. The impairment loss was recognized within loss from discontinued operations for the year ended September 30, 2021 in our consolidated statement of operations.

See Note 3 - Summary of Significant Accounting Policies in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our significant accounting policies.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 8. Financial Statements and Supplementary Data

The information required by this item appears beginning on page F-1 of this report.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

Our management establishes and maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Such information is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate, to allow

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timely decisions regarding required disclosure. We evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2022, with the participation of our CEO and CFO, as well as other key members of our management. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2022.

Management's Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external reporting purposes in accordance with accounting principles generally accepted in the United States.

Our management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2022, using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework (2013). We have evaluated the effectiveness of our internal control over financial reporting as of the end of the period covered by this report, with the participation of our CEO and CFO, as well as other key members of our management. Based on this assessment, management concluded that, as of December 31, 2022, the Company’s internal control over financial reporting was effective.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended December 31, 2022 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Report of the Independent Registered Public Accounting Firm

Shareholders and Board of Directors

Riley Exploration Permian, Inc.

Oklahoma City, Oklahoma

Opinion on Internal Control over Financial Reporting

We have audited Riley Exploration Permian, Inc.’s (the “Company’s”) internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of December 31, 2022 and 2021, the related consolidated statements of operations, changes in members’/shareholders’ equity, and cash flows for the year ended December 31, 2022, the three months ended December 31, 2021, and the year ended September 30, 2021, and the related notes and our report dated March 8, 2023 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A, Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ BDO USA, LLP

Houston, Texas

March 8, 2023

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Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information as to Item 10 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2022.

Item 11. Executive Compensation

Information as to Item 11 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2022.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information as to Item 12 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2022.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information as to Item 13 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2022.

Item 14. Principal Accountant Fees and Services

Information as to Item 14 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2022.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

The following documents are filed as a part of this report:

(1) Consolidated Financial Statements

Reference is made to the Index to Consolidated Financial Statements appearing on page F-1.

(2) Financial Statement Schedules

All financial statement schedules have been omitted because they are not applicable or the required information is presented in the consolidated financial statements or notes thereto.

(3) Exhibits

Exhibit Number	Description
2.1	Agreement and Plan of Merger, by and among Tengasco, Inc., Antman Sub, LLC, and Riley Exploration - Permian, LLC, dated as of October 21, 2020 (incorporated by reference from Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on October 22, 2020).
2.2	Amendment No. 1 to Agreement and Plan of Merger, by and among Tengasco, Inc., Antman Sub, LLC, and Riley Exploration - Permian, LLC, dated as of January 20, 2021 (incorporated by reference from Exhibit 2.1 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on January 22, 2021).
3.1	First Amended and Restated Certificate of Incorporation of Riley Exploration Permian, Inc. (incorporated by reference to Exhibit 4.1 to the Registrant’s Registration Statement on Form S-8 filed with the Securities and Exchange Commission on March 1, 2021, Registration No. 333-253750).
3.2	Third Amended and Restated Bylaws of Riley Exploration Permian, Inc. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on September 23, 2022).
10.1	Credit Agreement dated as of September 28, 2017, by and among Riley Exploration – Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.1 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.2	First Amendment to Credit Agreement dated as of February 27, 2018, by and among Riley Exploration – Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.2 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.3	Second Amendment to Credit Agreement dated as of November 9, 2018, by and among Riley Exploration – Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.3 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.4	Third Amendment to Credit Agreement dated as of April 3, 2019, by and among Riley Exploration – Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.4 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.5	Fourth Amendment to Credit Agreement dated as of October 15, 2019, by and among Riley Exploration – Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.5 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.6	Fifth Amendment to Credit Agreement dated as of May 7, 2020, by and among Riley Exploration – Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.6 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).

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10.7	Sixth Amendment to Credit Agreement dated as of August 31, 2020, by and among Riley Exploration – Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.7 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.8	Seventh Amendment and Consent to Credit Agreement dated as of October 21, 2020, by and among Riley Exploration – Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.8 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.9	Eighth Amendment to Credit Agreement dated as of March 5, 2021, by and among Riley Exploration Permian, Inc., Riley Exploration - Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.9 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2021, as filed with the Securities and Exchange Commission on May 17, 2021).
10.10	Ninth Amendment to Credit Agreement dated as of May 5, 2021, by and among Riley Exploration Permian, Inc., Riley Exploration - Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.10 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2021, as filed with the Securities and Exchange Commission on May 17, 2021).
10.11	Tenth Amendment to the Credit Agreement dated as of October 12, 2021, by and among Riley Exploration Permian, Inc., Riley Exploration - Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on October 14, 2021).
10.12	Form of Indemnity Agreement (incorporated by reference from Exhibit 10.14 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on January 21, 2021, Registration No. 333-250019).
10.13	Form of Independent Director Agreement (incorporated by reference from Exhibit 10.13 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on January 21, 2021, Registration No. 333-250019).
10.14†	Riley Exploration Permian, Inc. 2021 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 25, 2021).
10.15†	Form of Common Stock Award Agreement (incorporated by reference from Exhibit 10.10 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on March 15, 2021).
10.16†	Form of Restricted Stock Agreement (Time Vesting) (incorporated by reference to Exhibit 4.4 to the Registrant’s Registration Statement on Form S-8, as filed with the Securities and Exchange Commission on March 1, 2021, Registration No. 333- 253750).
10.17†	Form of Substitute Restricted Stock Agreement (Time Vesting) (incorporated by reference from Exhibit 4.5 to the Registrant’s Registration Statement on Form S-8 filed with the Commission on March 1, 2021, Registration No. 333-253750).
10.18†	Form of Restricted Stock Agreement (Non-Employee Director) (incorporated by reference from Exhibit 4.6 to the Registrant’s Registration Statement on Form S-8 filed with the Commission on March 1, 2021, Registration No. 333-253750).
10.19†	Employment Agreement dated effective as of March 15, 2021 by and between Riley Exploration Permian, Inc. and Corey Riley (incorporated by reference from Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on March 15, 2021).
10.20†	Employment Agreement dated effective as of March 15, 2021 by and between Riley Exploration Permian, Inc. and Philip Riley (incorporated by reference from Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on March 15, 2021).
10.21†	Employment Agreement dated April 1, 2019 by and between Riley Exploration – Permian, LLC and Bobby D. Riley and assigned by Riley Exploration – Permian, LLC to Riley Permian Operating Company, LLC on June 8, 2019 (incorporated by reference from Exhibit 10.9 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).

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10.22†	Amendment No. 1 to Employment Agreement dated October 1, 2020 by and between Riley Permian Operating Company, LLC and Bobby D. Riley (incorporated by reference from Exhibit 10.10 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.23†	Amendment No. 2 to Employment Agreement dated March 15, 2021 by and between Riley Permian Operating Company, LLC and Bobby D. Riley (incorporated by reference from Exhibit 10.7 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on March 15, 2021).
10.24†	Employment Agreement dated April 1, 2019 by and between Riley Exploration – Permian, LLC and Kevin Riley and assigned by Riley Exploration – Permian, LLC to Riley Permian Operating Company, LLC on June 8, 2019 (incorporated by reference from Exhibit 10.11 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019)
10.25†	Amendment No. 1 to Employment Agreement dated March 15, 2021 by and between Riley Permian Operating Company, LLC and Kevin Riley (incorporated by reference from Exhibit 10.8 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on March 15, 2021).
10.26	Second Amended and Restated Registration Rights Agreement dated October 7, 2020 by and among Riley Exploration – Permian, LLC, Riley Exploration Group, Inc., Yorktown Energy Partners XI, L.P., Boomer Petroleum, LLC, Bluescape Riley Exploration Holdings LLC, Bluescape Riley Acquisition Company LLC, Bobby D. Riley, Kevin Riley and Corey Riley (incorporated by reference to Exhibit 4.1 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.27†	Employment Agreement dated effective as of January 25, 2022 by and between Riley Exploration Permian, Inc. and Amber Bonney (incorporated by reference from Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on January 27, 2022).
10.28	Eleventh Amendment to the Credit Agreement dated as of April 29, 2022, by and among Riley Exploration Permian, Inc., Riley Exploration - Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.1 to the Registrant's Current Report on Form 8-K, as filed with the Securities and Exchange Commission on May 2, 2022).
10.29	Twelfth Amendment to the Credit Agreement dated as of October 25, 2022, by and among Riley Exploration Permian, Inc., Riley Exploration - Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.1 to the Registrant's Current Report on Form 8-K, as filed with the Securities and Exchange Commission on October 26, 2022).
10.30	Thirteenth Amendment to the Credit Agreement dated as of February 22, 2023, by and among Riley Exploration Permian, Inc., Riley Exploration - Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.2 to the Registrant's Current Report on Form 8-K, as filed with the Securities and Exchange Commission on February 27, 2023).
10.31	Purchase and Sale Agreement dated February 22, 2023 by and between Pecos Oil & Gas, LLC, as Seller, and Riley Exploration - Permian, LLC, as Purchaser (incorporated by reference from Exhibit 2.1 to the Registrant's Current Report on Form 8-K, as filed with the Securities and Exchange Commission on February 27, 2023).
10.32	Commitment Letter dated February 22, 2023 by and between Riley Exploration Permian, Inc. and EOC Partners Advisors L.P. (incorporated by reference from Exhibit 10.1 to the Registrant's Current Report on Form 8-K, as filed with the Securities and Exchange Commission on February 27, 2023)
21.1*	Subsidiaries of the Registrant
23.1*	Consent of BDO USA, LLP
23.2*	Consent of Netherland, Sewell & Associates, Inc.
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C., Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C., Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1*	Report of Netherland, Sewell & Associates, Inc.
101.INS*	XBRL Instance Document

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101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Definition Linkbase Document
101.LAB*	XBRL Taxonomy Label Linkbase Document
101.PRE*	XBRL Taxonomy Presentation Linkbase Document

*    Filed herewith.

†    Compensatory plan or arrangement.

Item 16. Form 10-K Summary

None.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	RILEY EXPLORATION PERMIAN, INC.
Date: March 8, 2023	By:	/s/ Bobby D. Riley
		Bobby D. Riley
		Chief Executive Officer
	By:	/s/ Philip Riley
		Philip Riley
		Chief Financial Officer

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in their capacities and on the dates indicated.

Signature	Title	Date
/s/ Bobby D. Riley	Chairman of the Board and Chief Executive Officer (Principal Executive Officer)	March 8, 2023
Bobby D. Riley
/s/ Philip Riley	Chief Financial Officer (Principal Financial Officer)	March 8, 2023
Philip Riley
/s/ Amber Bonney	Chief Accounting Officer (Principal Accounting Officer)	March 8, 2023
Amber Bonney
/s/ Brent Arriaga	Director	March 8, 2023
Brent Arriaga
/s/ Bryan H. Lawrence	Director	March 8, 2023
Bryan H. Lawrence
/s/ E. Wayne Nordberg	Director	March 8, 2023
E. Wayne Nordberg
/s/ Beth A. di Santo	Director	March 8, 2023
Beth A di Santo
/s/ Rebecca Bayless	Director	March 8, 2023
Rebecca Bayless

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INDEX TO FINANCIAL STATEMENTS
	Page
Report of Independent Registered Public Accounting Firm (BDO USA, LLP; Houston, Texas, PCAOB ID #243)	F-2
Consolidated Balance Sheets as of December 31, 2022 and 2021	F-4
Consolidated Statements of Operations for the Year Ended December 31, 2022, Three Months Ended December 31, 2021 and Year Ended September 30, 2021	F-5
Consolidated Statements of Changes in Members'/Shareholders' Equity for the Year Ended December 31, 2022, Three Months Ended December 31, 2021 and Year Ended September 30, 2021	F-7
Consolidated Statements of Cash Flows for the Year Ended December 2022, Three Months Ended December 31, 2021 and Year Ended September 30, 2021	F-8
Notes to Consolidated Financial Statements	F-10

F-1

Report of Independent Registered Public Accounting Firm

Shareholders and Board of Directors

Riley Exploration Permian, Inc.

Oklahoma City, Oklahoma

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Riley Exploration Permian, Inc. (the “Company”) as of December 31, 2022 and 2021, the related consolidated statements of operations, changes in members’/shareholders’ equity, and cash flows for the year ended December 31, 2022, the three months ended December 31, 2021, and the year ended September 30, 2021, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2022 and 2021, and the results of its operations and its cash flows for the year ended December 31, 2022, the three months ended December 31, 2021, and the year ended September 30, 2021, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company's internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and our report dated March 8, 2023 expressed an unqualified opinion thereon.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

F-2

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Estimation of Oil and Natural Gas Reserves and Effect on Depreciation, Depletion and Amortization (“DD&A”) Expense and Impairment Expense Related to Proved Oil and Natural Gas Properties

The Company’s oil and natural gas properties, net balance as of December 31, 2022 was $440.1 million, which includes proved oil and natural gas properties of $516.0 million and accumulated DD&A and impairment of $133.8 million. DD&A expense and impairment expense was $31.5 million and $7.3 million, respectively, for the year ended December 31, 2022. As described in Note 3 – Summary of Significant Accounting Policies to the consolidated financial statements, the Company accounts for its oil and natural gas activities using the successful efforts method of accounting which involves management’s use of internal and independent petroleum engineers to make estimates of proved oil and natural gas reserves necessary to record DD&A expense and impairment expense. To estimate the proved oil and natural gas reserves, management and their internal and independent petroleum engineers make significant estimates and assumptions including forecasting of future production volumes of proved oil and natural gas properties.

We have identified the estimation of future production volumes used to estimate proved oil and natural gas reserves and the associated effect on DD&A expense and impairment expense related to proved oil and natural gas properties as a critical audit matter. Estimating future production volumes involves a high degree of subjectivity from management and their internal and independent petroleum engineers. Changes in this estimate and assumptions could have a significant effect on the measurement of DD&A expense and impairment expense. Auditing this estimate and assumptions required subjective and complex auditor judgement.

The primary procedures we performed to address this critical audit matter included:

•Testing the design and operating effectiveness of internal controls relating to management’s estimation of proved oil and natural gas reserves.

•Evaluating the professional qualifications of the internal and independent petroleum engineers, including their relationship to the Company, and evaluating the process and judgments used in estimating the Company’s proved oil and natural gas reserves.

•Comparing estimates of future production volumes and production decline analyses against historical results of production volumes and production decline analyses on a summary basis for all wells, on a detailed basis for certain wells and on a field level for the field that was impaired during the year.

•Performing a retrospective review over management estimates of future production volumes made in prior periods as compared to actual results.

/s/ BDO USA, LLP

We have served as the Company's auditor since 2016.

Houston, Texas

March 8, 2023

F-3

RILEY EXPLORATION PERMIAN, INC.
CONSOLIDATED BALANCE SHEETS
	December 31, 2022		December 31, 2021
	(In thousands, except share amounts)
Assets
Current Assets:
Cash and cash equivalents	$	13,301	$	8,317
Accounts receivable	25,551		18,002
Prepaid expenses and other current assets	3,236		4,122
Inventory	8,886		780
Current derivative assets	20		83
Total current assets	50,994		31,304
Oil and natural gas properties, net (successful efforts)	440,102		359,131
Other property and equipment, net	20,023		3,174
Non-current derivative assets	—		267
Other non-current assets, net	4,175		2,293
Total Assets	$	515,294	$	396,169
Liabilities and Shareholders' Equity
Current Liabilities:
Accounts payable	$	3,939	$	7,737
Accounts payable - related parties	324		164
Accrued liabilities	35,582		12,874
Revenue payable	17,750		11,370
Current derivative liabilities	16,472		30,984
Other current liabilities	2,238		947
Total Current Liabilities	76,305		64,076
Non-current derivative liabilities	12		9,515
Asset retirement obligations	2,724		2,261
Revolving credit facility	56,000		65,000
Deferred tax liabilities	45,756		17,384
Other non-current liabilities	1,051		95
Total Liabilities	181,848		158,331
Commitments and Contingencies (Note 14)
Shareholders' Equity:
Preferred stock, $0.0001 par value, 25,000,000 shares authorized; 0 shares issued and outstanding	—		—
Common stock, $0.001 par value, 240,000,000 shares authorized; 20,160,980 and 19,836,885 shares issued and outstanding at December 31, 2022 and December 31, 2021, respectively	20		20
Additional paid-in capital	274,643		271,737
Retained earnings (Accumulated deficit)	58,783		(33,919)
Total Shareholders' Equity	333,446		237,838
Total Liabilities and Shareholders' Equity	$	515,294	$	396,169

The accompanying notes are an integral part of these consolidated financial statements.

F-4

RILEY EXPLORATION PERMIAN, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands, except per share/unit amounts)
Revenues:
Oil and natural gas sales, net	$	319,343	$	56,650	$	148,636
Contract services - related parties	2,400		600		2,400
Total Revenues	321,743		57,250		151,036
Costs and Expenses:
Lease operating expenses	32,458		7,419		21,975
Production and ad valorem taxes	19,273		3,005		8,636
Exploration costs	2,032		611		9,566
Depletion, depreciation, amortization and accretion	32,113		6,867		26,015
Impairment of oil and natural gas properties	7,325		—		—
General and administrative:
Administrative costs	18,496		3,633		13,966
Unit-based compensation expense	—		—		689
Share-based compensation expense	3,439		951		6,104
Cost of contract services - related parties	450		150		477
Transaction costs	2,638		1,258		3,732
Total Costs and Expenses	118,224		23,894		91,160
Income From Operations	203,519		33,356		59,876
Other Expense:
Interest expense, net	(1,090)		(896)		(4,534)
Loss on derivatives	(51,574)		(5,193)		(89,195)
Total Other Expense	(52,664)		(6,089)		(93,729)
Net Income (Loss) From Continuing Operations Before Income Taxes	150,855		27,267		(33,853)
Income tax expense	(32,844)		(5,869)		(13,016)
Net Income (Loss) From Continuing Operations	118,011		21,398		(46,869)

The accompanying notes are an integral part of these consolidated financial statements.

F-5

RILEY EXPLORATION PERMIAN, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS - (Continued)
	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands, except per share/unit amounts)
Discontinued Operations:
Loss from discontinued operations	—		—		(18,738)
Income tax expense on discontinued operations	—		—		(59)
Loss on Discontinued Operations	—		—		(18,797)
Net Income (Loss)	118,011		21,398		(65,666)
Dividends on preferred units	—		—		(1,491)
Net Income (Loss) Attributable to Common Shareholders/Unitholders	$	118,011	$	21,398	$	(67,157)
Net Income (Loss) per Share/Unit from Continuing Operations:
Basic	$	6.04	$	1.10	$	(3.02)
Diluted	$	5.99	$	1.09	$	(3.02)
Net Loss per Share/Unit from Discontinued Operations:
Basic	$	—	$	—	$	(1.17)
Diluted	$	—	$	—	$	(1.17)
Net Income (Loss) per Share/Unit:
Basic	$	6.04	$	1.10	$	(4.19)
Diluted	$	5.99	$	1.09	$	(4.19)
Weighted Average Common Shares/Units Outstanding:
Basic	19,553		19,470		16,021
Diluted	19,686		19,569		16,021

The accompanying notes are an integral part of these consolidated financial statements.

F-6

RILEY EXPLORATION PERMIAN, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS'/SHAREHOLDERS' EQUITY
(In Thousands)
	Members' Equity			Shareholders' Equity
				Common Stock
	Units Outstanding	Amount		Shares	Amount		Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)		Total Shareholders' Equity
Balance, September 30, 2020	1,555	$	166,617	—	$	—	$	—	$	—	$	—
Issuance of common units under long-term incentive plan	13	—		—	—		—		—		—
Purchase of common units under long-term incentive plan	(3)	(191)		—	—		—		—		—
Dividends on preferred units	—	(1,491)		—	—		—		—		—
Dividends on common units	—	(7,571)		—	—		—		—		—
Unit-based compensation expense	—	689		—	—		—		—		—
Net loss from October 1, 2020 through February 26, 2021	—	(27,058)		—	—		—		—		—
Preferred units converted to common units	512	61,196		—	—		—		—		—
Restricted common shares issued in exchange for common units issued under long-term incentive plan	(24)	—		198	—		—		—		—
Common shares issued in exchange for common units (effected for 1-for-12 reverse stock split)	(2,053)	(192,191)		16,733	17		192,174		—		192,191
Common shares issued for business combination	—	—		891	1		26,391		—		26,392
Restricted common shares issued	—	—		3	—		—		—		—
Share-based compensation expense	—	—		—	—		1,939		—		1,939
Dividends declared	—	—		—	—		—		(10,559)		(10,559)
Net loss from February 27, 2021 through September 30, 2021	—	—		—	—		—		(38,608)		(38,608)
Issuance of common shares under long-term incentive plan	—	—		197	—		4,165		—		4,165
Common stock sold to public, net of issuance costs	—	—		1,667	2		46,682		—		46,684
Repurchased shares for tax withholding	—	—		(17)	—		(514)		—		(514)
Balance, September 30, 2021	—	$	—	19,672	$	20	$	270,837	$	(49,167)	$	221,690
Share-based compensation expense	—	—		—	—		919		—		919
Repurchased shares for tax withholding	—	—		(10)	—		(19)		—		(19)
Issuance of common shares under long-term incentive plan	—	—		175	—		—		—		—
Dividends declared	—	—		—	—		—		(6,150)		(6,150)
Net income	—	—		—	—		—		21,398		21,398
Balance, December 31, 2021	—	$	—	19,837	$	20	$	271,737	$	(33,919)	$	237,838
Share-based compensation expense	—	—			—		3,946		—		3,946
Repurchased shares for tax withholding	—	—		(45)	—		(1,040)		—		(1,040)
Issuance of common shares under long-term incentive plan	—	—		369	—		—		—		—
Dividends declared	—	—		—	—		—		(25,309)		(25,309)
Net income	—	—		—	—		—		118,011		118,011
Balance, December 31, 2022	—	$	—	20,161	$	20	$	274,643	$	58,783	$	333,446

The accompanying notes are an integral part of these consolidated financial statements.

F-7

RILEY EXPLORATION PERMIAN, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Cash Flows from Operating Activities:
Net income (loss)	$	118,011	$	21,398	$	(65,666)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss from discontinued operations	—		—		18,797
Oil and gas lease expirations	1,953		588		9,347
Depletion, depreciation, amortization and accretion	32,113		6,867		26,015
Impairment of proved properties	7,325		—		—
Loss on derivatives	51,574		5,193		89,195
Settlements on derivative contracts	(75,257)		(16,014)		(16,304)
Amortization of deferred financing costs	731		282		653
Unit-based compensation expense	—		—		689
Share-based compensation expense	3,946		951		6,104
Deferred income tax expense	28,372		5,756		12,962
Changes in operating assets and liabilities
Accounts receivable	(7,549)		(529)		(7,345)
Accounts receivable – related parties	—		456		(401)
Prepaid expenses and other current assets	(997)		(3,172)		201
Accounts payable and accrued liabilities	2,860		(2,625)		7,445
Accounts payable - related parties	160		164		—
Revenue payable	6,380		2,362		4,576
Other current liabilities	666		50		(195)
Net Cash Provided by Operating Activities - Continuing Operations	170,288		21,727		86,073
Cash Flows from Investing Activities:
Additions to oil and natural gas properties	(111,662)		(29,011)		(58,329)
Acquisitions of oil and natural gas properties	—		—		(445)
Acquisitions of land	(15,342)		—		—
Additions to other property and equipment	(1,252)		(117)		(1,714)
Tengasco acquired cash	—		—		860
Net Cash Used in Investing Activities - Continuing Operations	(128,256)		(29,128)		(59,628)

The accompanying notes are an integral part of these consolidated financial statements.

F-8

RILEY EXPLORATION PERMIAN, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS - (Continued)
	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Cash Flows from Financing Activities:
Deferred financing costs	(1,942)		(274)		(139)
Proceeds from revolving credit facility	22,000		5,000		5,500
Repayments under revolving credit facility	(31,000)		—		(46,500)
Payment of common share/unit dividends	(25,066)		(6,056)		(18,286)
Proceeds from issuance of common stock	—		—		50,000
Public offering costs	—		—		(3,316)
Payment of preferred unit dividends	—		—		(1,491)
Common stock repurchased for tax withholding	(1,040)		(19)		(514)
Purchase of common units under long-term incentive plan	—		—		(191)
Net Cash Used in Financing Activities - Continuing Operations	(37,048)		(1,349)		(14,937)
Net Increase (Decrease) in Cash and Cash Equivalents from Continuing Operations	4,984		(8,750)		11,508
Cash Flows from Discontinued Operations:
Operating activities	—		—		7
Investing activities	—		—		3,892
Net Increase in Cash and Cash Equivalents from Discontinued Operations	—		—		3,899
Net Increase (Decrease) in Cash and Cash Equivalents	4,984		(8,750)		15,407
Cash and Cash Equivalents, Beginning of Period	8,317		17,067		1,660
Cash and Cash Equivalents, End of Period	$	13,301	$	8,317	$	17,067
Supplemental Disclosure of Cash Flow Information
Cash Paid For:
Interest, net of capitalized interest	$	1,749	$	495	$	3,234
Income taxes	$	3,611	$	—	$	191
Non-cash Investing and Financing Activities - Continuing Operations:
Changes in capital expenditures in accounts payable and accrued liabilities	$	15,229	$	(8,443)	$	11,204
Right of use assets obtained in exchange for operating lease liability	$	1,655	$	—	$	—
Preferred unit dividends paid in kind	$	—	$	—	$	904
Common stock issued in exchange for common units	$	—	$	—	$	192,191
Assets acquired and liabilities assumed in business combination	$	—	$	—	$	3,695
Common stock issued for business combination	$	—	$	—	$	26,392
Preferred units converted to common units	$	—	$	—	$	61,196
Non-cash Investing Activities - Discontinued Operations:
Goodwill incurred in business combination	$	—	$	—	$	19,013
Assets acquired and liabilities assumed in business combination	$	—	$	—	$	2,824

The accompanying notes are an integral part of these consolidated financial statements.

F-9

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(1)Nature of Business

Organization

Riley Exploration Permian, Inc., ("Riley Permian", "REPX", "the Company", "Registrant", "we", "our", or "us"), is a growth-oriented, independent oil and natural gas company focused on the acquisition, exploration, development and production of oil, natural gas and natural gas liquids ("NGL") in Texas and New Mexico. Our activities primarily include the horizontal development of the San Andres formation, a shelf margin deposit on the Northwest Shelf of the Permian Basin. Our acreage is primarily located on large, contiguous blocks in Yoakum County, Texas.

On February 26, 2021 (the “Closing Date”), Riley Permian (f/k/a Tengasco, Inc. (“Tengasco”)), consummated a merger, dated as of October 21, 2020, by and among Tengasco, Antman Sub, LLC, a newly formed Delaware limited liability company and wholly owned subsidiary of Tengasco (“Merger Sub”), and Riley Exploration – Permian, LLC (“REP LLC”). Merger Sub merged with and into REP LLC, with REP LLC as the surviving company and as a wholly owned subsidiary of Tengasco (collectively, with the other transactions described in the Merger Agreement, the “Merger”). On the Closing Date, the Registrant changed its name from Tengasco, Inc. to Riley Exploration Permian, Inc.

Current Commodity Environment

U.S. and global markets experienced heightened volatility following impactful geopolitical events, consistent evidence of widespread inflation, as well as increased fears of an economic recession. However, commodity prices continued to remain high during 2022 due to OPEC+ and other oil and natural gas producers not rapidly increasing production levels, as well as from the recovery in demand related to the COVID-19 pandemic. The full-scale military invasion of Ukraine by Russian troops has continued unabated since February 2022 coupled with related economic sanctions imposed on Russia further exacerbating supply shortages, leading to disruptions in the credit and capital markets, including significant uncertainty in commodity prices, during 2022.

(2)Basis of Presentation

On August 16, 2022, the Company's Board of Directors (the "Board") acting by written consent resolved to amend and restate the Company's Second Amended and Restated Bylaws to change the Company's fiscal year period from October 1st through September 30th each year to January 1st through December 31st each year commencing with the 2022 calendar year (the "Bylaws Restatement"). On August 19, 2022, the holders of approximately 75% of our outstanding Common Stock acting by written consent approved the Bylaws Restatement and adopted the Third Amended and Restated Bylaws. In accordance with Rule 14c-2 under the Exchange Act, the aforementioned actions taken by written consent became effective on September 23, 2022. As a result, the Company's 2022 fiscal year is now the period from January 1, 2022 to December 31, 2022.

The accompanying consolidated financial statements include the accounts of Riley Permian and its wholly owned subsidiaries REP LLC, Riley Permian Operating Company, LLC ("RPOC"), Tengasco Pipeline Corporation, Tennessee Land & Mineral Corporation, and Manufactured Methane Corporation, and have been prepared in accordance with accounting principles generally accepted in the United States ("U.S. GAAP"). All intercompany balances and transactions have been eliminated upon consolidation. The Merger was accounted for as a reverse merger and, as such, the historical operations of REP LLC are deemed to be those of the Company. Thus, the consolidated financial statements included in this report reflect (i) the historical operating results of REP LLC prior to the Merger; (ii) the consolidated results of the Company following the Merger; (iii) the assets and liabilities of REP LLC at their historical cost; and (iv) the Company’s equity and earnings per share for all periods presented.

Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had an immaterial effect on the previously reported total assets, total liabilities, members'/shareholders' equity, results of operations or cash flows.

F-10

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(3)Summary of Significant Accounting Policies

Significant Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, accounts receivable, accrued capital expenditures and operating expenses, asset retirement obligations ("ARO"), the fair value determination of acquired assets and assumed liabilities, certain tax accruals and the fair value of derivatives.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. The Company maintains cash at financial institutions which may at times exceed federally insured amounts. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on its cash and cash equivalents.

Accounts Receivable

Our receivables arise primarily from the sale of oil, natural gas and NGLs and joint interest owner receivables for properties in which we serve as the operator. Accounts receivable are stated at amounts due, net of an allowance for credit losses, if necessary.

Accounts receivable from oil, natural gas and NGL sales are generally due within 30 to 60 days after the last day of each production month. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items.

To the extent actual volumes and prices of oil, natural gas and NGLs are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balance sheets. Oil is priced based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Natural gas pricing provisions are tied to a market index, with certain adjustments based on, among other factors, quality and heat content of natural gas, and prevailing supply and demand conditions. NGLs are priced based upon a market index with certain adjustments for transportation and fractionation. These market indices are determined on a monthly basis.

The Company estimates uncollectible amounts based on the length of time that the accounts receivable has been outstanding, historical collection experience and current and future economic and market conditions, if failure to collect is expected to occur. Allowances for credit losses are recorded as reductions to the carrying values of the accounts receivables included in the Company’s consolidated balance sheets and are recorded in Administrative costs in the consolidated statements of operations if failure to collect an estimable portion is determined to be probable. The Company had no allowance for credit losses at December 31, 2022 and December 31, 2021.

F-11

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Accounts receivable is summarized below:

	December 31, 2022		December 31, 2021
	(In thousands)
Oil, natural gas and NGL sales	$	24,136	$	17,562
Joint interest accounts receivable	793		409
Other accounts receivable	622		31
Total accounts receivable	$	25,551	$	18,002

Inventory

The Company's inventory represents tangible assets such as drilling pipe, tubing, casing and operating supplies used in the Company's future drilling or repair operations. The Company accounts for its inventory using the first-in, first-out method and valued at the lower of cost or net realizable value.

Proved Oil and Natural Gas Properties

The Company uses the successful efforts method of accounting for its oil and natural gas producing activities. Under this method, all property acquisition costs and costs of development wells are capitalized as incurred. The costs of development wells are capitalized whether producing or non-producing. Costs to drill exploratory wells are capitalized pending the determination of whether proved reserves are found. If an exploratory well is determined to be unsuccessful, the costs of drilling the unsuccessful exploratory well are charged to exploration costs.

Geological and geophysical costs, including seismic studies, are charged to exploration costs as incurred. Expenditures incurred to operate and for maintenance, repairs and minor renewals necessary to maintain our oil and natural gas properties in operating condition are charged to lease operating expenses as incurred.

Capitalized costs of proved oil and natural gas properties are amortized using the units-of-production method based on production and estimates of proved reserve quantities. Leasehold acquisition costs of proved properties are depleted over total estimated proved reserves, and capitalized development costs of wells and related equipment and facilities are depleted over-estimated proved developed reserves.

On the sale or retirement of a complete unit of a proved property or field, the cost and related accumulated depletion, depreciation and amortization are eliminated from the oil and natural gas property accounts, and the resulting gain or loss is recognized. On the sale of a partial unit of proved property, the unamortized cost of the property is apportioned to the interest sold and the interest retained is accounted for on the basis of the fair value of the retained interests and a gain or loss is recognized if the divestiture significantly affects the depletion rate.

Unproved Oil and Natural Gas Properties

Unproved oil and natural gas properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we charge the associated unproved lease acquisition costs to exploration costs. Lease acquisition costs related to successful drilling are reclassified to proved oil and natural gas properties.

Upon the sale of an entire interest in an unproved property for cash or cash equivalents, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from the sale of partial interests in unproved oil and natural gas properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.

Impairment of Oil and Natural Gas Properties

The cost of proved oil and natural gas properties are assessed on a field-by-field basis for impairment at least annually or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The expected undiscounted future cash flows of the oil and natural gas properties are compared to the carrying amount of the oil, natural gas and NGL properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the carrying amount of the oil and natural gas properties is adjusted to estimated fair value. Assumptions associated with discounted cash flow models or valuations used in the impairment evaluation include estimates of

F-12

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

future oil, natural gas and NGL prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. Unproved oil and natural gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. See further discussion in Note 7 - Fair Value Measurements.

Business Combinations

In accordance with ASC 805 - Business Combinations, the Company accounts for its acquisitions that qualify as a business using the acquisition method. If the set of assets and activities acquired is not considered a business, it is accounted for as an asset acquisition using a cost accumulation model. In the cost accumulation model, the cost of the acquisition, including certain transaction costs, is allocated to the assets acquired on the basis of relative fair values.

The Company includes the results of operations of acquired businesses beginning on the respective acquisition dates. In accordance with the acquisition method, the Company allocates the purchase price of an acquired business to its identifiable assets and liabilities based on the estimated fair values. Transaction costs related to the business combination are expensed as incurred. This fair value measurement is based on unobservable (Level 3) inputs. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. The excess value of the net identifiable assets and liabilities acquired over the purchase price of an acquired business, if any, is recorded as a bargain purchase gain.

Other Property and Equipment, Net

Property and equipment are capitalized and recorded at cost, while maintenance and repairs are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 5 to 39 years. Capitalized costs related to leasehold improvements are depreciated over the life of the lease. As of December 31, 2022 and 2021, the Company had capitalized property and equipment costs of $5.3 million and $3.6 million, respectively, with $2.0 million and $1.7 million, respectively, of accumulated depreciation on the consolidated balance sheet. Components of other property and equipment consists of computer equipment, office furniture, tools and equipment, buildings and improvements, and vehicles.

Land purchases are accounted for at cost and are not depreciated. As of December 31, 2022 and 2021, the Company had capitalized land costs of $16.7 million and $1.3 million, respectively, on the consolidated balance sheet.

Deferred Financing Costs

Deferred financing costs include origination, arrangement, legal and other fees to issue or amend the terms of credit facility agreements. These deferred financing costs are reported as other non-current assets and recognized on the consolidated statement of operations as interest expense by amortizing the costs over the related financing using the straight-line method, which approximates the effective interest method.

Equity Issuance Costs

Equity issuance costs include underwriter, legal, accounting, printing and other fees to issue common equity securities. These issuance costs are netted against offering proceeds at the time of issuance and are reported as other non-current assets when related to the issuance of common equity securities. The issuance costs are expensed to the consolidated statement of operations if the issuance is unsuccessful.

F-13

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Other Non-Current Assets, Net

Other non-current assets consisted of the following:

	December 31, 2022		December 31, 2021
	(In thousands)
Deferred financing costs, net	$	2,556	$	1,345
Prepayments to outside operators	186		690
Right of use assets	1,370		208
Other deposits	63		50
Total other non-current assets, net	$	4,175	$	2,293

The Company incurred $1.9 million in financing costs related to the amendments of its revolving credit facility in April and October 2022. The Company extended certain existing leases and entered into a new lease during the year ended December 31, 2022, which resulted in additions to the right of use assets.

Accrued Liabilities

Accrued liabilities consisted of the following:

	December 31, 2022		December 31, 2021
	(In thousands)
Accrued capital expenditures	$	16,744	$	5,618
Accrued lease operating expenses	4,607		2,534
Accrued general and administrative costs	2,286		3,404
Accrued inventory	6,235		—
Accrued ad valorem tax	3,789		705
Other accrued expenditures	1,921		613
Total accrued liabilities	$	35,582	$	12,874

Asset Retirement Obligations

ARO consist of future plugging and abandonment expenses on oil and natural gas properties. The fair value of the ARO is recorded as a liability in the period in which wells are drilled with a corresponding increase in the carrying amount of oil and natural gas properties. The liability is accreted for the change in its present value each period and the capitalized cost is depreciated using the units-of-production method. The asset and liability are adjusted for changes resulting from revisions to the timing or the amount of the original estimate when deemed necessary. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

F-14

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Components of the changes in ARO consisted of the following and is shown below:

	December 31, 2022		December 31, 2021
	(In thousands)
ARO, beginning balance	$	2,453	$	2,434
Liabilities incurred	358		56
Revision of estimated obligations	326		—
Liability settlements and disposals	(178)		(58)
Accretion	79		21
ARO, ending balance	3,038		2,453
Less: current ARO(1)	(314)		(192)
ARO, long-term	$	2,724	$	2,261

_____________________

(1)Current ARO is included within other current liabilities on the accompanying consolidated balance sheets.

Goodwill

Goodwill represents the future economic benefit arising from other assets acquired in a business combination that are not individually identified or separately recognized. Goodwill is initially recognized as the excess of the purchase price of a business combination over the fair value of the net assets acquired and is tested for impairment annually in accordance with ASC 350 - Intangibles - Goodwill and Other, or more frequently if there is a change in events or circumstances that indicate the carrying value of the goodwill may not be recoverable.

The impairment test should occur at the reporting unit level determined by the Company and an impairment should only exist if the Company has determined the carrying value of the goodwill no longer exceeds the implied fair value. If the Company determines it is more likely than not the fair value of the reporting unit is less than its carrying value, including goodwill, then a quantitative assessment is necessary. An impairment loss is recognized if the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill.

At the closing of the Merger, the Company determined it had two reporting units, and the entire goodwill balance was included in the reporting unit acquired in the Merger (the "Kansas Reporting Unit"). The Company did not fully integrate the Kansas Reporting Unit in the Company's operations as it was deemed to be held for sale upon acquisition. The Company assessed the goodwill balance for impairment since the Company entered into a purchase and sale agreement ("PSA") in March 2021 for $3.5 million before closing adjustments. As the carrying value exceeded the implied fair value at the time of the closing of the Merger, the Company concluded the goodwill balance associated with the Kansas Reporting Unit was impaired and recognized a goodwill impairment loss, included within loss from discontinued operations on the consolidated statement of operations, of $18.5 million for the year ended September 30, 2021. See further discussion in Note 12 - Discontinued Operations and Assets Held for Sale.

Revenue Recognition

Oil Sales

Under the Company’s oil sales contracts, oil that is produced by the Company is delivered to the purchaser at a contractually agreed-upon delivery point at which point the purchaser takes custody, title and risk of loss of the product. Once control has been transferred, the purchaser transports the product to a third party and receives market-based prices from the third party. The Company receives a percentage of proceeds received by the purchaser less transportation costs in accordance with the pricing provisions in the Company's contracts. As transportation costs are incurred after the transfer of control, the costs are included in oil and natural gas sales and represent part of the transaction price of the contract. The pricing provisions also provide quantity requirements and grade and quality specifications. The Company recognizes revenue at the net price received when control transfers to the purchaser.

Natural Gas and NGL Sales

Under the Company’s natural gas gathering and processing contracts, natural gas is delivered to the purchaser at the inlet of the purchasers' gathering system, at which point title and risk of loss is transferred to the purchaser. The purchaser gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of natural gas and NGLs in accordance

F-15

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

with the pricing provisions of the Company's contracts. As the gathering, processing and transportation activities occur after the transfer of control, these costs are netted against our oil and natural gas sales and represent part of the transaction price of the contract, and may exceed the sales price. The pricing provisions also provide quantity requirements and grade and quality specifications. The Company recognizes revenue on a net basis for amounts expected to be received from third party customers through the marketing process.

Transaction Price Allocated to Remaining Performance Obligations

Based on the Company’s current product sales contracts, with contract terms ranging from one to ten years, each unit of production is considered a separate performance obligation and therefore future production volumes are wholly unsatisfied and do not require allocation or disclosure of the transaction price to remaining performance obligations.

Contract Balances

Under the Company’s product sales contracts, the Company has the right to invoice customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606.

Prior-Period Performance Obligations

Revenue is recorded in the month in which production is delivered to the purchaser. However, certain settlement statements for oil, natural gas and NGLs may not be received for thirty to ninety days after the date production is delivered and, as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences identified between the Company’s revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2022, the three months ended December 31, 2021, and year ended September 30, 2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Disaggregation of Revenue

The following table presents oil and natural gas sales disaggregated by product:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Oil and natural gas sales:
Oil	$	298,723	$	50,623	$	136,421
Natural gas	10,755		2,705		7,500
Natural gas liquids	9,865		3,322		4,715
Total oil and natural gas sales, net	$	319,343	$	56,650	$	148,636

Contract Services with Related Parties

The Company has contracts with related parties to provide certain contract operating, accounting and back-office support services. Revenue related to these contract services is recognized over time as the services are rendered, and the fee is stated within the contract at a fixed monthly rate. Costs directly attributable to performing these services are also recognized as the services are rendered. Refer to Note 8 - Transactions with Related Parties for a more detailed discussion regarding these contracts.

Revenue Payable

For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds that the Company has not yet distributed to other revenue and royalty owners are reflected as revenue payable in the consolidated balance sheets.

F-16

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Lease Operating Expenses

Lease operating costs, including payroll for field personnel, saltwater disposal, electricity, generator rentals, diesel fuel and other operating expenses, are expensed as incurred and included in lease operating expenses in our consolidated statements of operations.

Income Taxes

The Company uses the asset and liability method of accounting for income taxes, which requires the establishment of deferred tax accounts for all temporary differences between: (i) financial reporting and tax bases of assets and liabilities, using currently enacted federal and state income tax rates, and (ii) operating loss and tax credit carryforwards. In addition, deferred tax accounts must be adjusted to reflect new rates if enacted into law.

Realization of deferred tax assets is contingent on the generation of future taxable income. As a result, management considers whether it is more likely than not that all or a portion of such assets will be realized during periods when they are available, and if not, management provides a valuation allowance for amounts not likely to be recognized.

Management periodically evaluates tax reporting methods to determine if any uncertain tax positions exist that would require the establishment of a loss contingency. A loss contingency would be recognized if it were probable that a liability has been incurred as of the date of the financial statements and the amount of the loss can be reasonably estimated. The amount recognized is subject to estimates and management’s judgment with respect to the likely outcome of each uncertain tax position. The amount that is ultimately incurred for an individual uncertain tax position or for all uncertain tax positions in the aggregate could differ from the amount recognized. Interest and penalties, if any, related to uncertain tax positions are included in current income tax expense. There are no unrecorded liabilities for uncertain tax positions related to the Company as of December 31, 2022 and December 31, 2021. See further discussion in Note 11- Income Taxes.

Interest Expense

We have financed a portion of our working capital requirements, capital expenditures and certain acquisitions with borrowings under our revolving credit facility. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Interest expense in the consolidated statements of operations reflects interest less amounts allocated to capital expenditures, unused commitment fees paid to our lender, interest rate swap settlements plus the amortization of deferred financing costs (including origination and amendment fees). Interest expense was $1.1 million, $0.9 million, and $4.5 million for the year ended December 31, 2022, the three months ended December 31, 2021, and the year ended September 30, 2021, respectively.

Capitalized interest represents interest expense related to wells in process during the period in which the Company is incurring costs and expending resources to get the properties ready for their intended purpose. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful life of the asset in the same manner as the underlying asset.

Concentrations of Credit Risk

Our customer concentration may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry.

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, 2022, the three months ended December 31, 2021, and the year ended September 30, 2021, one purchaser accounted for 89%, 87%, and 87%, respectively, of our revenue purchased, with two end customers each accounting for more than 10% of the purchased revenue. During such periods, no other purchaser accounted for 10% or more of our revenues. The loss of this purchaser could materially and adversely affect our revenues in the short-term. However, the end customers include companies with lower credit risk. Further, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of any of our purchasers would not have a long-term material adverse effect on our financial condition and results of operations because oil, natural gas and NGLs are marketable products with well-established markets.

We manage credit risk related to accounts receivable through credit approvals, escrow accounts and monitoring procedures. Accounts receivable are generally not collateralized. However, we routinely assess the financial strength of our customers and, based upon factors surrounding the credit risk, establish an allowance for uncollectible accounts, if required. As a result, we believe that our accounts receivable credit risk exposure beyond such allowance is limited.

F-17

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Environmental and Other Issues

We are engaged in oil and natural gas exploration and production and may become subject to certain liabilities as they relate to environmental cleanup of well sites or other environmental restoration procedures. In connection with our acquisition of existing or previously drilled well bores, we may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental cleanup or restoration, we would be responsible for curing such a violation.

We account for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated.

Fair Value Measurements

Certain financial instruments are reported at fair value on our consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost). These approaches are considered Level 3 in the fair value hierarchy.

The carrying values of financial instruments comprising cash and cash equivalents, payables, receivables, related party accounts receivable/payable and advances from joint interest owners approximate fair values due to the short-term maturities of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value reported for the revolving credit facility approximates fair value because the underlying instruments are at interest rates which approximate current market rates and is considered Level 3 in the fair value hierarchy. Assets and liabilities accounted for at fair value on a non-recurring basis in accordance with the fair value hierarchy include the initial recognition of asset retirement obligations, the fair value of oil and natural gas properties, and goodwill when acquired in a business combination or assessed for impairment and are considered Level 3 in the fair value hierarchy.

Derivative Contracts

We report the fair value of derivatives on the consolidated balance sheets in derivative assets and derivative liabilities as either current or non-current based on the timing of the settlement of individual trades. Trades that are scheduled to settle in the next twelve months are reported as current. The Company nets derivative assets and liabilities, in the consolidated balance sheets, whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract.

For the year ended December 31, 2022, the three months ended December 31, 2021, and year ended September 30, 2021, we have not designated our derivative contracts as hedges for accounting purposes, and therefore changes in the fair value of derivatives are recognized in earnings. Cash settlements of contracts are included in cash flows from operating activities in the consolidated statement of cash flows. Derivative contracts are settled on a monthly basis.

The fair value of the derivatives is established using index prices, volatility curves and discount factors. The value we report in our consolidated financial statements is as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors.

The use of derivatives involves the risk that the counterparties to such contracts will be unable to meet their obligations under the terms of the agreement. To minimize the credit risk with derivative instruments, it is our policy to enter into derivative contracts primarily with counterparties that are financial institutions that are also lenders within our revolving credit facility. Under the terms of the current counterparties' contracts, only those that are lenders under our revolving credit facility

F-18

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

are secured by the same collateral as outlined in our revolving credit facility. The counterparties are not required to provide credit support to the Company. See further discussion in Note 6 – Derivative Instruments.

Leases

The Company's current leases include office space and information technology equipment, comprised primarily of printers and copiers. The Company reviews all contracts to determine if a lease exists at contract inception. A lease exists when the Company has the right to obtain substantially all of the economic benefit of a specific asset and to control the use of that asset over the term of the agreement. Identified leases are classified as an operating or finance lease, which determines the recognition, measurement and presentation of expenses. As of December 31, 2022, the Company did not have any finance leases. Operating leases are capitalized on the consolidated balance sheet at commencement through a lease right-of-use ("ROU") asset and lease liability representing the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset includes any lease payments made to the lessor prior to lease commencement less any lease incentives and initial direct costs incurred. Options to extend or terminate leases are included in the lease term when it is reasonably certain the Company will exercise the option. For operating leases, lease costs are recognized on a straight-line basis over the term of the lease.

The present value of operating lease payments and amortization of the lease liability is calculated using a discount rate. When available, the Company uses the rate implicit in the lease as the discount rate; however, most of the Company’s leases do not provide a readily determinable implicit rate. In such cases, the Company is required to use its incremental borrowing rate ("IBR"). The Company’s IBR reflects the estimated rate of interest that the Company would pay to borrow on a collateralized basis over a similar term and amount equal to the lease payments in a similar economic environment. The Company is required to reassess the discount rate for any new and modified lease contracts as of the lease effective date. The weighted-average discount rate was 3.18% and 5.17%, respectively, at December 31, 2022 and 2021. The weighted average remaining lease term was 2.4 years and 0.5 years, respectively, at December 31, 2022 and 2021. Lease expense was $0.5 million, $0.1 million, and $0.4 million, respectively, for the year ended December 31, 2022, the three months ended December 31, 2021, and year ended September 30, 2021.

	December 31, 2022		December 31, 2021
	(In thousands)
ROU asset	$	1,370	$	208
Current lease liability	$	539	$	212
Long-term lease liability	$	838	$	—

The ROU asset and current lease liability was included in other non-current assets and other current liabilities and non-current lease liabilities, respectively, on the accompanying consolidated balance sheets. Lease expense for the Company was included in general and administrative costs on the accompanying consolidated statements of operations.

Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements

In December 2019, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2019-12, "Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes." This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance and is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company adopted this ASU effective October 1, 2021. The adoption of this ASU did not have a material impact on the Company's consolidated financial statements.

In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (“ASU 2020-04”), which provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates (e.g., London Interbank Offered Rate ("LIBOR")) that are expected to be discontinued. ASU 2020-04 allows, among other things, certain contract modifications, such as those within the scope of Topic 470 on debt, to be accounted for as a continuation of the existing contract. The Company adopted this ASU effective concurrent with the amendment of the Company's revolving credit facility in April 2022. See Note 9 - Revolving Credit Facility for additional information on the amendment of the revolving credit facility. The adoption of this ASU did not have a material impact on the Company's consolidated financial statements.

F-19

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(4)Acquisitions

Business Combination Between REP LLC and Tengasco

Immediately prior to the closing of the Merger on February 26, 2021, REP LLC converted all of its issued and outstanding Series A Preferred Units into common units of REP LLC. In connection with the Merger, holders of common units of REP LLC were entitled to receive, in exchange for each common unit, shares of common stock of Tengasco (which was renamed Riley Exploration Permian, Inc.), par value $0.001 per share (“Tengasco common stock”) based on the exchange ratio set forth in the Merger Agreement (the “Exchange Ratio”), with cash paid in lieu of the issuance of any fractional shares. The Exchange Ratio was 97.796467 shares of Tengasco common stock for each common unit of REP LLC (as adjusted for the reverse stock split). Immediately prior to the closing of the Merger, Tengasco effected a one-for-twelve reverse stock split resulting in outstanding common stock of approximately 17.8 million shares including shares of Tengasco common stock issued in the Merger.

The combination between REP LLC and Tengasco qualified as a business combination with REP LLC being treated as the accounting acquirer. The assets acquired and liabilities assumed were recognized on the consolidated balance sheet at fair value as of the acquisition date.

The consideration paid in the Merger by REP LLC as the accounting acquirer totaled approximately $26.4 million and was determined based on the closing price of Tengasco’s common stock on February 26, 2021 and the total number of shares outstanding immediately prior to the Merger. The Merger was structured as a tax-free reorganization for United States federal income tax purposes.

The following table summarizes the consideration for the Merger (presented in thousands, except stock price):

Tengasco common stock price	$	29.64
Tengasco common stock - issued and outstanding as of February 26, 2021	891
Total consideration	$	26,392

The Company incurred approximately $5.0 million of related costs for the Merger, of which $3.6 million was expensed for the year ended September 30, 2021 as transaction costs on the consolidated statements of operations.

F-20

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The Company completed the determination of the fair value attributable to the assets acquired and liabilities assumed as of September 30, 2021. The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed based on their fair values on February 26, 2021 (in thousands):

Assets
Cash and cash equivalents	$	860
Accounts receivable	325
Prepaid and other current assets	759
Total current assets	1,944
Oil and gas properties	4,525
Other property and equipment	91
Right of use assets	42
Other non-current assets	4
Deferred tax assets	2,987
Total assets acquired	$	9,593
Liabilities
Accounts payable	$	130
Accrued liabilities	409
Current lease liabilities, operating	42
Current lease liabilities, financing	68
Total current liabilities	649
Asset retirement obligations	1,565
Total liabilities assumed	2,214
Net identifiable assets acquired	7,379
Goodwill	19,013
Net assets acquired	$	26,392

The goodwill recognized was primarily attributable to a substantial increase in the stock price of Tengasco on the Closing Date, which increased the amount of the consideration transferred. The Company does not expect goodwill to be deductible for tax purposes.

Pro Forma Operating Results (Unaudited)

The following unaudited pro forma combined results for the year ended September 30, 2021 reflect the consolidated results of operations of the Company as if the Merger had occurred on October 1, 2019. Subsequent to the Merger, the Company changed its fiscal year period from October 1st through September 30th each year to January 1st to December 31st each year commencing with the 2022 calendar year. The unaudited pro forma information includes adjustments for $3.6 million of transaction costs being reclassified to the fourth quarter of calendar year 2019 which were incurred during the year ended September 30, 2021. Additionally, the Company adjusted for $0.9 million of oil and natural gas property impairment that Tengasco recognized under the full-cost method of accounting, which would not have been recognized under the successful efforts method, during the three months ended December 31, 2020. Also, the unaudited pro forma information has been tax

F-21

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

effected using a 21% tax rate. The common stock was also adjusted for the conversion of the REP LLC preferred units into common units and retroactively adjusted for the Exchange Ratio and one-for-twelve reverse stock split.

	For the year ended September 30, 2021
	(In thousands, except per share/unit amounts)
	(Unaudited)
Total Revenues	$	151,036
Pro Forma Net Loss before Taxes	(29,871)
Pro forma income tax benefit	6,273
Pro Forma Net Loss	$	(23,598)
Net Loss per Share/Unit from Continuing Operations:
Basic	$	(1.88)
Diluted	$	(1.88)
Net Income per Share/Unit from Discontinued Operations:
Basic	$	0.02
Diluted	$	0.02

The unaudited pro forma combined financial information is for informational purposes only and was based off of the fiscal year period October 1st through September 30th as this was the fiscal year in effect at the time of the Merger. The unaudited pro forma financial information was not modified for the change in the Company's fiscal year. It is not intended to represent or to be indicative of the combined results of operations that the Company would have reported had the Merger been completed as of October 1, 2019 and should not be taken as indicative of the Company's future combined results of operations. The actual results may differ significantly from that reflected in the unaudited pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the unaudited pro forma combined financial information and actual results.

Divestitures

On April 2, 2021, the Company closed on the sale of the Kansas Reporting Unit for an agreed upon purchase price of $3.5 million, less approximately $0.2 million of closing adjustments. See further discussion in Note 12 - Discontinued Operations and Assets Held for Sale.

Transaction Costs

Transaction costs consist of those costs associated with investment banking, accounting, legal and other diligence costs related to unsuccessful acquisitions or successful acquisitions accounted for as business combinations. The Company recognized transaction costs for the periods presented below:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Business combination acquisition costs	$	2,638	$	1,258	$	3,572
Other	—		—		160
Total transaction costs	$	2,638	$	1,258	$	3,732

The transaction costs of $2.6 million and $1.3 million for the year ended December 31, 2022 and three months ended December 31, 2021, respectively, primarily related to a potential business combination and related financing that the Company pursued but ultimately chose not to consummate. During the year ended September 30, 2021, the transaction costs of $3.6 million primarily relate to costs incurred on the Merger with Tengasco in February 2021.

F-22

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(5)Oil and Natural Gas Properties

Oil and natural gas properties are summarized below:

	December 31, 2022		December 31, 2021
	(In thousands)
Proved	$	516,011	$	421,779
Unproved	12,770		18,839
Work-in-progress	45,169		13,534
	573,950		454,152
Accumulated depletion, amortization and impairment	(133,848)		(95,021)
Total oil and natural gas properties, net	$	440,102	$	359,131

At December 31, 2022 and 2021, the Company had one exploratory well drilled but uncompleted that was included in work-in-progress with associated well costs of $3.8 million and $3.7 million, respectively. At December 31, 2022, the Company had one exploratory well with costs of $3.8 million that has been capitalized for greater than two years. The Company is in the process of evaluating completion methods for this exploratory well.

Depletion and amortization expense for proved oil and natural gas properties was $31.5 million for the year ended December 31, 2022, $6.7 million for the three months ended December 31, 2021, and $25.2 million for the year ended September 30, 2021.

Exploration expense was $2.0 million for the year ended December 31, 2022, $0.6 million for the three months ended December 31, 2021, and $9.6 million for the year ended September 30, 2021. Exploration expense was primarily attributable to the expiration of oil and natural gas leases for the year ended December 31, 2022, the three months ended December 31, 2021 and year ended September 30, 2021.

Impairment of Proved Properties

Certain proved oil and natural gas properties were impaired during year ended December 31, 2022. Our impairment test involved a Step 1 assessment to determine if the net book value of our proved oil and natural gas properties is expected to be recovered from the estimated undiscounted future net cash flows. We calculated the expected undiscounted future net cash flows of our long-lived assets using management’s assumptions and expectations. See further discussion in Note 7 - Fair Value Measurements.

Certain oil and natural gas properties in our New Mexico operating area failed the Step 1 assessment. For these assets, we used a discounted cash flow analysis to estimate fair value. The expected future net cash flows were discounted using a rate of 10.25%, which we believe represents the estimated weighted average cost of capital of a market participant. Based on Step 2 of our long-lived assets impairment test, we recognized a $7.3 million impairment because the carrying value exceeded the estimated fair market value as of the year ended December 31, 2022. See further discussion of our fair value assumptions in Note 7 - Fair Value Measurements.

(6)Derivative Instruments

Oil and Natural Gas Contracts

The Company uses commodity based derivative contracts to reduce exposure to fluctuations in oil and natural gas prices. While the use of these contracts limits the downside risk for adverse price changes, their use also limits future revenues from favorable price changes. We have not designated our derivative contracts as hedges for accounting purposes, and therefore changes in the fair value of derivatives are included and recognized in other income (expense) in the consolidated statement of operations.

As of December 31, 2022, the Company's oil and natural gas derivative instruments consisted of the following types:

•Fixed Price Swaps – the Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

F-23

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

•Costless collars – the combination of a put option (fixed floor) and call option (fixed ceiling), with the options structured so that the premium paid to purchase the put option is offset by the premium received from the sale of the call option. If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the put and the call strike price, no payments are due from either party.

•Basis Protection Swaps – basis swaps are settled based on differences between a fixed price differential and the differential between the settlement prices of two referenced indexes. We receive the fixed price differential and pay the differential between the referenced indexes.

The following table summarizes the open financial derivative positions as of December 31, 2022, related to oil and natural gas production:

		Weighted Average Price
Calendar Quarter / Year	Notional Volume	Fixed		Put		Call
		($ per unit)
Oil Swaps (Bbl)
Q1 2023	225,000	$	53.65	$	—	$	—
Q2 2023	195,000	$	53.89	$	—	$	—
Q3 2023	126,000	$	53.79	$	—	$	—
Q4 2023	114,000	$	54.59	$	—	$	—
Oil Collars (Bbl)
Q1 2023	30,000	$	—	$	60.00	$	109.60
Q2 2023	30,000	$	—	$	60.00	$	109.60
Q3 2023	—	$	—	$	—	$	—
Q4 2023	—	$	—	$	—	$	—
2024	3,000	$	—	$	50.00	$	88.00

The Company entered into additional derivative contracts subsequent to December 31, 2022. See further discussion in Note 15 - Subsequent Events.

Interest Rate Contracts

During the years ended December 31, 2022 and 2021, the Company entered into floating-to-fixed interest rate swaps, in which it received a floating market rate equal to one-month LIBOR or Secured Overnight Financing Rate ("SOFR") and paid a fixed interest rate, to manage interest rate exposure related to the Company's revolving credit facility. In December 2022, the Company settled the remaining open positions for the interest rate swap which resulted in a $1.5 million settlement. The Company recognizes settlements on interest rate swaps in interest expense on the consolidated statements of operations.

F-24

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Balance Sheet Presentation of Derivatives    

The following tables present the location and fair value of the Company’s derivative contracts included in the consolidated balance sheets as of December 31, 2022 and 2021:

	December 31, 2022
Balance Sheet Classification	Gross Fair Value		Amounts Netted		Net Fair Value
	(In thousands)
Current derivative assets	$	64	$	(44)	$	20
Non-current derivative assets	9		(9)		—
Current derivative liabilities	(16,516)		44		(16,472)
Non-current derivative liabilities	(21)		9		(12)
Total	$	(16,464)	$	—	$	(16,464)
	December 31, 2021
Balance Sheet Classification	Gross Fair Value		Amounts Netted		Net Fair Value
	(In thousands)
Current derivative assets	$	281	$	(198)	$	83
Non-current derivative assets	267		—		267
Current derivative liabilities	(31,182)		198		(30,984)
Non-current derivative liabilities	(9,515)		—		(9,515)
Total	$	(40,149)	$	—	$	(40,149)

The following table presents the components of the Company's gain (loss) on derivatives for the periods presented below:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Settlements on derivative contracts(1)	$	(75,257)	$	(16,014)	$	(16,304)
Non-cash gain (loss) on derivatives	23,683		10,821		(72,891)
Loss on derivatives	$	(51,574)	$	(5,193)	$	(89,195)

_____________________________________________________

(1) In December 2022, the Company settled a portion of its 2023 open oil fixed price swap contracts which resulted in a $1.5 million settlement.

(7)Fair Value Measurements

The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.

The carrying values of financial instruments comprising cash and cash equivalents, payables, receivables, and advances from joint interest owners approximate fair values due to the short-term maturities of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value reported for the revolving credit facility approximates fair value because the underlying instruments are at interest rates which approximate current market rates. The revolving line of credit is considered Level 3 in the fair value hierarchy.

Assets and Liabilities Measured on a Recurring Basis

The fair value of commodity derivatives and interest rate swaps is estimated using discounted cash flow calculations based upon forward curves and are classified as Level 2 in the fair value hierarchy. The following table presents the Company’s

F-25

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2022 and 2021, by level within the fair value hierarchy:

	December 31, 2022
	Level 1		Level 2		Level 3		Total
	(In thousands)
Financial assets:
Commodity derivative assets	$	—	$	73	$	—	$	73
Financial liabilities:
Commodity derivative liabilities	$	—	$	(16,537)	$	—	$	(16,537)
	December 31, 2021
	Level 1		Level 2		Level 3		Total
	(In thousands)
Financial assets:
Commodity derivative assets	$	—	$	187	$	—	$	187
Interest rate assets	$	—	$	361	$	—	$	361
Financial liabilities:
Commodity derivative liabilities	$	—	$	(40,687)	$	—	$	(40,687)
Interest rate liabilities	$	—	$	(10)	$	—	$	(10)

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

Assets and liabilities accounted for at fair value on a non-recurring basis in accordance with the fair value hierarchy include the initial recognition of asset retirement obligations, the fair value of oil and natural gas properties, and goodwill when acquired in a business combination or assessed for impairment.

The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future commodity prices; (iii) operating and development costs; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that the Company’s management believes will impact realizable prices. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation.

The fair value of asset retirement obligations incurred and acquired during the year ended December 31, 2022 and the three months ended December 31, 2021, totaled approximately $0.4 million and $0.1 million, respectively. The fair value of additions to the asset retirement obligation liabilities is measured using valuation techniques consistent with the income approach, which converts future cash flows to a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well for all oil and natural gas wells and for all disposal wells; (ii) estimated remaining life per well; (iii) future inflation factors; and (iv) our average credit-adjusted risk-free rate. These assumptions represent Level 3 inputs.

If the carrying amount of our oil and natural gas properties exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The fair value of our oil and natural gas properties is determined using valuation techniques consistent with the income and market approach. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with the expected cash flow projected. These assumptions represent Level 3 inputs.

F-26

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(8)Transactions with Related Parties

Contract Services

RPOC provides certain administrative services to Combo Resources, LLC ("Combo") and is also the contract operator on behalf of Combo in exchange for a monthly fee of $100 thousand and reimbursement of all third party expenses pursuant to a contract services agreement. Additionally, RPOC provides certain administrative and operational services to Riley Exploration Group, LLC ("REG") in exchange for a monthly fee of $100 thousand pursuant to a contract services agreement. Combo and REG are portfolio companies of Yorktown Energy Partners XI, L.P. ("Yorktown XI"), certain managed funds of which have investments in the Company (all deemed to be related parties). One of our executives held positions with REG and Combo at December 31, 2022. Our Executive Vice President, Business Intelligence is the President of both REG and Combo, as well as a board member of Combo.

The following table presents revenues from and related cost for contract services for related parties:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Combo	$	1,200	$	300	$	1,200
REG	1,200		300		1,200
Contract services - related parties	$	2,400	$	600	$	2,400
Cost of contract services	$	450	$	150	$	477

The Company had amounts payable to Combo of $0.4 million and $0.2 million at December 31, 2022 and 2021, respectively, which are reflected in accounts payable - related parties on the accompanying consolidated balance sheets. Amounts due to Combo reflect the revenue, net of any expenditures for wells and fees due under the contract services agreement, for Combo's net working interest in wells that the Company operates on Combo's behalf.

Consulting and Legal Fees

The Company has an engagement agreement with di Santo Law PLLC ("di Santo Law"), a law firm owned by Beth di Santo, a member of our Board of Directors, pursuant to which di Santo Law's attorneys provide legal services to the Company. For the year ended December 31, 2022, the three months ended December 31, 2021, and year ended September 30, 2021, the Company incurred legal fees from di Santo Law of approximately $0.7 million, $0.2 million, and $1.0 million, respectively. As of December 31, 2022 there are no accrued amounts for di Santo Law. As of December 31, 2021, the Company had approximately $0.2 million in amounts accrued for di Santo Law, which was included in accrued liabilities in the accompanying consolidated balance sheets.

(9)Revolving Credit Facility

On September 28, 2017, REP LLC entered into a credit agreement (the "Credit Agreement") to establish a senior secured revolving credit facility with a syndicate of banks including SunTrust Bank, now Truist Bank as successor by merger, as administrative agent. The revolving credit facility had an initial borrowing base of $25 million with a maximum facility amount of $500 million. In both April and October 2022, the Company amended its Credit Agreement to, among other things, increase the borrowing base to $225 million. The Credit Agreement is set to mature in April 2026. Substantially all of the Company’s assets are pledged to secure the revolving credit facility.

The borrowing base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. During these redetermination periods, the Company’s borrowing base may be increased or may be reduced in certain circumstances. The revolving credit facility allows for SOFR Loans and Base Rate Loans (each as defined in the Credit Agreement). The interest rate on each SOFR Loan will be the adjusted Term SOFR for the applicable interest period plus a margin between 2.75% and 3.75% (depending on the borrowing base utilization percentage). The annual interest rate on each Base Rate Loan will be the Base Rate for the applicable interest period plus a margin between 1.75% and 2.75% (depending on the borrowing base utilization percentage). The Company is also subject to an unused commitment fee of between 0.375% and 0.500% (depending on the borrowing base utilization percentage).

F-27

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The Credit Agreement contains certain covenants, which, among other things, require the maintenance of (i) a total leverage ratio of not more than 3.25 to 1.0 and (ii) a minimum current ratio of not less than 1.0 to 1.0 as of the last day of any quarter. The Credit Agreement also contains a total leverage ratio for Restricted Payments, as defined in the Credit Agreement, after giving pro forma effect to such Restricted Payments, which includes payments to any holder of the Company's shares, would not exceed 2.50 to 1.0. If the Company's leverage ratio, after giving pro forma effect to such Restricted Payments (as defined in the Credit Agreement), is above 2.0 to 1.0, then an additional test of free cash flow is applied, and the Company will only be permitted to make such Restricted Payments if such payment does not exceed the Company's free cash flow. The Company is also required to limit its cash balance to less than $15 million or 10% of the borrowing base, whichever is greater. If the Company's cash balance exceeds this limit on the last business day of the month, the Company will be required to apply the excess to reduce its credit facility borrowings. The Credit Agreement also contains other customary affirmative and negative covenants and events of default. The Company's minimum hedging requirement is between 0% and 50% (depending on the borrowing base utilization percentage and leverage ratio as of the hedge evaluation date) of its proved developed producing ("PDP") volumes on a rolling 24-month basis. As of December 31, 2022, the Company's minimum hedging requirement was 0%.

The following table summarizes the Company's interest expense:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Interest expense(1)	$	864	$	512	$	3,686
Capitalized interest	(1,022)		$	—	—
Amortization of deferred financing costs	731		282		653
Unused commitment fees	517		102		195
Total interest expense, net	$	1,090	$	896	$	4,534

_____________________

(1)In December 2022, the Company settled the remaining open positions for the interest rate swap which resulted in a $1.5 million settlement. The Company recognizes settlements on its interest rate swaps in interest expense on the consolidated statements of operations.

As of December 31, 2022 and 2021, the weighted average interest rate on outstanding borrowings under the revolving credit facility was 7.17% and 3.10%, respectively.

As of December 31, 2022 and 2021, the Company was in compliance with all covenants contained in the Credit Agreement and had $56 million and $65 million, respectively, of outstanding borrowings and $169 million and $110 million, respectively, available under the borrowing base.

(10) Members’/Shareholders' Equity

Public Offering of Common Stock

On June 30, 2021, the Company entered into an Underwriting Agreement (the "Underwriting Agreement") with Truist Securities, Inc., as the representative of the other several underwriters named in the Underwriting Agreement. On July 2, 2021, the Company issued 1,666,667 shares of common stock at a price to the public of $30.00 per share in accordance with the Underwriting Agreement. Net proceeds from the issuance were approximately $46.7 million, after deducting the underwriting fees and other offering costs incurred.

Dividends

Cash dividends for the periods presented were declared for all issued and outstanding common shares or units, including vested and unvested under the respective Long-Term Incentive Plan in effect during the period of dividend declaration. The portion of the cash attributable to the unvested restricted shares issued under the 2021 Long-Term Incentive Plan ("2021 LTIP") is included in accrued liabilities on the consolidated balance sheet and will be paid in cash once the unvested restricted shares fully vest. Any accrued but unpaid cash dividends attributable to the unvested restricted shares issued under the 2018 Long-Term Incentive Plan ("2018 LTIP") was paid in accordance with the Merger Agreement immediately prior to consummation of the Merger. See Note 9 - Revolving Credit Facility for discussion over the Company's restrictions on certain payments, including dividends.

F-28

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The table below summarizes the following cash distributions declared to common shareholders and unitholders during the periods presented below:

Quarter Ended	Per Share/Unit Distribution(1)		Total Distribution
			(In millions)
2022
December 31, 2022	$	0.34	$	6.7
September 30, 2022	$	0.31	$	6.2
June 30, 2022	$	0.31	$	6.2
March 31, 2022	$	0.31	$	6.2
2021
December 31, 2021	$	0.31	$	6.2
September 30, 2021	$	0.28	$	5.5
June 30, 2021	$	—	$	—
March 31, 2021(2)	$	0.29	$	8.8
2020
December 31, 2020	$	0.30	$	3.8

_____________________

(1)Per unit amounts for dividends declared before the Closing Date of the Merger have been effected by giving adjustment to the 1-for-12 reverse stock split and exchange ratio of 97.796467.

(2)On February 4, 2021, the Board of Managers of REP LLC declared a $3.8 million cash dividend, paid on February 5, 2021. On March 4, 2021, the Board of Directors of the Company declared a cash dividend of $0.28 per share or $5.0 million total, paid on May 7, 2021.

Share-Based and Unit-Based Compensation

In connection with the Merger, the Company shareholders adopted an omnibus equity incentive plan, the 2021 LTIP, for the employees, consultants and the directors of the Company and its affiliates who perform services for the Company. The holders of unvested restricted units issued under the 2018 LTIP were issued substitute awards under the 2021 LTIP at the closing of the Merger. Upon the closing of the Merger and after giving effect to the adjustment resulting from the one-for-twelve reverse stock split, the 2021 LTIP had 1,387,022 shares of common stock available for issuance, of which 440,784 shares remained available as of December 31, 2022.

2021 Long-Term Incentive Plan

The 2021 LTIP will provide for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws ("ISO's:); (ii) stock options that do not qualify as incentive stock options; (iii) stock appreciation rights, or SARs; (iv) restricted stock awards; (v) restricted stock units, or RSUs; (vi) stock awards; (vii) performance awards; (viii) dividend equivalents; (ix) other stock-based awards; (x) cash awards; and (xi) substitute awards, all of which will collectively be referred to as the "Awards".

The 2021 LTIP authorizes the Compensation Committee to administer the plan and designate eligible persons as participants, determine the type or types of Awards to be granted to an eligible person, determine the number of shares of stock or amount of cash to be covered by the Awards, approve the forms of award agreements for use under the plan, determine the terms and conditions of any Award, modify, waive or adjust any term or condition of an Award that has been granted, among other responsibilities delegated by the Company's Board.

Restricted Shares: The Company granted 367,420, 174,575, and 397,739 restricted shares to executives, employees and independent directors of the Company during the year ended December 31, 2022, three months ended December 31, 2021, and year ended September 30, 2021, respectively. The holder of these restricted shares receive dividends, in arrears, once the shares vest. The Company has accrued for these dividends which are reported in accrued liabilities and other non-current liabilities.

F-29

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

All restricted shares granted have a service period between 3 and 36 months. The Company estimates the fair values of the restricted shares as the closing price of the Company's common stock on the grant date of the award, with the expense amortized on a straight-line basis and recognized over the vesting period.

The following table presents the Company's restricted stock activity during the year ended December 31, 2022 under the 2021 LTIP:

2021 Long-Term Incentive Plan
	Restricted Shares	Weighted Average Grant Date Fair Value(1)
Unvested at December 31, 2021	366,789	$	19.41
Granted	367,420	$	17.63
Vested	(192,899)	$	19.25
Forfeited	(5,101)	$	23.46
Unvested at December 31, 2022	536,209	$	18.39

_____________________________________________________

(1) For the three months ended December 31, 2021, the Company granted 174,575 restricted shares at a weighted average grant date fair value of $23.46. For the year ended September 30, 2021, the Company granted 397,739 restricted shares at a weighted average grant date fair value of $21.16.

For the year ended December 31, 2022, the three months ended December 31, 2021, and year ended September 30, 2021, the total equity-based compensation expense is $3.9 million, $0.9 million, and $6.1 million, respectively, for all periods and is included in general and administrative costs on the Company's consolidated statement of operations for the restricted share awards granted under the 2021 LTIP. At the time of the forfeiture, the Company will recognize any forfeited shares as a reduction to share-based compensation expense on the consolidated statement of operations and a decrease to shareholders' equity on the consolidated balance sheet. Any unpaid dividends on forfeited shares will be recognized as a decrease to accrued liabilities and an increase to shareholders' equity on the consolidated balance sheet. Approximately $8.3 million of additional equity-based compensation expense will be recognized over the weighted average life of 28 months for the unvested restricted share awards as of December 31, 2022 granted under the 2021 LTIP.

2018 Long-Term Incentive Plan

In connection with the Merger and in accordance with the Merger Agreement, each unvested restricted unit outstanding under the 2018 LTIP was converted into restricted shares of the Company under the 2021 LTIP. The holders of unvested restricted units issued under the 2018 LTIP were issued substitute awards under the 2021 LTIP at the closing of the Merger.

The Company granted 13,309 restricted units to executives and employees of the Company during the year ended September 30, 2021. Total unit-based compensation expense of $0.7 million is for all of the issuances outstanding during the period of January 2021 through the date of the merger, February 26, 2021. Unit-based compensation expense is included in general and administrative costs on the Company's consolidated statement of operations.

(11)Income Taxes

REP LLC was organized as a limited liability company and treated as a flow-through entity for federal income tax purposes. As such, taxable income and any related tax credits were passed through to its members and included in their tax returns, even though such taxable income or tax credits may not have been distributed. In connection with the closing of the Merger, the Company's tax status changed from a limited liability company to a C-corporation. As a result, the Company is responsible for federal and state income taxes and must record deferred tax assets and liabilities for the tax effects of any temporary differences that exist on the date of the change. When push down accounting does not apply as part of a business combination, U.S. GAAP requires the effect of the change in tax status to be recognized in the financial statements and the effect is included in income (loss) from continuing operations. Upon consummation of the Merger, the Company established a $13.6 million provision for deferred income taxes with the conversion to a C-corporation. Accordingly, a provision for federal

F-30

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

and state corporate income taxes has been made for the operations of REP LLC only from February 27, 2021 through December 31, 2022 in the accompanying consolidated financial statements.

The components of the Company's consolidated provision for income taxes from continuing operations are as follows:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Current income tax expense:
Federal	$	4,026	$	—	$	2
State	446		113		52
Total current income tax expense	$	4,472	$	113	$	54
Deferred income tax expense (benefit):
Federal	$	27,393	$	5,669	$	14,202
State	979		87		(1,240)
Total deferred income tax expense (benefit)	$	28,372	$	5,756	$	12,962
Total income tax expense (benefit)	$	32,844	$	5,869	$	13,016

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company's net deferred tax position is as follows:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Deferred tax assets
Non-cash gain on derivatives	$	3,563	$	10,286	$	11,006
Intangibles	182		215		222
Inventory	—		23		23
Share-based compensation	421		690		480
Accruals and other	484		558		578
Net operating loss	2,812		3,172		5,422
Total deferred tax assets	7,462		14,944		17,731
Oil and natural gas assets	(52,665)		(32,154)		(29,161)
Other fixed assets	(553)		(174)		(198)
Total deferred tax liabilities	(53,218)		(32,328)		(29,359)
Net deferred tax liabilities	$	(45,756)	$	(17,384)	$	(11,628)

F-31

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

A reconciliation of the statutory federal income tax rate to the Company's effective income tax rate is as follows:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
Tax at statutory rate	21.0	%	21.0	%	21.0	%
Nondeductible compensation	0.2	%	0.1	%	(1.0)	%
Transaction costs	—	%	—	%	(1.5)	%
Share-based compensation	—	%	(0.3)	%	(0.1)	%
State income taxes, net of federal benefit	0.7	%	0.7	%	0.4	%
Change in tax status	—	%	—	%	(40.1)	%
Income subject to taxation by REP LLC's unitholders	—	%	—	%	(17.1)	%
Other	(0.2)	%	—	%	—	%
Effective income tax rate	21.7	%	21.5	%	(38.4)	%

The Company's federal income tax returns for the years subsequent to December 31, 2018 remain subject to examination. The Company's income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2017. The Company currently believes that all other significant filing positions are highly certain and that all of its other significant income tax positions and deductions would be sustained under audit or the final resolution would not have a material effect on the consolidated financial statements. Therefore, the Company has not established any significant reserves for uncertain tax positions.

Section 382 of the Internal Revenue Code limits the utilization of U.S. net operating loss ("NOL") carryforwards following a change in control. The Merger caused a stock ownership change for purposes of Section 382 which is subject to an approximate annual limit. The Company has federal net operating losses subject to the annual Section 382 limit of $13.4 million of which $4.6 million will expire beginning in 2022 with the remaining $8.8 million of the NOL's not expiring. Additionally, the Company has no federal net operating losses generated after the Merger that are not limited by Section 382 and are not subject to expiration. We believe it is more likely than not the tax benefit of these net operating losses will be fully realized, as such no valuation allowance has been recorded. The deferred tax assets for the net operating losses are presented net with deferred tax liabilities, which primarily consist of book and tax depreciation differences.

(12)Discontinued Operations and Assets Held For Sale

Kansas Reporting Unit

On March 10, 2021, the Company entered into a PSA to divest of the Kansas Reporting Unit for an agreed upon purchase price of $3.5 million before certain closing adjustments. In addition, the Company also agreed to assign to the buyer its lease associated with Tengasco's former corporate office in Greenwood Village, Colorado. With Tengasco qualifying as a business and the Kansas Reporting Unit making up a significant portion of the assets of Tengasco, the Company concluded that the transaction met the requirements of assets held for sale and discontinued operations upon the acquisition date. The sale closed on April 2, 2021 for an adjusted purchase price of $3.3 million, after customary closing adjustments.

F-32

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The following table presents the components of the loss on discontinued operations reported in the consolidated statements of operations for the periods ended September 30, 2021:

		Year Ended
		September 30, 2021
	(In thousands)
Oil and natural gas sales		$	—
Total revenues		—
Lease operating expenses		115
Goodwill impairment		18,516
Total expenses		18,631
Other expenses		(107)
Loss from discontinued operations before income taxes		(18,738)
Income tax expense		(59)
Loss from discontinued operations, net of tax		$	(18,797)

The Company did not have any discontinued operations during the year ended December 31, 2022.

(13)Net Income (Loss) Per Share/Unit

Net income (loss) per share/unit is calculated using a retroactive application of the Exchange Ratio and the one-for-twelve reverse stock split that occurred in conjunction with the Merger. The Company calculated net income or loss per share/unit using the treasury stock method.

The table below sets forth the computation of basic and diluted net income (loss) per share/unit for the periods presented below:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands, except per share/unit)
Continuing Operations:
Net income (loss) - Diluted	$	118,011	$	21,398	$	(46,869)
Less: Dividends on preferred units	—		—		(1,491)
Net income (loss) attributable to common shareholders/unitholders - Basic(1)	$	118,011	$	21,398	$	(48,360)
Basic weighted-average common shares/units outstanding	19,553		19,470		16,021
Effecting of dilutive securities:
Restricted shares/units	133		99		—
Diluted weighted-average common shares/units outstanding	19,686		19,569		16,021
Continuing Operations:
Basic net income (loss) per common share/unit	$	6.04	$	1.10	$	(3.02)
Diluted net income (loss) per common share/unit	$	5.99	$	1.09	$	(3.02)

_____________________________________________________

(1) Used in the basic and diluted net loss per share/unit calculation when the Company is in a net loss position.

F-33

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The following shares/units were excluded from the calculation of diluted net income (loss) per share/unit due to their anti-dilutive effect for the periods presented:

	Year Ended December 31, 2022	Three Months Ended December 31, 2021	Year Ended September 30, 2021
	(In thousands)
Restricted shares/units	405	268	228

(14)Commitments and Contingencies

Legal Matters

The Company was named as a defendant in an adversary proceeding (the "Adversary Proceeding") commenced on October 25, 2021 in United States Bankruptcy Court for the Northern District of Texas, Dallas Division (the "Bankruptcy Court"), by the Trustee of the Chapter 7 bankruptcy of the Hoactzin Partners, L.P. ("Hoactzin"). The complaint in the Adversary Proceeding alleges that in October of 2018, one year prior to the Hoactzin bankruptcy filing in October of 2019, Peter Salas ("Salas"), Chairman of the Board of Tengasco during the period of the purported fraudulent transfers, caused Hoactzin to transfer its working interests in certain wells on its Kansas acreage (the “Kansas Working Interests”) to the Company for an amount the complaint alleges was purportedly less than the reasonable equivalent value of such Kansas Working Interests. The complaint includes avoidance actions and other causes of action in connection with the transfer of the Kansas Working Interests, as well as other causes of action alleged related to certain transactions to which the Company was not a party.

On October 13, 2022, the Company entered into a Compromise Settlement Agreement and Mutual General Release (the “Settlement Agreement”) with the Trustee for the bankruptcy estate for Hoactzin to resolve certain claims against the Company in the Adversary Proceeding. Under the terms of the Settlement Agreement, the Company agreed to pay $80 thousand to the Trustee in full settlement and satisfaction of (a) all claims, causes of action, and damages that have been asserted against the Company or could be asserted against the Company in the Adversary Proceeding; and (b) all claims which might arise from or relate to any actions taken by the Company while acting in connection with Debtor.

On November 17, 2022, the Bankruptcy Court approved the Settlement Agreement. On November 17, 2022, the Company made the settlement payment to the Trustee in accordance with the Settlement Agreement. On November 22, 2022, the Bankruptcy Court entered an Order Granting the Joint Motion Dismissal resulting in the dismissal of the Adversary Proceeding with prejudice (the "Dismissal Order"), as contemplated by the Settlement Agreement.

Neither the Settlement Agreement nor the Dismissal Order has any effect on the Trustee’s claims against any of the other defendants in the Adversary Proceeding, including without limitation, those claims against Peter Salas, our former Chief Executive Officer.

Environmental Matters

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. The Company had no material environmental liabilities as of December 31, 2022 or 2021.

Contractual Commitments

In October 2021, the Company executed two agreements related to its enhanced oil recovery ("EOR") project. The first agreement is a CO2 purchase agreement with Kinder Morgan CO2 Company, LLC that has a primary term extending through the earlier of the total contract quantity delivered or December 31, 2025. The agreement also has a daily contract quantity for Kinder Morgan to deliver CO2 to the Company. The second agreement is a connection agreement that also established a delivery point for the purchased CO2 with the Cortez Pipeline Company.

F-34

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

In April 2022, the Company entered into a purchase agreement for pipe related to its 2023 drilling program. Under the agreement, the Company has commitments to purchase an additional approximately $2.8 million of pipe by second quarter of 2023 as of December 31, 2022.

In August 2022, the Company entered into a second amendment on its gas gathering and processing agreement with its primary midstream counterparty, Stakeholder Midstream LLC (“Stakeholder”). Stakeholder committed to expand their gathering and processing system with a commitment from the Company to deliver an annual minimum volume to Stakeholder’s gathering system for a minimum of seven years beginning on the in-service date of the expanded plant.

(15)Subsequent Events

Dividend Declaration

On January 11, 2023, the Board of Directors of the Company declared a cash dividend of $0.34 per share of common stock payable on February 8, 2023 to its shareholders of record at the close of business on January 25, 2023.

Entry into Purchase and Sales Agreement

On February 22, 2023, the Company entered into a purchase and sale agreement (the "Purchase Agreement") to acquire interests in oil and natural gas leases and related property with Pecos Oil & Gas, LLC (“Pecos”) for a purchase price of approximately $330 million, subject to customary closing adjustments, (the “New Mexico Acquisition”). The oil and natural gas leases are located in the Yeso trend of the Permian Basin in Eddy County of New Mexico. On February 22, 2023, in connection with the Purchase Agreement, REP deposited $33 million in cash into a third party escrow account, which will be credited against the purchase price upon closing.

The New Mexico Acquisition is expected to close early in the second quarter of 2023, subject to the satisfaction of several closing considerations, including but not limited to, an amendment to the revolving credit facility and a commitment letter dated February 22, 2023 with Truist Bank and the other participating lenders, it is anticipated that up to $130 million of the purchase price will be funded by amending REP’s existing credit facility to increase the total borrowing base to $475 million from $225 million. The commitment letter and related amendment to the credit facility and increase to the borrowing base are subject to a number of conditions, including the preparation, execution and delivery of loan amendments.

In connection with the Purchase Agreement, the Company entered into a commitment letter dated February 22, 2023 (the "Commitment Letter") with EOC Partners Advisors L.P. and/or one of its affiliates (collectively, “EOC”) in which EOC and/or one of its affiliates will purchase $200 million of unsecured senior notes (“Senior Notes”) from the Company on the closing date of the New Mexico Acquisition. The proceeds of the Senior Notes will be used to fund a portion of the purchase price of the New Mexico Acquisition and to pay fees, costs and expenses related to the New Mexico Acquisition and the related financing transactions. The Senior Notes will bear interest at 10.5% annually and will mature five years after issuance. The Senior Notes contain certain mandatory and voluntary prepayment conditions. Additionally, the Senior Notes have various financial covenants. The funding of the Senior Notes is contingent on the satisfaction or waiver of certain conditions set forth in the Commitment Letter.

Derivative Contracts

As discussed above, the Company entered into the Purchase Agreement to acquire assets in Eddy County New Mexico. In connection with the Purchase Agreement, the Company entered into the Commitment Letter described above for the issuance of $200 million of Senior Notes upon closing of the New Mexico Acquisition, which is subject to the terms and conditions set forth therein. The Senior Notes contain certain hedging requirements. The Company has therefore added to its open derivative contracts in anticipation of an early second quarter close on the New Mexico Acquisition and issuance of Senior Notes. The

F-35

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

following table summarizes the Company's open derivative positions as of March 3, 2023, related to oil and natural gas production:

		Weighted Average Price
Period(1)	Notional Volume	Fixed		Put		Call
		($ per unit)
Oil Swaps (Bbl)
Q1 2023	225,000	$	53.65	$	—	$	—
Q2 2023	315,000	$	62.78	$	—	$	—
Q3 2023	216,000	$	63.04	$	—	$	—
Q4 2023	189,000	$	62.51	$	—	$	—
2024	240,000	$	71.60	$	—	$	—
Oil Collars (Bbl)
Q1 2023	210,000	$	—	$	70.95	$	89.96
Q2 2023	300,000	$	—	$	71.50	$	88.98
Q3 2023	330,000	$	—	$	68.64	$	88.85
Q4 2023	330,000	$	—	$	68.64	$	88.85
2024	1,293,000	$	—	$	61.02	$	86.39
2025	315,000	$	—	$	60.00	$	77.98
Natural Gas Swaps (MMBtu)
Q1 2023	—	$	—	$	—	$	—
Q2 2023	450,000	$	2.60	$	—	$	—
Q3 2023	450,000	$	2.60	$	—	$	—
Q4 2023	400,000	$	3.23	$	—	$	—
2024	1,500,000	$	3.43	$	—	$	—
2025	375,000	$	4.05	$	—	$	—
Natural Gas Collars (MMBtu)
Q1 2023	—	$	—	$	—	$	—
Q2 2023	300,000	$	—	$	2.55	$	3.20
Q3 2023	300,000	$	—	$	2.55	$	3.20
Q4 2023	300,000	$	—	$	3.12	$	4.07
2024	1,065,000	$	—	$	3.19	$	4.14
2025	255,000	$	—	$	3.65	$	4.95
Oil Basis (Bbl)
Q1 2023	240,000	$	1.28	$	—	$	—
Q2 2023	360,000	$	1.28	$	—	$	—
Q3 2023	360,000	$	1.28	$	—	$	—
Q4 2023	360,000	$	1.28	$	—	$	—
2024	960,000	$	0.87	$	—	$	—

___________________

(1)Q1 2023 derivative positions shown include January and February 2023 contracts, some of which have settled as of March 3, 2023.

F-36

SUPPLEMENTAL OIL AND GAS INFORMATION - (Continued)
(Unaudited)

(16)Supplemental Information on Oil and Natural Gas Operations (Unaudited)

Capitalized Costs

Capitalized costs include the cost of properties, equipment and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells and related equipment and facilities.

Capitalized costs for unproved properties include costs for acquiring or extending oil and natural gas leaseholds where no proved reserves have been identified. Work in progress include costs of exploratory and development wells that are in the process of drilling or in active completion, and costs of exploratory and development wells suspended or waiting on completion. For a summary of these costs, please refer to Note 5 – Oil and Natural Gas Properties.

Costs Incurred for Property Acquisition, Exploration and Development

Amounts reported as costs incurred include both capitalized costs and costs charged to expense when incurred for oil and natural gas property acquisition, exploration and development activities. Costs incurred also include new ARO established in the current year as well as increases or decreases to ARO resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells and construction of related production facilities.

The following summarizes the costs incurred for oil and natural gas property acquisition, exploration and development activities for the periods presented below:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Acquisition of properties
Proved	$	450	$	67	$	74
Unproved	1,468		193		1,562
Exploration costs	157		—		7,993
Development costs	119,673		20,348		59,948
Total costs incurred	$	121,748	$	20,608	$	69,577

F-37

SUPPLEMENTAL OIL AND GAS INFORMATION - (Continued)
(Unaudited)

Results of Operations

The following table includes revenues and expenses associated with the Company's oil and natural gas producing activities. They do not include any allocation of the Company's interest costs or general corporate overhead. Therefore, the following schedule is not necessarily indicative of the contribution of net earnings of the Company's oil and natural gas operations.

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Oil, natural gas and NGL sales	$	319,343	$	56,650	$	148,636
Lease operating expenses	32,458		7,419		21,975
Production and ad valorem taxes	19,273		3,005		8,636
Exploration costs	2,032		611		9,566
Depletion, accretion and amortization	31,500		6,742		25,347
Impairment of oil and natural gas properties	7,325		—		—
Results of operations	226,755		38,873		83,112
Income tax expense (1)	48,957		(8,393)		(13,505)
Results of operations, net of income tax expense	$	275,712	$	30,480	$	69,607

_____________________________________________________

(1)    Subsequent to the Closing Date of the Merger, the statutory combined federal and state tax rate of 21.59% is used for the year ended December 31, 2022, three months ended December 31, 2021, and year ended September 30, 2021.

Oil, Natural Gas and NGL Quantities

Our reserve reports, as of the year ended December 31, 2022, three months ended December 31, 2021, and year ended September 30, 2021, were prepared by Netherland, Sewell & Associates, Inc. and are presented below. All reserves are located within the continental United States. Proved oil, natural gas and NGL reserves are the estimated quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimate is made. Proved developed oil, natural gas and NGL reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

F-38

SUPPLEMENTAL OIL AND GAS INFORMATION - (Continued)
(Unaudited)

The following table sets forth information for the periods below with respect to changes in the Company’s proved (i.e. proved developed and undeveloped) reserves:

	Oil	Natural Gas	NGLs	Total
	(MBbl)	(MMcf)	(MBbl)	(MBoe)
September 30, 2020	37,158	53,683	10,681	56,787
Extensions and discoveries	9,308	12,089	2,436	13,759
Revisions	2,138	12,850	492	4,772
Production	(2,341)	(2,603)	(380)	(3,155)
September 30, 2021	46,263	76,019	13,229	72,163
Extensions and discoveries	1,328	1,961	371	2,026
Revisions	99	350	(24)	133
Production	(669)	(844)	(105)	(915)
December 31, 2021	47,021	77,486	13,471	73,407
Extensions and discoveries	9,949	13,178	2,651	14,796
Revisions	(4,871)	(1,417)	(1,224)	(6,331)
Production	(3,217)	(3,229)	(444)	(4,199)
December 31, 2022	48,882	86,018	14,454	77,673
Proved Developed Reserves, Included Above
September 30, 2021	26,170	46,173	7,650	41,516
December 31, 2021	27,096	47,974	7,949	43,041
December 31, 2022	29,632	59,314	9,604	49,122
Proved Undeveloped Reserves, Included Above
September 30, 2021	20,093	29,846	5,579	30,647
December 31, 2021	19,925	29,512	5,522	30,366
December 31, 2022	19,250	26,704	4,850	28,551

As of December 31, 2022, reserves were comprised of 62.9% oil, 18.5% natural gas and 18.6% NGL. 2022 proved reserves were estimated based on prices of $91.96 per Bbl of oil, $3.16 per Mcf of natural gas and $25.55 per Bbl of NGL. Prices used in the 2022 reserve report are based on the twelve month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January 2022 through December 2022. For oil and NGL volumes, the average West Texas Intermediate ("WTI") spot price of $94.14 per Bbl is adjusted for quality, transportation fees, and market differentials. The fees associated with the transportation contract are included as a deduction to oil revenue. For gas volumes, the average Henry Hub spot price of $6.36 per MMBtu is adjusted for energy content, transportation fees and market differentials.

As of December 31, 2021, reserves were comprised of 64.1% oil, 17.6% natural gas and 18.3% NGL. December 31, 2021 proved reserves were estimated based on prices of $64.60 per Bbl of oil, $1.65 per Mcf of natural gas and $13.75 per Bbl of NGL. Prices used in the December 31, 2021 reserve report are based on the twelve month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January 2021 through December 2021. For oil and NGL volumes, the average WTI spot price of $66.55 per Bbl is adjusted for quality, transportation fees, and market differentials. The fees associated with the transportation contract are included as a deduction to oil revenue. For gas volumes, the average Henry Hub spot price of $3.60 per MMBtu is adjusted for energy content, transportation fees and market differentials.

As of September 30, 2021, reserves were comprised of 64.1% oil, 17.6% natural gas and 18.3% NGL. September 30, 2021 proved reserves were estimated based on prices of $55.73 per Bbl of oil, $0.99 per Mcf of natural gas and $9.83 per Bbl of NGL. Prices used in the September 30, 2021 reserve report are based on the twelve month unweighted arithmetic average of the first-day-of-the-month price for each month in the period October 2020 through September 2021. For oil and NGL volumes, the average WTI spot price of $57.64 per Bbl is adjusted for quality, transportation fees, and market differentials. The fees associated with the transportation contract are included as a deduction to oil revenue. For gas volumes, the average Henry Hub spot price of $2.94 per MMBtu is adjusted for energy content, transportation fees and market differentials.

F-39

SUPPLEMENTAL OIL AND GAS INFORMATION - (Continued)
(Unaudited)

For the year ended December 31, 2022, the Company had downward revisions of previous estimates of 6,331 MBoe. These revisions are primarily the result of changes in well level projections in certain undeveloped areas and increases in service costs. The Company had extensions and discoveries to proved developed and proved non-developed reserves of 14,796 MBoe which consisted of 7,759 MBoe as a result of drilling successful wells that were previously classified as unproved locations, and the addition to proved undeveloped of 7,037 MBoe as a result of drilling successful wells offsetting locations that were previously unproven locations. During the fiscal year in 2022, the Company did not purchase any additional reserves.

For the three months ended December 31, 2021, the Company had net upward revisions of previous estimates of 133 MBoe. These revisions are primarily the result of increases in pricing. The Company had extensions and discoveries to proved developed and proved non-developed reserves of 2,026 MBoe as a result of drilling successful wells that were previously classified as unproved locations. During the three months ended December 31, 2021, the Company did not purchase any additional reserves.

For the year ended September 30, 2021, the Company had upward revisions of previous estimates of 4,772 MBoe. These revisions are primarily the result of increases in pricing. The Company had extensions and discoveries to proved developed and proved non-developed reserves of 13,759 MBoe which consisted of 6,564 MBoe as a result of drilling successful wells that were previously classified as unproved locations, and the addition to proved undeveloped of 7,195 MBoe as a result of drilling successful wells offsetting locations that were previously unproven locations. During the year ended September 30, 2021, the Company did not purchase any additional reserves.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves

The Company follows the guidelines prescribed in ASC Topic 932 Extractive Activities – Oil and Gas for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following summarizes the policies used in the preparation of the accompanying oil, natural gas and NGL reserve disclosures, standardized measures of discounted future net cash flows from proved oil, natural gas and NGL reserves and the reconciliations of standardized measures from year to year.

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (i) estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions; (ii) estimated future cash flows are compiled by applying the twelve month average of the first of the month prices of crude oil and natural gas relating to the Company’s proved reserves to the year-end quantities of those reserves for reserves; (iii) future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions, plus Company overhead incurred; (iv) future income tax expenses are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and natural gas properties, other deductions, credits and allowances relating to the Company’s proved oil and natural gas reserves; and, (v) future net cash flows are discounted to present value by applying a discount rate of 10%.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the Securities and Exchange Commission. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations, since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

F-40

SUPPLEMENTAL OIL AND GAS INFORMATION - (Continued)
(Unaudited)

The following summary sets forth the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure prescribed in ASC Topic 932:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Future crude oil, natural gas and NGLs sales (1)(2)(3)	$	5,135,650	$	3,350,506	$	2,783,910
Future production costs	(1,559,266)		(912,468)		(839,167)
Future development costs	(341,481)		(216,138)		(218,765)
Future income tax expense	(658,340)		(436,829)		(324,487)
Future net cash flows	2,576,563		1,785,071		1,401,491
10% annual discount	(1,468,187)		(1,081,602)		(848,555)
Standardized measure of discounted future net cash flows	$	1,108,376	$	703,469	$	552,936

_____________________________________________________

(1)    December 31, 2022 proved reserves were derived based on prices of $91.96 per barrel of oil, $3.16 per Mcf of natural gas and $25.55 per barrel of NGL.

(2)    December 31, 2021 proved reserves were derived based on prices of $64.60 per barrel of oil, $1.65 per Mcf of natural gas and $13.75 per barrel of NGL.

(3)    September 30, 2021 proved reserves were derived based on prices of $55.73 per barrel of oil, $0.99 per Mcf of natural gas and $9.83 per barrel of NGL.

Principal sources of change in the Standardized Measure are shown below:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Balance, beginning of period	$	703,469	$	552,936	$	302,338
Sales of crude oil, natural gas and NGLs, net	(267,612)		(46,226)		(118,030)
Net change in prices and production costs	406,803		194,596		237,475
Net changes in future development costs	(40,226)		1,267		(18,856)
Extensions and discoveries	321,009		35,111		144,392
Revisions of previous quantity estimates	(83,188)		(536)		50,283
Previously estimated development costs incurred	8,775		4,182		12,844
Net change in income taxes	(117,098)		(47,881)		(124,625)
Accretion of discount	87,914		17,018		30,551
Other	88,530		(6,998)		36,564
Balance, end of period	$	1,108,376	$	703,469	$	552,936

F-41

EX-21.1

Exhibit 21.1

Riley Exploration Permian, Inc.

Subsidiaries

Name of Subsidiary	State of Formation
Riley Exploration – Permian, LLC	DE
Riley Permian Operating Company, LLC	DE
RPC Power HoldCo LLC	DE
RPC Power LLC	DE
RPC P&W LLC	DE
RPC Toll LLC	DE
RPC Merchant LLC	DE

{00031185.DOCX:1 }

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

Riley Exploration Permian, Inc.

Oklahoma City, Oklahoma

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-255104) and Form S-8 (No. 333-253750) of Riley Exploration Permian, Inc. of our reports dated March 8, 2023, relating to the consolidated financial statements, and the effectiveness of Riley Exploration Permian, Inc.’s internal control over financial reporting, which appear in this Form 10-K.

/s/ BDO USA, LLP

Houston, Texas

March 8, 2023

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the inclusion in this Annual Report on Form 10-K of Riley Exploration Permian, Inc. for the year ended December 31, 2022, of our report dated February 27, 2023, with respect to estimates of reserves and future net revenue of Riley Exploration Permian, Inc., as of December 31, 2022, and to all references to our firm included in this Annual Report. We also consent to the reference to us under the heading “Experts” in such Registration Statement.

NETHERLAND, SEWELL & ASSOCIATES, INC.
	By:	/s/ Eric J. Stevens
		Eric J. Stevens, P.E.
		President and Chief Operating Officer
Dallas, Texas
March 7, 2023

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Bobby D. Riley, certify that:

1. I have reviewed this Annual Report on Form 10-K of Riley Exploration Permian, Inc. for the year ended December 31, 2022.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Dated: March 8, 2023
By:	/s/ Bobby D. Riley
	Bobby D. Riley
	Chief Executive Officer

EX-31.2

Exhibit 31.2 

CERTIFICATION

I, Philip Riley, certify that:

1. I have reviewed this Annual Report on Form 10-K of Riley Exploration Permian, Inc. for the year ended December 31, 2022.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Dated: March 8, 2023
By:	/s/ Philip Riley
	Philip Riley
	Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 I hereby certify that:

I have reviewed the Annual Report on Form 10-K of Riley Exploration Permian, Inc. (the “Company”) for the year ended December 31, 2022 (the “Report”).

To the best of my knowledge the Report (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m (a) or 78o (d)); and, (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:  March 8, 2023
By:	/s/ Bobby Riley
	Bobby D. Riley
	Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION

 Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 I hereby certify that:

I have reviewed the Annual Report on Form 10-K of Riley Exploration Permian, Inc. (the “Company”) for the year ended December 31, 2022 (the “Report”).

To the best of my knowledge the Report (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m (a) or 78o (d)); and, (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:  March 8, 2023
By:	/s/ Philip Riley
	Philip Riley
	Chief Financial Officer

EX-99.1

Exhibit 99.1

February 27, 2023

Mr. Dan Doherty

Riley Exploration Permian, Inc.

29 East Reno Avenue, Suite 500

Oklahoma City, Oklahoma 73104

Dear Mr. Doherty:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2022, to the Riley Exploration Permian, Inc. (Riley Permian) interest in certain oil and gas properties located in New Mexico and Texas. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Riley Permian. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Riley Permian's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Riley Permian interest in these properties, as of December 31, 2022, to be:

	Net Reserves			Future Net Revenue (M$)
	Oil	NGL	Gas		Present Worth
Category	(MBBL)	(MBBL)	(MMCF)	Total	at 10%
Proved Developed Producing	29,631.9	9,604.4	59,313.6	2,205,346.9	1,010,693.0
Proved Developed Shut-In(1)	0.0	0.0	0.0	-565.4	-441.7
Proved Undeveloped	19,249.8	4,850.1	26,704.2	1,030,121.6	390,896.8
Total Proved	48,881.7	14,454.5	86,017.8	3,234,903.1	1,401,148.1

(1)    Future net revenue is after deducting estimated abandonment costs.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. Our study indicates that as of December 31, 2022, there are no proved developed non-producing reserves for these properties. As requested, probable and possible reserves that exist for these properties have not been included. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.

Gross revenue is Riley Permian's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Riley Permian's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Exhibit 99.1

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2022. For oil and NGL volumes, the average West Texas Intermediate spot price of $94.14 per barrel is adjusted by basin for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $6.357 per MMBTU is adjusted by basin for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $91.96 per barrel of oil, $25.55 per barrel of NGL, and $3.155 per MCF of gas.

Operating costs used in this report are based on operating expense records of Riley Permian. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into per-well costs and per-unit-of-production costs. Headquarters general and administrative overhead expenses of Riley Permian are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Riley Permian and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Riley Permian's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Riley Permian interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Riley Permian receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field- and lease-level accounting statements.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Riley Permian, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations; such reserves are based on analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Exhibit 99.1

The data used in our estimates were obtained from Riley Permian, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical person primarily responsible for preparing the estimates presented herein meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Michael B. Begland, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 1993 and has over 8 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
By:	/s/ C.H. (Scott) Rees III
	C.H. (Scott) Rees III, P.E.
	Executive Chairman
By:	/s/ Michael B. Begland
	Michael B. Begland, P.E. 104898
	Vice President
Date Signed: February 27, 2023

MBB:LEE

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
	Exhibit 99.1

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)    Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii)    Same environment of deposition;

(iii)    Similar geological structure; and

(iv)    Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and 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.

Supplemental definitions from the 2018 Petroleum Resources Management System:

Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i)    Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii)    Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii)    Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv)    Provide improved recovery systems.

Definitions - Page 1 of 6

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
	Exhibit 99.1

(8) 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.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) 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 gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i)    Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii)    Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii)    Dry hole contributions and bottom hole contributions.

(iv)    Costs of drilling and equipping exploratory wells.

(v)    Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is 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 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 as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i)    Oil and gas producing activities include:

(A)    The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;

(B)    The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C)    The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1)    Lifting the oil and gas to the surface; and

(2)    Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D)    Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a.    The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b.    In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Definitions - Page 2 of 6

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
	Exhibit 99.1

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii)    Oil and gas producing activities do not include:

(A)    Transporting, refining, or marketing oil and gas;

(B)    Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C)    Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D)    Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)    When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii)    Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii)    Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv)    The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v)    Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi)    Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)    When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii)    Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii)    Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv)    See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i)    Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A)    Costs of labor to operate the wells and related equipment and facilities.

(B)    Repairs and maintenance.

(C)    Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

Definitions - Page 3 of 6

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
	Exhibit 99.1

(D)    Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E)    Severance taxes.

(ii)    Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and 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. 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.

(i)    The area of the reservoir considered as proved includes:

(A)    The area identified by drilling and limited by fluid contacts, if any, and

(B)    Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)    In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)    Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)    Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)    Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B)    The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)    Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. 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.

(26) Reserves. Reserves are estimated remaining quantities of oil and 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 gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): 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

Definitions - Page 4 of 6

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
	Exhibit 99.1

reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

    a.    Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

    b.    Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

    a.    Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

    b.    Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

    c.    Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.

    d.    Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

    e.    Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

    f.    Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas 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.

(i)    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.

(ii)    Undrilled locations can be classified as having 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.

Definitions - Page 5 of 6

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
	Exhibit 99.1

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

    The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

    The company's historical record at completing development of comparable long-term projects;

    The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

    The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

    The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii)    Under no circumstances shall estimates for 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 6 of 6

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Cover - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Mar. 01, 2023	Jun. 30, 2022
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Current Fiscal Year End Date	--12-31
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Entity File Number	001-15555
Entity Registrant Name	Riley Exploration Permian, Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	87-0267438
Entity Address, Address Line One	29 E. Reno Avenue
Entity Address, Address Line Two	Suite 500
Entity Address, City or Town	Oklahoma City
Entity Address, State or Province	OK
City Area Code	405
Local Phone Number	415-8699
Title of 12(b) Security	Common stock, par value $0.001
Trading Symbol	REPX
Security Exchange Name	NYSEAMER
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Entity Public Float			$ 102.2
Entity Common Stock, Shares Outstanding		20,158,934
Documents Incorporated by Reference	The information required by Part III of this 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 2023, 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.
Entity Central Index Key	0001001614
Amendment Flag	false
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Entity Address, Postal Zip Code	73104

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Audit Information	12 Months Ended
	Dec. 31, 2022
Audit Information [Abstract]
Auditor Name	BDO USA, LLP
Auditor Location	Houston, Texas
Auditor Firm ID	243

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Current Assets:
Cash and cash equivalents	$ 13,301	$ 8,317
Accounts receivable	25,551	18,002
Prepaid expenses and other current assets	3,236	4,122
Inventory	8,886	780
Current derivative assets	20	83
Total current assets	50,994	31,304
Oil and natural gas properties, net (successful efforts)	440,102	359,131
Other property and equipment, net	20,023	3,174
Non-current derivative assets	0	267
Other non-current assets, net	4,175	2,293
Total Assets	515,294	396,169
Current Liabilities:
Accounts payable	3,939	7,737
Accounts payable - related parties	324	164
Accrued liabilities	35,582	12,874
Revenue payable	17,750	11,370
Current derivative liabilities	16,472	30,984
Other current liabilities	2,238	947
Total Current Liabilities	76,305	64,076
Non-current derivative liabilities	12	9,515
Asset retirement obligations	2,724	2,261
Revolving credit facility	56,000	65,000
Deferred tax liabilities	45,756	17,384
Other non-current liabilities	1,051	95
Total Liabilities	181,848	158,331
Commitments and Contingencies (Note 14)
Shareholders' Equity:
Preferred stock, $0.0001 par value, 25,000,000 shares authorized; 0 shares issued and outstanding	0	0
Common stock, $0.001 par value, 240,000,000 shares authorized; 20,160,980 and 19,836,885 shares issued and outstanding at December 31, 2022 and December 31, 2021, respectively	20	20
Additional paid-in capital	274,643	271,737
Retained earnings (Accumulated deficit)	58,783	(33,919)
Total Shareholders' Equity	333,446	237,838
Total Liabilities and Shareholders' Equity	$ 515,294	$ 396,169
Common stock outstanding post merger (in Shares)	20,160,980	19,836,885
Common stock, shares issued (in Shares)	20,160,980	19,836,885

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CONSOLIDATED BALANCE SHEETS (PARENTHETICAL) - $ / shares	Dec. 31, 2022	Dec. 31, 2021
Statement of Financial Position [Abstract]
Preferred stock, par value (USD per Share)	$ 0.0001	$ 0.0001
Preferred stock, shares authorized (in Shares)	25,000,000	25,000,000
Preferred stock, shares issued (in Shares)	0	0
Preferred stock, shares outstanding (in Shares)	0	0
Common stock, par value (USD per Share)	$ 0.001	$ 0.001
Common stock, shares authorized (in Shares)	240,000,000	240,000,000
Common stock, shares issued (in Shares)	20,160,980	19,836,885
Common stock, shares outstanding (in Shares)	20,160,980	19,836,885

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CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Sep. 30, 2021
Revenues:
Total Revenues	$ 57,250	$ 321,743	$ 151,036
Costs and Expenses:
Lease operating expenses	7,419	32,458	21,975
Production and ad valorem taxes	3,005	19,273	8,636
Exploration costs	611	2,032	9,566
Depletion, depreciation, amortization and accretion	6,867	32,113	26,015
Impairment of oil and natural gas properties	0	7,325	0
General and administrative:
Administrative costs	3,633	18,496	13,966
Unit-based compensation expense	0	0	689
Share-based compensation expense	951	3,439	6,104
Cost of contract services - related parties	150	450	477
Transaction costs	1,258	2,638	3,732
Total Costs and Expenses	23,894	118,224	91,160
Income From Operations	33,356	203,519	59,876
Other Expense:
Interest expense, net	(896)	(1,090)	(4,534)
Loss on derivatives	(5,193)	(51,574)	(89,195)
Total Other Expense	(6,089)	(52,664)	(93,729)
Net Income (Loss) From Continuing Operations Before Income Taxes	27,267	150,855	(33,853)
Income tax expense	(5,869)	(32,844)	(13,016)
Net Income (Loss) From Continuing Operations	21,398	118,011	(46,869)
Discontinued Operations:
Loss from discontinued operations	0	0	(18,738)
Income tax expense on discontinued operations	0	0	(59)
Loss on Discontinued Operations	0	0	(18,797)
Net Income (Loss)	21,398	118,011	(65,666)
Dividends on preferred units	0	0	(1,491)
Net Income (Loss) Attributable to Common Shareholders/Unitholders	21,398	118,011	(67,157)
Net Income (Loss) Attributable to Common Shareholders/Unitholders	$ 21,398	$ 118,011	$ (67,157)
Net Income (Loss) per Share/Unit:
Net Income (Loss) per Share/Unit from Continuing Operations, Basic (USD per Share/Unit)	$ 1.10	$ 6.04	$ (3.02)
Net Income (Loss) per Share/Unit from Continuing Operations, Diluted (USD per Share/Unit)	1.09	5.99	(3.02)
Net Loss per Share/Unit from Discontinued Operations, Basic (USD per Share/Unit)	0	0	(1.17)
Net Loss per Share/Unit from Discontinued Operations, Diluted (USD per Share/Unit)	0	0	(1.17)
Net Income (Loss) per Share/Unit, Basic (USD per Share/Unit)	1.10	6.04	(4.19)
Net Income (Loss) per Share/Unit, Diluted (USD per Share/Unit)	$ 1.09	$ 5.99	$ (4.19)
Weighted Average Common Shares/Units Outstanding:
Basic (in Shares/Units)	19,470	19,553	16,021
Diluted (in Shares/Units)	19,569	19,686	16,021
Oil and natural gas sales, net
Revenues:
Total Revenues	$ 56,650	$ 319,343	$ 148,636
Contract services - related parties
Revenues:
Total Revenues	$ 600	$ 2,400	$ 2,400

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CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS'/SHAREHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Members' Equity	Common Stock	Additional Paid-in Capital	Retained Earnings (Accumulated Deficit)
Beginning balance (in Shares/Units) at Sep. 30, 2020		1,555	0
Beginning balance at Sep. 30, 2020	$ 0	$ 166,617	$ 0	$ 0	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common units under long-term incentive plan net (in Shares/Units)		13	197
Issuance of common shares under long-term incentive plan	4,165			4,165
Purchase of common units under long-term incentive plan (in Shares/Units)		(3)
Purchase of common units under long-term incentive plan		$ (191)
Dividends on preferred units		(1,491)
Dividends on common units		(7,571)
Unit-based compensation expense		$ 689
Net income (loss)	(65,666)
Preferred units converted to common units (in Shares/Units)		512
Preferred units converted to common units		$ 61,196
Restricted common shares issued in exchange for common units issued under long-term incentive plan (in Shares/Units)		(24)	198
Common shares issued in exchange for common units (effected for 1-for-12 reverse stock split) (in Shares/Units)		(2,053)	16,733
Common shares issued in exchange for common units (effected for 1-for-12 reverse stock split)	192,191	$ (192,191)	$ 17	192,174
Common shares issued for business combination (in Shares)			891
Common shares issued for business combination	26,392		$ 1	26,391
Restricted common shares issued (in Shares)			3
Share-based compensation expense	1,939			1,939
Dividends declared	(10,559)				(10,559)
Common stock sold to public, net of issuance costs (in Shares)			1,667
Common stock sold to public, net of issuance costs	46,684		$ 2	46,682
Repurchased shares for tax withholding (in Shares)			(17)
Repurchased shares for tax withholding	(514)			(514)
Ending balance (in Shares/Units) at Sep. 30, 2021		0	19,672
Ending balance at Sep. 30, 2021	221,690	$ 0	$ 20	270,837	(49,167)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common units under long-term incentive plan net (in Shares/Units)			175
Issuance of common shares under long-term incentive plan	0
Net income (loss)	21,398				21,398
Common shares issued for business combination	0
Share-based compensation expense	919			919
Dividends declared	(6,150)				(6,150)
Repurchased shares for tax withholding (in Shares)			(10)
Repurchased shares for tax withholding	(19)			(19)
Ending balance (in Shares/Units) at Dec. 31, 2021		0	19,837
Ending balance at Dec. 31, 2021	237,838	$ 0	$ 20	271,737	(33,919)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common units under long-term incentive plan net (in Shares/Units)			369
Issuance of common shares under long-term incentive plan	0
Net income (loss)	118,011				118,011
Common shares issued for business combination	0
Share-based compensation expense	3,946			3,946
Dividends declared	(25,309)				(25,309)
Repurchased shares for tax withholding (in Shares)			(45)
Repurchased shares for tax withholding	(1,040)			(1,040)
Ending balance (in Shares/Units) at Dec. 31, 2022		0	20,161
Ending balance at Dec. 31, 2022	$ 333,446	$ 0	$ 20	$ 274,643	$ 58,783

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CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS'/SHAREHOLDERS' EQUITY (PARENTHETICAL)	12 Months Ended
	Sep. 30, 2021
Statement of Stockholders' Equity [Abstract]
Reverse stock split	0.083

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Sep. 30, 2021
Cash Flows from Operating Activities:
Net income (loss)	$ 21,398	$ 118,011	$ (65,666)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss from discontinued operations	0	0	18,797
Oil and gas lease expirations	588	1,953	9,347
Depletion, depreciation, amortization and accretion	6,867	32,113	26,015
Impairment of proved properties	0	7,325	0
Loss on derivatives	5,193	51,574	89,195
Settlements on derivative contracts	(16,014)	(75,257)	(16,304)
Amortization of deferred financing costs	282	731	653
Unit-based compensation expense	0	0	689
Share-based compensation expense	951	3,946	6,104
Deferred income tax expense	5,756	28,372	12,962
Changes in operating assets and liabilities
Accounts receivable	(529)	(7,549)	(7,345)
Accounts receivable – related parties	456	0	(401)
Prepaid expenses and other current assets	(3,172)	(997)	201
Accounts payable and accrued liabilities	(2,625)	2,860	7,445
Accounts payable - related parties	164	160	0
Revenue payable	2,362	6,380	4,576
Other current liabilities	50	666	(195)
Net Cash Provided by Operating Activities - Continuing Operations	21,727	170,288	86,073
Cash Flows from Investing Activities:
Additions to oil and natural gas properties	(29,011)	(111,662)	(58,329)
Acquisitions of oil and natural gas properties	0	0	(445)
Acquisitions of land	0	(15,342)	0
Additions to other property and equipment	(117)	(1,252)	(1,714)
Tengasco acquired cash	0	0	860
Net Cash Used in Investing Activities - Continuing Operations	(29,128)	(128,256)	(59,628)
Cash Flows from Financing Activities:
Deferred financing costs	(274)	(1,942)	(139)
Proceeds from revolving credit facility	5,000	22,000	5,500
Repayments under revolving credit facility	0	(31,000)	(46,500)
Payment of common share/unit dividends	(6,056)	(25,066)	(18,286)
Proceeds from issuance of common stock	0	0	50,000
Public offering costs	0	0	(3,316)
Payment of preferred unit dividends	0	0	(1,491)
Common stock repurchased for tax withholding	(19)	(1,040)	(514)
Purchase of common units under long-term incentive plan	0	0	(191)
Net Cash Used in Financing Activities - Continuing Operations	(1,349)	(37,048)	(14,937)
Net Increase (Decrease) in Cash and Cash Equivalents from Continuing Operations	(8,750)	4,984	11,508
Cash Flows from Discontinued Operations:
Operating activities	0	0	7
Investing activities	0	0	3,892
Net Increase in Cash and Cash Equivalents from Discontinued Operations	0	0	3,899
Net Increase (Decrease) in Cash and Cash Equivalents	(8,750)	4,984	15,407
Cash and Cash Equivalents, Beginning of Period	17,067	8,317	1,660
Cash and Cash Equivalents, End of Period	8,317	13,301	17,067
Cash Paid For:
Interest, net of capitalized interest	495	1,749	3,234
Income taxes	0	3,611	191
Non-cash Investing and Financing Activities - Continuing Operations:
Changes in capital expenditures in accounts payable and accrued liabilities	(8,443)	15,229	11,204
Right of use assets obtained in exchange for operating lease liability	0	1,655	0
Preferred unit dividends paid in kind	0	0	904
Common stock issued in exchange for common units	0	0	192,191
Assets acquired and liabilities assumed in business combination	0	0	3,695
Common stock issued for business combination	0	0	26,392
Preferred units converted to common units	0	0	61,196
Non-cash Investing Activities - Discontinued Operations:
Goodwill incurred in business combination	0	0	19,013
Assets acquired and liabilities assumed in business combination	$ 0	$ 0	$ 2,824

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Nature of Business

12 Months Ended

Dec. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Business

Nature of Business

Organization

Riley Exploration Permian, Inc., ("Riley Permian", "REPX", "the Company", "Registrant", "we", "our", or "us"), is a growth-oriented, independent oil and natural gas company focused on the acquisition, exploration, development and production of oil, natural gas and natural gas liquids ("NGL") in Texas and New Mexico. Our activities primarily include the horizontal development of the San Andres formation, a shelf margin deposit on the Northwest Shelf of the Permian Basin. Our acreage is primarily located on large, contiguous blocks in Yoakum County, Texas.

On February 26, 2021 (the “Closing Date”), Riley Permian (f/k/a Tengasco, Inc. (“Tengasco”)), consummated a merger, dated as of October 21, 2020, by and among Tengasco, Antman Sub, LLC, a newly formed Delaware limited liability company and wholly owned subsidiary of Tengasco (“Merger Sub”), and Riley Exploration – Permian, LLC (“REP LLC”). Merger Sub merged with and into REP LLC, with REP LLC as the surviving company and as a wholly owned subsidiary of Tengasco (collectively, with the other transactions described in the Merger Agreement, the “Merger”). On the Closing Date, the Registrant changed its name from Tengasco, Inc. to Riley Exploration Permian, Inc.

Current Commodity Environment

U.S. and global markets experienced heightened volatility following impactful geopolitical events, consistent evidence of widespread inflation, as well as increased fears of an economic recession. However, commodity prices continued to remain high during 2022 due to OPEC+ and other oil and natural gas producers not rapidly increasing production levels, as well as from the recovery in demand related to the COVID-19 pandemic. The full-scale military invasion of Ukraine by Russian troops has continued unabated since February 2022 coupled with related economic sanctions imposed on Russia further exacerbating supply shortages, leading to disruptions in the credit and capital markets, including significant uncertainty in commodity prices, during 2022.

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Basis of Presentation

12 Months Ended

Dec. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

Basis of Presentation

On August 16, 2022, the Company's Board of Directors (the "Board") acting by written consent resolved to amend and restate the Company's Second Amended and Restated Bylaws to change the Company's fiscal year period from October 1st through September 30th each year to January 1st through December 31st each year commencing with the 2022 calendar year (the "Bylaws Restatement"). On August 19, 2022, the holders of approximately 75% of our outstanding Common Stock acting by written consent approved the Bylaws Restatement and adopted the Third Amended and Restated Bylaws. In accordance with Rule 14c-2 under the Exchange Act, the aforementioned actions taken by written consent became effective on September 23, 2022. As a result, the Company's 2022 fiscal year is now the period from January 1, 2022 to December 31, 2022.

The accompanying consolidated financial statements include the accounts of Riley Permian and its wholly owned subsidiaries REP LLC, Riley Permian Operating Company, LLC ("RPOC"), Tengasco Pipeline Corporation, Tennessee Land & Mineral Corporation, and Manufactured Methane Corporation, and have been prepared in accordance with accounting principles generally accepted in the United States ("U.S. GAAP"). All intercompany balances and transactions have been eliminated upon consolidation. The Merger was accounted for as a reverse merger and, as such, the historical operations of REP LLC are deemed to be those of the Company. Thus, the consolidated financial statements included in this report reflect (i) the historical operating results of REP LLC prior to the Merger; (ii) the consolidated results of the Company following the Merger; (iii) the assets and liabilities of REP LLC at their historical cost; and (iv) the Company’s equity and earnings per share for all periods presented.

Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had an immaterial effect on the previously reported total assets, total liabilities, members'/shareholders' equity, results of operations or cash flows.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Significant Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, accounts receivable, accrued capital expenditures and operating expenses, asset retirement obligations ("ARO"), the fair value determination of acquired assets and assumed liabilities, certain tax accruals and the fair value of derivatives.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. The Company maintains cash at financial institutions which may at times exceed federally insured amounts. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on its cash and cash equivalents.

Accounts Receivable

Our receivables arise primarily from the sale of oil, natural gas and NGLs and joint interest owner receivables for properties in which we serve as the operator. Accounts receivable are stated at amounts due, net of an allowance for credit losses, if necessary.

Accounts receivable from oil, natural gas and NGL sales are generally due within 30 to 60 days after the last day of each production month. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items.

To the extent actual volumes and prices of oil, natural gas and NGLs are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balance sheets. Oil is priced based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Natural gas pricing provisions are tied to a market index, with certain adjustments based on, among other factors, quality and heat content of natural gas, and prevailing supply and demand conditions. NGLs are priced based upon a market index with certain adjustments for transportation and fractionation. These market indices are determined on a monthly basis.

The Company estimates uncollectible amounts based on the length of time that the accounts receivable has been outstanding, historical collection experience and current and future economic and market conditions, if failure to collect is expected to occur. Allowances for credit losses are recorded as reductions to the carrying values of the accounts receivables included in the Company’s consolidated balance sheets and are recorded in Administrative costs in the consolidated statements of operations if failure to collect an estimable portion is determined to be probable. The Company had no allowance for credit losses at December 31, 2022 and December 31, 2021.

Accounts receivable is summarized below:

	December 31, 2022		December 31, 2021
	(In thousands)
Oil, natural gas and NGL sales	$	24,136	$	17,562
Joint interest accounts receivable	793		409
Other accounts receivable	622		31
Total accounts receivable	$	25,551	$	18,002

Inventory

The Company's inventory represents tangible assets such as drilling pipe, tubing, casing and operating supplies used in the Company's future drilling or repair operations. The Company accounts for its inventory using the first-in, first-out method and valued at the lower of cost or net realizable value.

Proved Oil and Natural Gas Properties

The Company uses the successful efforts method of accounting for its oil and natural gas producing activities. Under this method, all property acquisition costs and costs of development wells are capitalized as incurred. The costs of development wells are capitalized whether producing or non-producing. Costs to drill exploratory wells are capitalized pending the determination of whether proved reserves are found. If an exploratory well is determined to be unsuccessful, the costs of drilling the unsuccessful exploratory well are charged to exploration costs.

Geological and geophysical costs, including seismic studies, are charged to exploration costs as incurred. Expenditures incurred to operate and for maintenance, repairs and minor renewals necessary to maintain our oil and natural gas properties in operating condition are charged to lease operating expenses as incurred.

Capitalized costs of proved oil and natural gas properties are amortized using the units-of-production method based on production and estimates of proved reserve quantities. Leasehold acquisition costs of proved properties are depleted over total estimated proved reserves, and capitalized development costs of wells and related equipment and facilities are depleted over-estimated proved developed reserves.

On the sale or retirement of a complete unit of a proved property or field, the cost and related accumulated depletion, depreciation and amortization are eliminated from the oil and natural gas property accounts, and the resulting gain or loss is recognized. On the sale of a partial unit of proved property, the unamortized cost of the property is apportioned to the interest sold and the interest retained is accounted for on the basis of the fair value of the retained interests and a gain or loss is recognized if the divestiture significantly affects the depletion rate.

Unproved Oil and Natural Gas Properties

Unproved oil and natural gas properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we charge the associated unproved lease acquisition costs to exploration costs. Lease acquisition costs related to successful drilling are reclassified to proved oil and natural gas properties.

Upon the sale of an entire interest in an unproved property for cash or cash equivalents, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from the sale of partial interests in unproved oil and natural gas properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.

Impairment of Oil and Natural Gas Properties

The cost of proved oil and natural gas properties are assessed on a field-by-field basis for impairment at least annually or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The expected undiscounted future cash flows of the oil and natural gas properties are compared to the carrying amount of the oil, natural gas and NGL properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the carrying amount of the oil and natural gas properties is adjusted to estimated fair value. Assumptions associated with discounted cash flow models or valuations used in the impairment evaluation include estimates of

future oil, natural gas and NGL prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. Unproved oil and natural gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. See further discussion in Note 7 - Fair Value Measurements.

Business Combinations

In accordance with ASC 805 - Business Combinations, the Company accounts for its acquisitions that qualify as a business using the acquisition method. If the set of assets and activities acquired is not considered a business, it is accounted for as an asset acquisition using a cost accumulation model. In the cost accumulation model, the cost of the acquisition, including certain transaction costs, is allocated to the assets acquired on the basis of relative fair values.

The Company includes the results of operations of acquired businesses beginning on the respective acquisition dates. In accordance with the acquisition method, the Company allocates the purchase price of an acquired business to its identifiable assets and liabilities based on the estimated fair values. Transaction costs related to the business combination are expensed as incurred. This fair value measurement is based on unobservable (Level 3) inputs. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. The excess value of the net identifiable assets and liabilities acquired over the purchase price of an acquired business, if any, is recorded as a bargain purchase gain.

Other Property and Equipment, Net

Property and equipment are capitalized and recorded at cost, while maintenance and repairs are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 5 to 39 years. Capitalized costs related to leasehold improvements are depreciated over the life of the lease. As of December 31, 2022 and 2021, the Company had capitalized property and equipment costs of $5.3 million and $3.6 million, respectively, with $2.0 million and $1.7 million, respectively, of accumulated depreciation on the consolidated balance sheet. Components of other property and equipment consists of computer equipment, office furniture, tools and equipment, buildings and improvements, and vehicles.

Land purchases are accounted for at cost and are not depreciated. As of December 31, 2022 and 2021, the Company had capitalized land costs of $16.7 million and $1.3 million, respectively, on the consolidated balance sheet.

Deferred Financing Costs

Deferred financing costs include origination, arrangement, legal and other fees to issue or amend the terms of credit facility agreements. These deferred financing costs are reported as other non-current assets and recognized on the consolidated statement of operations as interest expense by amortizing the costs over the related financing using the straight-line method, which approximates the effective interest method.

Equity Issuance Costs

Equity issuance costs include underwriter, legal, accounting, printing and other fees to issue common equity securities. These issuance costs are netted against offering proceeds at the time of issuance and are reported as other non-current assets when related to the issuance of common equity securities. The issuance costs are expensed to the consolidated statement of operations if the issuance is unsuccessful.

Other Non-Current Assets, Net

Other non-current assets consisted of the following:

	December 31, 2022		December 31, 2021
	(In thousands)
Deferred financing costs, net	$	2,556	$	1,345
Prepayments to outside operators	186		690
Right of use assets	1,370		208
Other deposits	63		50
Total other non-current assets, net	$	4,175	$	2,293

The Company incurred $1.9 million in financing costs related to the amendments of its revolving credit facility in April and October 2022. The Company extended certain existing leases and entered into a new lease during the year ended December 31, 2022, which resulted in additions to the right of use assets.

Accrued Liabilities

Accrued liabilities consisted of the following:

	December 31, 2022		December 31, 2021
	(In thousands)
Accrued capital expenditures	$	16,744	$	5,618
Accrued lease operating expenses	4,607		2,534
Accrued general and administrative costs	2,286		3,404
Accrued inventory	6,235		—
Accrued ad valorem tax	3,789		705
Other accrued expenditures	1,921		613
Total accrued liabilities	$	35,582	$	12,874

Asset Retirement Obligations

ARO consist of future plugging and abandonment expenses on oil and natural gas properties. The fair value of the ARO is recorded as a liability in the period in which wells are drilled with a corresponding increase in the carrying amount of oil and natural gas properties. The liability is accreted for the change in its present value each period and the capitalized cost is depreciated using the units-of-production method. The asset and liability are adjusted for changes resulting from revisions to the timing or the amount of the original estimate when deemed necessary. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Components of the changes in ARO consisted of the following and is shown below:

	December 31, 2022		December 31, 2021
	(In thousands)
ARO, beginning balance	$	2,453	$	2,434
Liabilities incurred	358		56
Revision of estimated obligations	326		—
Liability settlements and disposals	(178)		(58)
Accretion	79		21
ARO, ending balance	3,038		2,453
Less: current ARO(1)	(314)		(192)
ARO, long-term	$	2,724	$	2,261

_____________________

(1)Current ARO is included within other current liabilities on the accompanying consolidated balance sheets.

Goodwill

Goodwill represents the future economic benefit arising from other assets acquired in a business combination that are not individually identified or separately recognized. Goodwill is initially recognized as the excess of the purchase price of a business combination over the fair value of the net assets acquired and is tested for impairment annually in accordance with ASC 350 - Intangibles - Goodwill and Other, or more frequently if there is a change in events or circumstances that indicate the carrying value of the goodwill may not be recoverable.

The impairment test should occur at the reporting unit level determined by the Company and an impairment should only exist if the Company has determined the carrying value of the goodwill no longer exceeds the implied fair value. If the Company determines it is more likely than not the fair value of the reporting unit is less than its carrying value, including goodwill, then a quantitative assessment is necessary. An impairment loss is recognized if the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill.

At the closing of the Merger, the Company determined it had two reporting units, and the entire goodwill balance was included in the reporting unit acquired in the Merger (the "Kansas Reporting Unit"). The Company did not fully integrate the Kansas Reporting Unit in the Company's operations as it was deemed to be held for sale upon acquisition. The Company assessed the goodwill balance for impairment since the Company entered into a purchase and sale agreement ("PSA") in March 2021 for $3.5 million before closing adjustments. As the carrying value exceeded the implied fair value at the time of the closing of the Merger, the Company concluded the goodwill balance associated with the Kansas Reporting Unit was impaired and recognized a goodwill impairment loss, included within loss from discontinued operations on the consolidated statement of operations, of $18.5 million for the year ended September 30, 2021. See further discussion in Note 12 - Discontinued Operations and Assets Held for Sale.

Revenue Recognition

Oil Sales

Under the Company’s oil sales contracts, oil that is produced by the Company is delivered to the purchaser at a contractually agreed-upon delivery point at which point the purchaser takes custody, title and risk of loss of the product. Once control has been transferred, the purchaser transports the product to a third party and receives market-based prices from the third party. The Company receives a percentage of proceeds received by the purchaser less transportation costs in accordance with the pricing provisions in the Company's contracts. As transportation costs are incurred after the transfer of control, the costs are included in oil and natural gas sales and represent part of the transaction price of the contract. The pricing provisions also provide quantity requirements and grade and quality specifications. The Company recognizes revenue at the net price received when control transfers to the purchaser.

Natural Gas and NGL Sales

Under the Company’s natural gas gathering and processing contracts, natural gas is delivered to the purchaser at the inlet of the purchasers' gathering system, at which point title and risk of loss is transferred to the purchaser. The purchaser gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of natural gas and NGLs in accordance

with the pricing provisions of the Company's contracts. As the gathering, processing and transportation activities occur after the transfer of control, these costs are netted against our oil and natural gas sales and represent part of the transaction price of the contract, and may exceed the sales price. The pricing provisions also provide quantity requirements and grade and quality specifications. The Company recognizes revenue on a net basis for amounts expected to be received from third party customers through the marketing process.

Transaction Price Allocated to Remaining Performance Obligations

Based on the Company’s current product sales contracts, with contract terms ranging from one to ten years, each unit of production is considered a separate performance obligation and therefore future production volumes are wholly unsatisfied and do not require allocation or disclosure of the transaction price to remaining performance obligations.

Contract Balances

Under the Company’s product sales contracts, the Company has the right to invoice customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606.

Prior-Period Performance Obligations

Revenue is recorded in the month in which production is delivered to the purchaser. However, certain settlement statements for oil, natural gas and NGLs may not be received for thirty to ninety days after the date production is delivered and, as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences identified between the Company’s revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2022, the three months ended December 31, 2021, and year ended September 30, 2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Disaggregation of Revenue

The following table presents oil and natural gas sales disaggregated by product:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Oil and natural gas sales:
Oil	$	298,723	$	50,623	$	136,421
Natural gas	10,755		2,705		7,500
Natural gas liquids	9,865		3,322		4,715
Total oil and natural gas sales, net	$	319,343	$	56,650	$	148,636

Contract Services with Related Parties

The Company has contracts with related parties to provide certain contract operating, accounting and back-office support services. Revenue related to these contract services is recognized over time as the services are rendered, and the fee is stated within the contract at a fixed monthly rate. Costs directly attributable to performing these services are also recognized as the services are rendered. Refer to Note 8 - Transactions with Related Parties for a more detailed discussion regarding these contracts.

Revenue Payable

For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds that the Company has not yet distributed to other revenue and royalty owners are reflected as revenue payable in the consolidated balance sheets.

Lease Operating Expenses

Lease operating costs, including payroll for field personnel, saltwater disposal, electricity, generator rentals, diesel fuel and other operating expenses, are expensed as incurred and included in lease operating expenses in our consolidated statements of operations.

Income Taxes

The Company uses the asset and liability method of accounting for income taxes, which requires the establishment of deferred tax accounts for all temporary differences between: (i) financial reporting and tax bases of assets and liabilities, using currently enacted federal and state income tax rates, and (ii) operating loss and tax credit carryforwards. In addition, deferred tax accounts must be adjusted to reflect new rates if enacted into law.

Realization of deferred tax assets is contingent on the generation of future taxable income. As a result, management considers whether it is more likely than not that all or a portion of such assets will be realized during periods when they are available, and if not, management provides a valuation allowance for amounts not likely to be recognized.

Management periodically evaluates tax reporting methods to determine if any uncertain tax positions exist that would require the establishment of a loss contingency. A loss contingency would be recognized if it were probable that a liability has been incurred as of the date of the financial statements and the amount of the loss can be reasonably estimated. The amount recognized is subject to estimates and management’s judgment with respect to the likely outcome of each uncertain tax position. The amount that is ultimately incurred for an individual uncertain tax position or for all uncertain tax positions in the aggregate could differ from the amount recognized. Interest and penalties, if any, related to uncertain tax positions are included in current income tax expense. There are no unrecorded liabilities for uncertain tax positions related to the Company as of December 31, 2022 and December 31, 2021. See further discussion in Note 11- Income Taxes.

Interest Expense

We have financed a portion of our working capital requirements, capital expenditures and certain acquisitions with borrowings under our revolving credit facility. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Interest expense in the consolidated statements of operations reflects interest less amounts allocated to capital expenditures, unused commitment fees paid to our lender, interest rate swap settlements plus the amortization of deferred financing costs (including origination and amendment fees). Interest expense was $1.1 million, $0.9 million, and $4.5 million for the year ended December 31, 2022, the three months ended December 31, 2021, and the year ended September 30, 2021, respectively.

Capitalized interest represents interest expense related to wells in process during the period in which the Company is incurring costs and expending resources to get the properties ready for their intended purpose. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful life of the asset in the same manner as the underlying asset.

Concentrations of Credit Risk

Our customer concentration may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry.

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, 2022, the three months ended December 31, 2021, and the year ended September 30, 2021, one purchaser accounted for 89%, 87%, and 87%, respectively, of our revenue purchased, with two end customers each accounting for more than 10% of the purchased revenue. During such periods, no other purchaser accounted for 10% or more of our revenues. The loss of this purchaser could materially and adversely affect our revenues in the short-term. However, the end customers include companies with lower credit risk. Further, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of any of our purchasers would not have a long-term material adverse effect on our financial condition and results of operations because oil, natural gas and NGLs are marketable products with well-established markets.

We manage credit risk related to accounts receivable through credit approvals, escrow accounts and monitoring procedures. Accounts receivable are generally not collateralized. However, we routinely assess the financial strength of our customers and, based upon factors surrounding the credit risk, establish an allowance for uncollectible accounts, if required. As a result, we believe that our accounts receivable credit risk exposure beyond such allowance is limited.

Environmental and Other Issues

We are engaged in oil and natural gas exploration and production and may become subject to certain liabilities as they relate to environmental cleanup of well sites or other environmental restoration procedures. In connection with our acquisition of existing or previously drilled well bores, we may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental cleanup or restoration, we would be responsible for curing such a violation.

We account for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated.

Fair Value Measurements

Certain financial instruments are reported at fair value on our consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost). These approaches are considered Level 3 in the fair value hierarchy.

The carrying values of financial instruments comprising cash and cash equivalents, payables, receivables, related party accounts receivable/payable and advances from joint interest owners approximate fair values due to the short-term maturities of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value reported for the revolving credit facility approximates fair value because the underlying instruments are at interest rates which approximate current market rates and is considered Level 3 in the fair value hierarchy. Assets and liabilities accounted for at fair value on a non-recurring basis in accordance with the fair value hierarchy include the initial recognition of asset retirement obligations, the fair value of oil and natural gas properties, and goodwill when acquired in a business combination or assessed for impairment and are considered Level 3 in the fair value hierarchy.

Derivative Contracts

We report the fair value of derivatives on the consolidated balance sheets in derivative assets and derivative liabilities as either current or non-current based on the timing of the settlement of individual trades. Trades that are scheduled to settle in the next twelve months are reported as current. The Company nets derivative assets and liabilities, in the consolidated balance sheets, whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract.

For the year ended December 31, 2022, the three months ended December 31, 2021, and year ended September 30, 2021, we have not designated our derivative contracts as hedges for accounting purposes, and therefore changes in the fair value of derivatives are recognized in earnings. Cash settlements of contracts are included in cash flows from operating activities in the consolidated statement of cash flows. Derivative contracts are settled on a monthly basis.

The fair value of the derivatives is established using index prices, volatility curves and discount factors. The value we report in our consolidated financial statements is as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors.

The use of derivatives involves the risk that the counterparties to such contracts will be unable to meet their obligations under the terms of the agreement. To minimize the credit risk with derivative instruments, it is our policy to enter into derivative contracts primarily with counterparties that are financial institutions that are also lenders within our revolving credit facility. Under the terms of the current counterparties' contracts, only those that are lenders under our revolving credit facility

are secured by the same collateral as outlined in our revolving credit facility. The counterparties are not required to provide credit support to the Company. See further discussion in Note 6 – Derivative Instruments.

Leases

The Company's current leases include office space and information technology equipment, comprised primarily of printers and copiers. The Company reviews all contracts to determine if a lease exists at contract inception. A lease exists when the Company has the right to obtain substantially all of the economic benefit of a specific asset and to control the use of that asset over the term of the agreement. Identified leases are classified as an operating or finance lease, which determines the recognition, measurement and presentation of expenses. As of December 31, 2022, the Company did not have any finance leases. Operating leases are capitalized on the consolidated balance sheet at commencement through a lease right-of-use ("ROU") asset and lease liability representing the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset includes any lease payments made to the lessor prior to lease commencement less any lease incentives and initial direct costs incurred. Options to extend or terminate leases are included in the lease term when it is reasonably certain the Company will exercise the option. For operating leases, lease costs are recognized on a straight-line basis over the term of the lease.

The present value of operating lease payments and amortization of the lease liability is calculated using a discount rate. When available, the Company uses the rate implicit in the lease as the discount rate; however, most of the Company’s leases do not provide a readily determinable implicit rate. In such cases, the Company is required to use its incremental borrowing rate ("IBR"). The Company’s IBR reflects the estimated rate of interest that the Company would pay to borrow on a collateralized basis over a similar term and amount equal to the lease payments in a similar economic environment. The Company is required to reassess the discount rate for any new and modified lease contracts as of the lease effective date. The weighted-average discount rate was 3.18% and 5.17%, respectively, at December 31, 2022 and 2021. The weighted average remaining lease term was 2.4 years and 0.5 years, respectively, at December 31, 2022 and 2021. Lease expense was $0.5 million, $0.1 million, and $0.4 million, respectively, for the year ended December 31, 2022, the three months ended December 31, 2021, and year ended September 30, 2021.

	December 31, 2022		December 31, 2021
	(In thousands)
ROU asset	$	1,370	$	208
Current lease liability	$	539	$	212
Long-term lease liability	$	838	$	—

The ROU asset and current lease liability was included in other non-current assets and other current liabilities and non-current lease liabilities, respectively, on the accompanying consolidated balance sheets. Lease expense for the Company was included in general and administrative costs on the accompanying consolidated statements of operations.

Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements

In December 2019, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2019-12, "Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes." This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance and is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company adopted this ASU effective October 1, 2021. The adoption of this ASU did not have a material impact on the Company's consolidated financial statements.

In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (“ASU 2020-04”), which provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates (e.g., London Interbank Offered Rate ("LIBOR")) that are expected to be discontinued. ASU 2020-04 allows, among other things, certain contract modifications, such as those within the scope of Topic 470 on debt, to be accounted for as a continuation of the existing contract. The Company adopted this ASU effective concurrent with the amendment of the Company's revolving credit facility in April 2022. See Note 9 - Revolving Credit Facility for additional information on the amendment of the revolving credit facility. The adoption of this ASU did not have a material impact on the Company's consolidated financial statements.

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Acquisitions

12 Months Ended

Dec. 31, 2022

Business Combination and Asset Acquisition [Abstract]

Acquisitions

Acquisitions

Business Combination Between REP LLC and Tengasco

Immediately prior to the closing of the Merger on February 26, 2021, REP LLC converted all of its issued and outstanding Series A Preferred Units into common units of REP LLC. In connection with the Merger, holders of common units of REP LLC were entitled to receive, in exchange for each common unit, shares of common stock of Tengasco (which was renamed Riley Exploration Permian, Inc.), par value $0.001 per share (“Tengasco common stock”) based on the exchange ratio set forth in the Merger Agreement (the “Exchange Ratio”), with cash paid in lieu of the issuance of any fractional shares. The Exchange Ratio was 97.796467 shares of Tengasco common stock for each common unit of REP LLC (as adjusted for the reverse stock split). Immediately prior to the closing of the Merger, Tengasco effected a one-for-twelve reverse stock split resulting in outstanding common stock of approximately 17.8 million shares including shares of Tengasco common stock issued in the Merger.

The combination between REP LLC and Tengasco qualified as a business combination with REP LLC being treated as the accounting acquirer. The assets acquired and liabilities assumed were recognized on the consolidated balance sheet at fair value as of the acquisition date.

The consideration paid in the Merger by REP LLC as the accounting acquirer totaled approximately $26.4 million and was determined based on the closing price of Tengasco’s common stock on February 26, 2021 and the total number of shares outstanding immediately prior to the Merger. The Merger was structured as a tax-free reorganization for United States federal income tax purposes.

The following table summarizes the consideration for the Merger (presented in thousands, except stock price):

Tengasco common stock price	$	29.64
Tengasco common stock - issued and outstanding as of February 26, 2021	891
Total consideration	$	26,392

The Company incurred approximately $5.0 million of related costs for the Merger, of which $3.6 million was expensed for the year ended September 30, 2021 as transaction costs on the consolidated statements of operations.

The Company completed the determination of the fair value attributable to the assets acquired and liabilities assumed as of September 30, 2021. The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed based on their fair values on February 26, 2021 (in thousands):

Assets
Cash and cash equivalents	$	860
Accounts receivable	325
Prepaid and other current assets	759
Total current assets	1,944
Oil and gas properties	4,525
Other property and equipment	91
Right of use assets	42
Other non-current assets	4
Deferred tax assets	2,987
Total assets acquired	$	9,593
Liabilities
Accounts payable	$	130
Accrued liabilities	409
Current lease liabilities, operating	42
Current lease liabilities, financing	68
Total current liabilities	649
Asset retirement obligations	1,565
Total liabilities assumed	2,214
Net identifiable assets acquired	7,379
Goodwill	19,013
Net assets acquired	$	26,392

The goodwill recognized was primarily attributable to a substantial increase in the stock price of Tengasco on the Closing Date, which increased the amount of the consideration transferred. The Company does not expect goodwill to be deductible for tax purposes.

Pro Forma Operating Results (Unaudited)

The following unaudited pro forma combined results for the year ended September 30, 2021 reflect the consolidated results of operations of the Company as if the Merger had occurred on October 1, 2019. Subsequent to the Merger, the Company changed its fiscal year period from October 1st through September 30th each year to January 1st to December 31st each year commencing with the 2022 calendar year. The unaudited pro forma information includes adjustments for $3.6 million of transaction costs being reclassified to the fourth quarter of calendar year 2019 which were incurred during the year ended September 30, 2021. Additionally, the Company adjusted for $0.9 million of oil and natural gas property impairment that Tengasco recognized under the full-cost method of accounting, which would not have been recognized under the successful efforts method, during the three months ended December 31, 2020. Also, the unaudited pro forma information has been tax

effected using a 21% tax rate. The common stock was also adjusted for the conversion of the REP LLC preferred units into common units and retroactively adjusted for the Exchange Ratio and one-for-twelve reverse stock split.

	For the year ended September 30, 2021
	(In thousands, except per share/unit amounts)
	(Unaudited)
Total Revenues	$	151,036
Pro Forma Net Loss before Taxes	(29,871)
Pro forma income tax benefit	6,273
Pro Forma Net Loss	$	(23,598)
Net Loss per Share/Unit from Continuing Operations:
Basic	$	(1.88)
Diluted	$	(1.88)
Net Income per Share/Unit from Discontinued Operations:
Basic	$	0.02
Diluted	$	0.02

The unaudited pro forma combined financial information is for informational purposes only and was based off of the fiscal year period October 1st through September 30th as this was the fiscal year in effect at the time of the Merger. The unaudited pro forma financial information was not modified for the change in the Company's fiscal year. It is not intended to represent or to be indicative of the combined results of operations that the Company would have reported had the Merger been completed as of October 1, 2019 and should not be taken as indicative of the Company's future combined results of operations. The actual results may differ significantly from that reflected in the unaudited pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the unaudited pro forma combined financial information and actual results.

Divestitures

On April 2, 2021, the Company closed on the sale of the Kansas Reporting Unit for an agreed upon purchase price of $3.5 million, less approximately $0.2 million of closing adjustments. See further discussion in Note 12 - Discontinued Operations and Assets Held for Sale.

Transaction Costs

Transaction costs consist of those costs associated with investment banking, accounting, legal and other diligence costs related to unsuccessful acquisitions or successful acquisitions accounted for as business combinations. The Company recognized transaction costs for the periods presented below:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Business combination acquisition costs	$	2,638	$	1,258	$	3,572
Other	—		—		160
Total transaction costs	$	2,638	$	1,258	$	3,732

The transaction costs of $2.6 million and $1.3 million for the year ended December 31, 2022 and three months ended December 31, 2021, respectively, primarily related to a potential business combination and related financing that the Company pursued but ultimately chose not to consummate. During the year ended September 30, 2021, the transaction costs of $3.6 million primarily relate to costs incurred on the Merger with Tengasco in February 2021.

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Oil and Natural Gas Properties

12 Months Ended

Dec. 31, 2022

Extractive Industries [Abstract]

Oil and Natural Gas Properties

Oil and Natural Gas Properties

Oil and natural gas properties are summarized below:

	December 31, 2022		December 31, 2021
	(In thousands)
Proved	$	516,011	$	421,779
Unproved	12,770		18,839
Work-in-progress	45,169		13,534
	573,950		454,152
Accumulated depletion, amortization and impairment	(133,848)		(95,021)
Total oil and natural gas properties, net	$	440,102	$	359,131

At December 31, 2022 and 2021, the Company had one exploratory well drilled but uncompleted that was included in work-in-progress with associated well costs of $3.8 million and $3.7 million, respectively. At December 31, 2022, the Company had one exploratory well with costs of $3.8 million that has been capitalized for greater than two years. The Company is in the process of evaluating completion methods for this exploratory well.

Depletion and amortization expense for proved oil and natural gas properties was $31.5 million for the year ended December 31, 2022, $6.7 million for the three months ended December 31, 2021, and $25.2 million for the year ended September 30, 2021.

Exploration expense was $2.0 million for the year ended December 31, 2022, $0.6 million for the three months ended December 31, 2021, and $9.6 million for the year ended September 30, 2021. Exploration expense was primarily attributable to the expiration of oil and natural gas leases for the year ended December 31, 2022, the three months ended December 31, 2021 and year ended September 30, 2021.

Impairment of Proved Properties

Certain proved oil and natural gas properties were impaired during year ended December 31, 2022. Our impairment test involved a Step 1 assessment to determine if the net book value of our proved oil and natural gas properties is expected to be recovered from the estimated undiscounted future net cash flows. We calculated the expected undiscounted future net cash flows of our long-lived assets using management’s assumptions and expectations. See further discussion in Note 7 - Fair Value Measurements.

Certain oil and natural gas properties in our New Mexico operating area failed the Step 1 assessment. For these assets, we used a discounted cash flow analysis to estimate fair value. The expected future net cash flows were discounted using a rate of 10.25%, which we believe represents the estimated weighted average cost of capital of a market participant. Based on Step 2 of our long-lived assets impairment test, we recognized a $7.3 million impairment because the carrying value exceeded the estimated fair market value as of the year ended December 31, 2022. See further discussion of our fair value assumptions in Note 7 - Fair Value Measurements.

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Derivative Instruments

12 Months Ended

Dec. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

Derivative Instruments

Oil and Natural Gas Contracts

The Company uses commodity based derivative contracts to reduce exposure to fluctuations in oil and natural gas prices. While the use of these contracts limits the downside risk for adverse price changes, their use also limits future revenues from favorable price changes. We have not designated our derivative contracts as hedges for accounting purposes, and therefore changes in the fair value of derivatives are included and recognized in other income (expense) in the consolidated statement of operations.

As of December 31, 2022, the Company's oil and natural gas derivative instruments consisted of the following types:

•Fixed Price Swaps – the Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

•Costless collars – the combination of a put option (fixed floor) and call option (fixed ceiling), with the options structured so that the premium paid to purchase the put option is offset by the premium received from the sale of the call option. If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the put and the call strike price, no payments are due from either party.

•Basis Protection Swaps – basis swaps are settled based on differences between a fixed price differential and the differential between the settlement prices of two referenced indexes. We receive the fixed price differential and pay the differential between the referenced indexes.

The following table summarizes the open financial derivative positions as of December 31, 2022, related to oil and natural gas production:

		Weighted Average Price
Calendar Quarter / Year	Notional Volume	Fixed		Put		Call
		($ per unit)
Oil Swaps (Bbl)
Q1 2023	225,000	$	53.65	$	—	$	—
Q2 2023	195,000	$	53.89	$	—	$	—
Q3 2023	126,000	$	53.79	$	—	$	—
Q4 2023	114,000	$	54.59	$	—	$	—
Oil Collars (Bbl)
Q1 2023	30,000	$	—	$	60.00	$	109.60
Q2 2023	30,000	$	—	$	60.00	$	109.60
Q3 2023	—	$	—	$	—	$	—
Q4 2023	—	$	—	$	—	$	—
2024	3,000	$	—	$	50.00	$	88.00

The Company entered into additional derivative contracts subsequent to December 31, 2022. See further discussion in Note 15 - Subsequent Events.

Interest Rate Contracts

During the years ended December 31, 2022 and 2021, the Company entered into floating-to-fixed interest rate swaps, in which it received a floating market rate equal to one-month LIBOR or Secured Overnight Financing Rate ("SOFR") and paid a fixed interest rate, to manage interest rate exposure related to the Company's revolving credit facility. In December 2022, the Company settled the remaining open positions for the interest rate swap which resulted in a $1.5 million settlement. The Company recognizes settlements on interest rate swaps in interest expense on the consolidated statements of operations.

Balance Sheet Presentation of Derivatives    

The following tables present the location and fair value of the Company’s derivative contracts included in the consolidated balance sheets as of December 31, 2022 and 2021:

	December 31, 2022
Balance Sheet Classification	Gross Fair Value		Amounts Netted		Net Fair Value
	(In thousands)
Current derivative assets	$	64	$	(44)	$	20
Non-current derivative assets	9		(9)		—
Current derivative liabilities	(16,516)		44		(16,472)
Non-current derivative liabilities	(21)		9		(12)
Total	$	(16,464)	$	—	$	(16,464)
	December 31, 2021
Balance Sheet Classification	Gross Fair Value		Amounts Netted		Net Fair Value
	(In thousands)
Current derivative assets	$	281	$	(198)	$	83
Non-current derivative assets	267		—		267
Current derivative liabilities	(31,182)		198		(30,984)
Non-current derivative liabilities	(9,515)		—		(9,515)
Total	$	(40,149)	$	—	$	(40,149)

The following table presents the components of the Company's gain (loss) on derivatives for the periods presented below:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Settlements on derivative contracts(1)	$	(75,257)	$	(16,014)	$	(16,304)
Non-cash gain (loss) on derivatives	23,683		10,821		(72,891)
Loss on derivatives	$	(51,574)	$	(5,193)	$	(89,195)

_____________________________________________________

(1) In December 2022, the Company settled a portion of its 2023 open oil fixed price swap contracts which resulted in a $1.5 million settlement.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2022

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.

The carrying values of financial instruments comprising cash and cash equivalents, payables, receivables, and advances from joint interest owners approximate fair values due to the short-term maturities of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value reported for the revolving credit facility approximates fair value because the underlying instruments are at interest rates which approximate current market rates. The revolving line of credit is considered Level 3 in the fair value hierarchy.

Assets and Liabilities Measured on a Recurring Basis

The fair value of commodity derivatives and interest rate swaps is estimated using discounted cash flow calculations based upon forward curves and are classified as Level 2 in the fair value hierarchy. The following table presents the Company’s

financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2022 and 2021, by level within the fair value hierarchy:

	December 31, 2022
	Level 1		Level 2		Level 3		Total
	(In thousands)
Financial assets:
Commodity derivative assets	$	—	$	73	$	—	$	73
Financial liabilities:
Commodity derivative liabilities	$	—	$	(16,537)	$	—	$	(16,537)
	December 31, 2021
	Level 1		Level 2		Level 3		Total
	(In thousands)
Financial assets:
Commodity derivative assets	$	—	$	187	$	—	$	187
Interest rate assets	$	—	$	361	$	—	$	361
Financial liabilities:
Commodity derivative liabilities	$	—	$	(40,687)	$	—	$	(40,687)
Interest rate liabilities	$	—	$	(10)	$	—	$	(10)

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

Assets and liabilities accounted for at fair value on a non-recurring basis in accordance with the fair value hierarchy include the initial recognition of asset retirement obligations, the fair value of oil and natural gas properties, and goodwill when acquired in a business combination or assessed for impairment.

The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future commodity prices; (iii) operating and development costs; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that the Company’s management believes will impact realizable prices. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation.

The fair value of asset retirement obligations incurred and acquired during the year ended December 31, 2022 and the three months ended December 31, 2021, totaled approximately $0.4 million and $0.1 million, respectively. The fair value of additions to the asset retirement obligation liabilities is measured using valuation techniques consistent with the income approach, which converts future cash flows to a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well for all oil and natural gas wells and for all disposal wells; (ii) estimated remaining life per well; (iii) future inflation factors; and (iv) our average credit-adjusted risk-free rate. These assumptions represent Level 3 inputs.

If the carrying amount of our oil and natural gas properties exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The fair value of our oil and natural gas properties is determined using valuation techniques consistent with the income and market approach. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with the expected cash flow projected. These assumptions represent Level 3 inputs.

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Transactions with Related Parties

12 Months Ended

Dec. 31, 2022

Related Party Transactions [Abstract]

Transactions with Related Parties

Transactions with Related Parties

Contract Services

RPOC provides certain administrative services to Combo Resources, LLC ("Combo") and is also the contract operator on behalf of Combo in exchange for a monthly fee of $100 thousand and reimbursement of all third party expenses pursuant to a contract services agreement. Additionally, RPOC provides certain administrative and operational services to Riley Exploration Group, LLC ("REG") in exchange for a monthly fee of $100 thousand pursuant to a contract services agreement. Combo and REG are portfolio companies of Yorktown Energy Partners XI, L.P. ("Yorktown XI"), certain managed funds of which have investments in the Company (all deemed to be related parties). One of our executives held positions with REG and Combo at December 31, 2022. Our Executive Vice President, Business Intelligence is the President of both REG and Combo, as well as a board member of Combo.

The following table presents revenues from and related cost for contract services for related parties:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Combo	$	1,200	$	300	$	1,200
REG	1,200		300		1,200
Contract services - related parties	$	2,400	$	600	$	2,400
Cost of contract services	$	450	$	150	$	477

The Company had amounts payable to Combo of $0.4 million and $0.2 million at December 31, 2022 and 2021, respectively, which are reflected in accounts payable - related parties on the accompanying consolidated balance sheets. Amounts due to Combo reflect the revenue, net of any expenditures for wells and fees due under the contract services agreement, for Combo's net working interest in wells that the Company operates on Combo's behalf.

Consulting and Legal Fees

The Company has an engagement agreement with di Santo Law PLLC ("di Santo Law"), a law firm owned by Beth di Santo, a member of our Board of Directors, pursuant to which di Santo Law's attorneys provide legal services to the Company. For the year ended December 31, 2022, the three months ended December 31, 2021, and year ended September 30, 2021, the Company incurred legal fees from di Santo Law of approximately $0.7 million, $0.2 million, and $1.0 million, respectively. As of December 31, 2022 there are no accrued amounts for di Santo Law. As of December 31, 2021, the Company had approximately $0.2 million in amounts accrued for di Santo Law, which was included in accrued liabilities in the accompanying consolidated balance sheets.

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Revolving Credit Facility

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

Revolving Credit Facility

Revolving Credit Facility

On September 28, 2017, REP LLC entered into a credit agreement (the "Credit Agreement") to establish a senior secured revolving credit facility with a syndicate of banks including SunTrust Bank, now Truist Bank as successor by merger, as administrative agent. The revolving credit facility had an initial borrowing base of $25 million with a maximum facility amount of $500 million. In both April and October 2022, the Company amended its Credit Agreement to, among other things, increase the borrowing base to $225 million. The Credit Agreement is set to mature in April 2026. Substantially all of the Company’s assets are pledged to secure the revolving credit facility.

The borrowing base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. During these redetermination periods, the Company’s borrowing base may be increased or may be reduced in certain circumstances. The revolving credit facility allows for SOFR Loans and Base Rate Loans (each as defined in the Credit Agreement). The interest rate on each SOFR Loan will be the adjusted Term SOFR for the applicable interest period plus a margin between 2.75% and 3.75% (depending on the borrowing base utilization percentage). The annual interest rate on each Base Rate Loan will be the Base Rate for the applicable interest period plus a margin between 1.75% and 2.75% (depending on the borrowing base utilization percentage). The Company is also subject to an unused commitment fee of between 0.375% and 0.500% (depending on the borrowing base utilization percentage).

The Credit Agreement contains certain covenants, which, among other things, require the maintenance of (i) a total leverage ratio of not more than 3.25 to 1.0 and (ii) a minimum current ratio of not less than 1.0 to 1.0 as of the last day of any quarter. The Credit Agreement also contains a total leverage ratio for Restricted Payments, as defined in the Credit Agreement, after giving pro forma effect to such Restricted Payments, which includes payments to any holder of the Company's shares, would not exceed 2.50 to 1.0. If the Company's leverage ratio, after giving pro forma effect to such Restricted Payments (as defined in the Credit Agreement), is above 2.0 to 1.0, then an additional test of free cash flow is applied, and the Company will only be permitted to make such Restricted Payments if such payment does not exceed the Company's free cash flow. The Company is also required to limit its cash balance to less than $15 million or 10% of the borrowing base, whichever is greater. If the Company's cash balance exceeds this limit on the last business day of the month, the Company will be required to apply the excess to reduce its credit facility borrowings. The Credit Agreement also contains other customary affirmative and negative covenants and events of default. The Company's minimum hedging requirement is between 0% and 50% (depending on the borrowing base utilization percentage and leverage ratio as of the hedge evaluation date) of its proved developed producing ("PDP") volumes on a rolling 24-month basis. As of December 31, 2022, the Company's minimum hedging requirement was 0%.

The following table summarizes the Company's interest expense:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Interest expense(1)	$	864	$	512	$	3,686
Capitalized interest	(1,022)		$	—	—
Amortization of deferred financing costs	731		282		653
Unused commitment fees	517		102		195
Total interest expense, net	$	1,090	$	896	$	4,534

_____________________

(1)In December 2022, the Company settled the remaining open positions for the interest rate swap which resulted in a $1.5 million settlement. The Company recognizes settlements on its interest rate swaps in interest expense on the consolidated statements of operations.

As of December 31, 2022 and 2021, the weighted average interest rate on outstanding borrowings under the revolving credit facility was 7.17% and 3.10%, respectively.

As of December 31, 2022 and 2021, the Company was in compliance with all covenants contained in the Credit Agreement and had $56 million and $65 million, respectively, of outstanding borrowings and $169 million and $110 million, respectively, available under the borrowing base.

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Members’/Shareholders' Equity

12 Months Ended

Dec. 31, 2022

Equity [Abstract]

Members’/Shareholders' Equity

Members’/Shareholders' Equity

Public Offering of Common Stock

On June 30, 2021, the Company entered into an Underwriting Agreement (the "Underwriting Agreement") with Truist Securities, Inc., as the representative of the other several underwriters named in the Underwriting Agreement. On July 2, 2021, the Company issued 1,666,667 shares of common stock at a price to the public of $30.00 per share in accordance with the Underwriting Agreement. Net proceeds from the issuance were approximately $46.7 million, after deducting the underwriting fees and other offering costs incurred.

Dividends

Cash dividends for the periods presented were declared for all issued and outstanding common shares or units, including vested and unvested under the respective Long-Term Incentive Plan in effect during the period of dividend declaration. The portion of the cash attributable to the unvested restricted shares issued under the 2021 Long-Term Incentive Plan ("2021 LTIP") is included in accrued liabilities on the consolidated balance sheet and will be paid in cash once the unvested restricted shares fully vest. Any accrued but unpaid cash dividends attributable to the unvested restricted shares issued under the 2018 Long-Term Incentive Plan ("2018 LTIP") was paid in accordance with the Merger Agreement immediately prior to consummation of the Merger. See Note 9 - Revolving Credit Facility for discussion over the Company's restrictions on certain payments, including dividends.

The table below summarizes the following cash distributions declared to common shareholders and unitholders during the periods presented below:

Quarter Ended	Per Share/Unit Distribution(1)		Total Distribution
			(In millions)
2022
December 31, 2022	$	0.34	$	6.7
September 30, 2022	$	0.31	$	6.2
June 30, 2022	$	0.31	$	6.2
March 31, 2022	$	0.31	$	6.2
2021
December 31, 2021	$	0.31	$	6.2
September 30, 2021	$	0.28	$	5.5
June 30, 2021	$	—	$	—
March 31, 2021(2)	$	0.29	$	8.8
2020
December 31, 2020	$	0.30	$	3.8

_____________________

(1)Per unit amounts for dividends declared before the Closing Date of the Merger have been effected by giving adjustment to the 1-for-12 reverse stock split and exchange ratio of 97.796467.

(2)On February 4, 2021, the Board of Managers of REP LLC declared a $3.8 million cash dividend, paid on February 5, 2021. On March 4, 2021, the Board of Directors of the Company declared a cash dividend of $0.28 per share or $5.0 million total, paid on May 7, 2021.

Share-Based and Unit-Based Compensation

In connection with the Merger, the Company shareholders adopted an omnibus equity incentive plan, the 2021 LTIP, for the employees, consultants and the directors of the Company and its affiliates who perform services for the Company. The holders of unvested restricted units issued under the 2018 LTIP were issued substitute awards under the 2021 LTIP at the closing of the Merger. Upon the closing of the Merger and after giving effect to the adjustment resulting from the one-for-twelve reverse stock split, the 2021 LTIP had 1,387,022 shares of common stock available for issuance, of which 440,784 shares remained available as of December 31, 2022.

2021 Long-Term Incentive Plan

The 2021 LTIP will provide for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws ("ISO's:); (ii) stock options that do not qualify as incentive stock options; (iii) stock appreciation rights, or SARs; (iv) restricted stock awards; (v) restricted stock units, or RSUs; (vi) stock awards; (vii) performance awards; (viii) dividend equivalents; (ix) other stock-based awards; (x) cash awards; and (xi) substitute awards, all of which will collectively be referred to as the "Awards".

The 2021 LTIP authorizes the Compensation Committee to administer the plan and designate eligible persons as participants, determine the type or types of Awards to be granted to an eligible person, determine the number of shares of stock or amount of cash to be covered by the Awards, approve the forms of award agreements for use under the plan, determine the terms and conditions of any Award, modify, waive or adjust any term or condition of an Award that has been granted, among other responsibilities delegated by the Company's Board.

Restricted Shares: The Company granted 367,420, 174,575, and 397,739 restricted shares to executives, employees and independent directors of the Company during the year ended December 31, 2022, three months ended December 31, 2021, and year ended September 30, 2021, respectively. The holder of these restricted shares receive dividends, in arrears, once the shares vest. The Company has accrued for these dividends which are reported in accrued liabilities and other non-current liabilities.

All restricted shares granted have a service period between 3 and 36 months. The Company estimates the fair values of the restricted shares as the closing price of the Company's common stock on the grant date of the award, with the expense amortized on a straight-line basis and recognized over the vesting period.

The following table presents the Company's restricted stock activity during the year ended December 31, 2022 under the 2021 LTIP:

2021 Long-Term Incentive Plan
	Restricted Shares	Weighted Average Grant Date Fair Value(1)
Unvested at December 31, 2021	366,789	$	19.41
Granted	367,420	$	17.63
Vested	(192,899)	$	19.25
Forfeited	(5,101)	$	23.46
Unvested at December 31, 2022	536,209	$	18.39

_____________________________________________________

(1) For the three months ended December 31, 2021, the Company granted 174,575 restricted shares at a weighted average grant date fair value of $23.46. For the year ended September 30, 2021, the Company granted 397,739 restricted shares at a weighted average grant date fair value of $21.16.

For the year ended December 31, 2022, the three months ended December 31, 2021, and year ended September 30, 2021, the total equity-based compensation expense is $3.9 million, $0.9 million, and $6.1 million, respectively, for all periods and is included in general and administrative costs on the Company's consolidated statement of operations for the restricted share awards granted under the 2021 LTIP. At the time of the forfeiture, the Company will recognize any forfeited shares as a reduction to share-based compensation expense on the consolidated statement of operations and a decrease to shareholders' equity on the consolidated balance sheet. Any unpaid dividends on forfeited shares will be recognized as a decrease to accrued liabilities and an increase to shareholders' equity on the consolidated balance sheet. Approximately $8.3 million of additional equity-based compensation expense will be recognized over the weighted average life of 28 months for the unvested restricted share awards as of December 31, 2022 granted under the 2021 LTIP.

2018 Long-Term Incentive Plan

In connection with the Merger and in accordance with the Merger Agreement, each unvested restricted unit outstanding under the 2018 LTIP was converted into restricted shares of the Company under the 2021 LTIP. The holders of unvested restricted units issued under the 2018 LTIP were issued substitute awards under the 2021 LTIP at the closing of the Merger.

The Company granted 13,309 restricted units to executives and employees of the Company during the year ended September 30, 2021. Total unit-based compensation expense of $0.7 million is for all of the issuances outstanding during the period of January 2021 through the date of the merger, February 26, 2021. Unit-based compensation expense is included in general and administrative costs on the Company's consolidated statement of operations.

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Income Taxes

12 Months Ended

Dec. 31, 2022

Income Tax Disclosure [Abstract]

Income Taxes

Income TaxesREP LLC was organized as a limited liability company and treated as a flow-through entity for federal income tax purposes. As such, taxable income and any related tax credits were passed through to its members and included in their tax returns, even though such taxable income or tax credits may not have been distributed. In connection with the closing of the Merger, the Company's tax status changed from a limited liability company to a C-corporation. As a result, the Company is responsible for federal and state income taxes and must record deferred tax assets and liabilities for the tax effects of any temporary differences that exist on the date of the change. When push down accounting does not apply as part of a business combination, U.S. GAAP requires the effect of the change in tax status to be recognized in the financial statements and the effect is included in income (loss) from continuing operations. Upon consummation of the Merger, the Company established a $13.6 million provision for deferred income taxes with the conversion to a C-corporation. Accordingly, a provision for federal

and state corporate income taxes has been made for the operations of REP LLC only from February 27, 2021 through December 31, 2022 in the accompanying consolidated financial statements.

The components of the Company's consolidated provision for income taxes from continuing operations are as follows:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Current income tax expense:
Federal	$	4,026	$	—	$	2
State	446		113		52
Total current income tax expense	$	4,472	$	113	$	54
Deferred income tax expense (benefit):
Federal	$	27,393	$	5,669	$	14,202
State	979		87		(1,240)
Total deferred income tax expense (benefit)	$	28,372	$	5,756	$	12,962
Total income tax expense (benefit)	$	32,844	$	5,869	$	13,016

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company's net deferred tax position is as follows:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Deferred tax assets
Non-cash gain on derivatives	$	3,563	$	10,286	$	11,006
Intangibles	182		215		222
Inventory	—		23		23
Share-based compensation	421		690		480
Accruals and other	484		558		578
Net operating loss	2,812		3,172		5,422
Total deferred tax assets	7,462		14,944		17,731
Oil and natural gas assets	(52,665)		(32,154)		(29,161)
Other fixed assets	(553)		(174)		(198)
Total deferred tax liabilities	(53,218)		(32,328)		(29,359)
Net deferred tax liabilities	$	(45,756)	$	(17,384)	$	(11,628)

A reconciliation of the statutory federal income tax rate to the Company's effective income tax rate is as follows:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
Tax at statutory rate	21.0	%	21.0	%	21.0	%
Nondeductible compensation	0.2	%	0.1	%	(1.0)	%
Transaction costs	—	%	—	%	(1.5)	%
Share-based compensation	—	%	(0.3)	%	(0.1)	%
State income taxes, net of federal benefit	0.7	%	0.7	%	0.4	%
Change in tax status	—	%	—	%	(40.1)	%
Income subject to taxation by REP LLC's unitholders	—	%	—	%	(17.1)	%
Other	(0.2)	%	—	%	—	%
Effective income tax rate	21.7	%	21.5	%	(38.4)	%

The Company's federal income tax returns for the years subsequent to December 31, 2018 remain subject to examination. The Company's income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2017. The Company currently believes that all other significant filing positions are highly certain and that all of its other significant income tax positions and deductions would be sustained under audit or the final resolution would not have a material effect on the consolidated financial statements. Therefore, the Company has not established any significant reserves for uncertain tax positions.

Section 382 of the Internal Revenue Code limits the utilization of U.S. net operating loss ("NOL") carryforwards following a change in control. The Merger caused a stock ownership change for purposes of Section 382 which is subject to an approximate annual limit. The Company has federal net operating losses subject to the annual Section 382 limit of $13.4 million of which $4.6 million will expire beginning in 2022 with the remaining $8.8 million of the NOL's not expiring. Additionally, the Company has no federal net operating losses generated after the Merger that are not limited by Section 382 and are not subject to expiration. We believe it is more likely than not the tax benefit of these net operating losses will be fully realized, as such no valuation allowance has been recorded. The deferred tax assets for the net operating losses are presented net with deferred tax liabilities, which primarily consist of book and tax depreciation differences.

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Discontinued Operations and Assets Held For Sale

12 Months Ended

Dec. 31, 2022

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations and Assets Held For Sale

Discontinued Operations and Assets Held For Sale

Kansas Reporting Unit

On March 10, 2021, the Company entered into a PSA to divest of the Kansas Reporting Unit for an agreed upon purchase price of $3.5 million before certain closing adjustments. In addition, the Company also agreed to assign to the buyer its lease associated with Tengasco's former corporate office in Greenwood Village, Colorado. With Tengasco qualifying as a business and the Kansas Reporting Unit making up a significant portion of the assets of Tengasco, the Company concluded that the transaction met the requirements of assets held for sale and discontinued operations upon the acquisition date. The sale closed on April 2, 2021 for an adjusted purchase price of $3.3 million, after customary closing adjustments.

The following table presents the components of the loss on discontinued operations reported in the consolidated statements of operations for the periods ended September 30, 2021:

		Year Ended
		September 30, 2021
	(In thousands)
Oil and natural gas sales		$	—
Total revenues		—
Lease operating expenses		115
Goodwill impairment		18,516
Total expenses		18,631
Other expenses		(107)
Loss from discontinued operations before income taxes		(18,738)
Income tax expense		(59)
Loss from discontinued operations, net of tax		$	(18,797)

The Company did not have any discontinued operations during the year ended December 31, 2022.

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Net Income (Loss) Per Share/Unit

12 Months Ended

Dec. 31, 2022

Earnings Per Share [Abstract]

Net Income (Loss) Per Share/Unit

Net Income (Loss) Per Share/Unit

Net income (loss) per share/unit is calculated using a retroactive application of the Exchange Ratio and the one-for-twelve reverse stock split that occurred in conjunction with the Merger. The Company calculated net income or loss per share/unit using the treasury stock method.

The table below sets forth the computation of basic and diluted net income (loss) per share/unit for the periods presented below:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands, except per share/unit)
Continuing Operations:
Net income (loss) - Diluted	$	118,011	$	21,398	$	(46,869)
Less: Dividends on preferred units	—		—		(1,491)
Net income (loss) attributable to common shareholders/unitholders - Basic(1)	$	118,011	$	21,398	$	(48,360)
Basic weighted-average common shares/units outstanding	19,553		19,470		16,021
Effecting of dilutive securities:
Restricted shares/units	133		99		—
Diluted weighted-average common shares/units outstanding	19,686		19,569		16,021
Continuing Operations:
Basic net income (loss) per common share/unit	$	6.04	$	1.10	$	(3.02)
Diluted net income (loss) per common share/unit	$	5.99	$	1.09	$	(3.02)

_____________________________________________________

(1) Used in the basic and diluted net loss per share/unit calculation when the Company is in a net loss position.

The following shares/units were excluded from the calculation of diluted net income (loss) per share/unit due to their anti-dilutive effect for the periods presented:

	Year Ended December 31, 2022	Three Months Ended December 31, 2021	Year Ended September 30, 2021
	(In thousands)
Restricted shares/units	405	268	228

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Commitment and Contingencies

12 Months Ended

Dec. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Legal Matters

The Company was named as a defendant in an adversary proceeding (the "Adversary Proceeding") commenced on October 25, 2021 in United States Bankruptcy Court for the Northern District of Texas, Dallas Division (the "Bankruptcy Court"), by the Trustee of the Chapter 7 bankruptcy of the Hoactzin Partners, L.P. ("Hoactzin"). The complaint in the Adversary Proceeding alleges that in October of 2018, one year prior to the Hoactzin bankruptcy filing in October of 2019, Peter Salas ("Salas"), Chairman of the Board of Tengasco during the period of the purported fraudulent transfers, caused Hoactzin to transfer its working interests in certain wells on its Kansas acreage (the “Kansas Working Interests”) to the Company for an amount the complaint alleges was purportedly less than the reasonable equivalent value of such Kansas Working Interests. The complaint includes avoidance actions and other causes of action in connection with the transfer of the Kansas Working Interests, as well as other causes of action alleged related to certain transactions to which the Company was not a party.

On October 13, 2022, the Company entered into a Compromise Settlement Agreement and Mutual General Release (the “Settlement Agreement”) with the Trustee for the bankruptcy estate for Hoactzin to resolve certain claims against the Company in the Adversary Proceeding. Under the terms of the Settlement Agreement, the Company agreed to pay $80 thousand to the Trustee in full settlement and satisfaction of (a) all claims, causes of action, and damages that have been asserted against the Company or could be asserted against the Company in the Adversary Proceeding; and (b) all claims which might arise from or relate to any actions taken by the Company while acting in connection with Debtor.

On November 17, 2022, the Bankruptcy Court approved the Settlement Agreement. On November 17, 2022, the Company made the settlement payment to the Trustee in accordance with the Settlement Agreement. On November 22, 2022, the Bankruptcy Court entered an Order Granting the Joint Motion Dismissal resulting in the dismissal of the Adversary Proceeding with prejudice (the "Dismissal Order"), as contemplated by the Settlement Agreement.

Neither the Settlement Agreement nor the Dismissal Order has any effect on the Trustee’s claims against any of the other defendants in the Adversary Proceeding, including without limitation, those claims against Peter Salas, our former Chief Executive Officer.

Environmental Matters

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. The Company had no material environmental liabilities as of December 31, 2022 or 2021.

Contractual Commitments

In October 2021, the Company executed two agreements related to its enhanced oil recovery ("EOR") project. The first agreement is a CO2 purchase agreement with Kinder Morgan CO2 Company, LLC that has a primary term extending through the earlier of the total contract quantity delivered or December 31, 2025. The agreement also has a daily contract quantity for Kinder Morgan to deliver CO2 to the Company. The second agreement is a connection agreement that also established a delivery point for the purchased CO2 with the Cortez Pipeline Company.

In April 2022, the Company entered into a purchase agreement for pipe related to its 2023 drilling program. Under the agreement, the Company has commitments to purchase an additional approximately $2.8 million of pipe by second quarter of 2023 as of December 31, 2022.

In August 2022, the Company entered into a second amendment on its gas gathering and processing agreement with its primary midstream counterparty, Stakeholder Midstream LLC (“Stakeholder”). Stakeholder committed to expand their gathering and processing system with a commitment from the Company to deliver an annual minimum volume to Stakeholder’s gathering system for a minimum of seven years beginning on the in-service date of the expanded plant.

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Subsequent Events

12 Months Ended

Dec. 31, 2022

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

Dividend Declaration

On January 11, 2023, the Board of Directors of the Company declared a cash dividend of $0.34 per share of common stock payable on February 8, 2023 to its shareholders of record at the close of business on January 25, 2023.

Entry into Purchase and Sales Agreement

On February 22, 2023, the Company entered into a purchase and sale agreement (the "Purchase Agreement") to acquire interests in oil and natural gas leases and related property with Pecos Oil & Gas, LLC (“Pecos”) for a purchase price of approximately $330 million, subject to customary closing adjustments, (the “New Mexico Acquisition”). The oil and natural gas leases are located in the Yeso trend of the Permian Basin in Eddy County of New Mexico. On February 22, 2023, in connection with the Purchase Agreement, REP deposited $33 million in cash into a third party escrow account, which will be credited against the purchase price upon closing.

The New Mexico Acquisition is expected to close early in the second quarter of 2023, subject to the satisfaction of several closing considerations, including but not limited to, an amendment to the revolving credit facility and a commitment letter dated February 22, 2023 with Truist Bank and the other participating lenders, it is anticipated that up to $130 million of the purchase price will be funded by amending REP’s existing credit facility to increase the total borrowing base to $475 million from $225 million. The commitment letter and related amendment to the credit facility and increase to the borrowing base are subject to a number of conditions, including the preparation, execution and delivery of loan amendments.

In connection with the Purchase Agreement, the Company entered into a commitment letter dated February 22, 2023 (the "Commitment Letter") with EOC Partners Advisors L.P. and/or one of its affiliates (collectively, “EOC”) in which EOC and/or one of its affiliates will purchase $200 million of unsecured senior notes (“Senior Notes”) from the Company on the closing date of the New Mexico Acquisition. The proceeds of the Senior Notes will be used to fund a portion of the purchase price of the New Mexico Acquisition and to pay fees, costs and expenses related to the New Mexico Acquisition and the related financing transactions. The Senior Notes will bear interest at 10.5% annually and will mature five years after issuance. The Senior Notes contain certain mandatory and voluntary prepayment conditions. Additionally, the Senior Notes have various financial covenants. The funding of the Senior Notes is contingent on the satisfaction or waiver of certain conditions set forth in the Commitment Letter.

Derivative Contracts

As discussed above, the Company entered into the Purchase Agreement to acquire assets in Eddy County New Mexico. In connection with the Purchase Agreement, the Company entered into the Commitment Letter described above for the issuance of $200 million of Senior Notes upon closing of the New Mexico Acquisition, which is subject to the terms and conditions set forth therein. The Senior Notes contain certain hedging requirements. The Company has therefore added to its open derivative contracts in anticipation of an early second quarter close on the New Mexico Acquisition and issuance of Senior Notes. The

following table summarizes the Company's open derivative positions as of March 3, 2023, related to oil and natural gas production:

		Weighted Average Price
Period(1)	Notional Volume	Fixed		Put		Call
		($ per unit)
Oil Swaps (Bbl)
Q1 2023	225,000	$	53.65	$	—	$	—
Q2 2023	315,000	$	62.78	$	—	$	—
Q3 2023	216,000	$	63.04	$	—	$	—
Q4 2023	189,000	$	62.51	$	—	$	—
2024	240,000	$	71.60	$	—	$	—
Oil Collars (Bbl)
Q1 2023	210,000	$	—	$	70.95	$	89.96
Q2 2023	300,000	$	—	$	71.50	$	88.98
Q3 2023	330,000	$	—	$	68.64	$	88.85
Q4 2023	330,000	$	—	$	68.64	$	88.85
2024	1,293,000	$	—	$	61.02	$	86.39
2025	315,000	$	—	$	60.00	$	77.98
Natural Gas Swaps (MMBtu)
Q1 2023	—	$	—	$	—	$	—
Q2 2023	450,000	$	2.60	$	—	$	—
Q3 2023	450,000	$	2.60	$	—	$	—
Q4 2023	400,000	$	3.23	$	—	$	—
2024	1,500,000	$	3.43	$	—	$	—
2025	375,000	$	4.05	$	—	$	—
Natural Gas Collars (MMBtu)
Q1 2023	—	$	—	$	—	$	—
Q2 2023	300,000	$	—	$	2.55	$	3.20
Q3 2023	300,000	$	—	$	2.55	$	3.20
Q4 2023	300,000	$	—	$	3.12	$	4.07
2024	1,065,000	$	—	$	3.19	$	4.14
2025	255,000	$	—	$	3.65	$	4.95
Oil Basis (Bbl)
Q1 2023	240,000	$	1.28	$	—	$	—
Q2 2023	360,000	$	1.28	$	—	$	—
Q3 2023	360,000	$	1.28	$	—	$	—
Q4 2023	360,000	$	1.28	$	—	$	—
2024	960,000	$	0.87	$	—	$	—

___________________

(1)Q1 2023 derivative positions shown include January and February 2023 contracts, some of which have settled as of March 3, 2023.

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Supplemental Information on Oil and Natural Gas Operations (Unaudited)

12 Months Ended

Dec. 31, 2022

Extractive Industries [Abstract]

Supplemental Information on Oil and Natural Gas Operations (Unaudited)

Supplemental Information on Oil and Natural Gas Operations (Unaudited)

Capitalized Costs

Capitalized costs include the cost of properties, equipment and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells and related equipment and facilities.

Capitalized costs for unproved properties include costs for acquiring or extending oil and natural gas leaseholds where no proved reserves have been identified. Work in progress include costs of exploratory and development wells that are in the process of drilling or in active completion, and costs of exploratory and development wells suspended or waiting on completion. For a summary of these costs, please refer to Note 5 – Oil and Natural Gas Properties.

Costs Incurred for Property Acquisition, Exploration and Development

Amounts reported as costs incurred include both capitalized costs and costs charged to expense when incurred for oil and natural gas property acquisition, exploration and development activities. Costs incurred also include new ARO established in the current year as well as increases or decreases to ARO resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells and construction of related production facilities.

The following summarizes the costs incurred for oil and natural gas property acquisition, exploration and development activities for the periods presented below:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Acquisition of properties
Proved	$	450	$	67	$	74
Unproved	1,468		193		1,562
Exploration costs	157		—		7,993
Development costs	119,673		20,348		59,948
Total costs incurred	$	121,748	$	20,608	$	69,577

Results of Operations

The following table includes revenues and expenses associated with the Company's oil and natural gas producing activities. They do not include any allocation of the Company's interest costs or general corporate overhead. Therefore, the following schedule is not necessarily indicative of the contribution of net earnings of the Company's oil and natural gas operations.

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Oil, natural gas and NGL sales	$	319,343	$	56,650	$	148,636
Lease operating expenses	32,458		7,419		21,975
Production and ad valorem taxes	19,273		3,005		8,636
Exploration costs	2,032		611		9,566
Depletion, accretion and amortization	31,500		6,742		25,347
Impairment of oil and natural gas properties	7,325		—		—
Results of operations	226,755		38,873		83,112
Income tax expense (1)	48,957		(8,393)		(13,505)
Results of operations, net of income tax expense	$	275,712	$	30,480	$	69,607

_____________________________________________________

(1)    Subsequent to the Closing Date of the Merger, the statutory combined federal and state tax rate of 21.59% is used for the year ended December 31, 2022, three months ended December 31, 2021, and year ended September 30, 2021.

Oil, Natural Gas and NGL Quantities

Our reserve reports, as of the year ended December 31, 2022, three months ended December 31, 2021, and year ended September 30, 2021, were prepared by Netherland, Sewell & Associates, Inc. and are presented below. All reserves are located within the continental United States. Proved oil, natural gas and NGL reserves are the estimated quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimate is made. Proved developed oil, natural gas and NGL reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

The following table sets forth information for the periods below with respect to changes in the Company’s proved (i.e. proved developed and undeveloped) reserves:

	Oil	Natural Gas	NGLs	Total
	(MBbl)	(MMcf)	(MBbl)	(MBoe)
September 30, 2020	37,158	53,683	10,681	56,787
Extensions and discoveries	9,308	12,089	2,436	13,759
Revisions	2,138	12,850	492	4,772
Production	(2,341)	(2,603)	(380)	(3,155)
September 30, 2021	46,263	76,019	13,229	72,163
Extensions and discoveries	1,328	1,961	371	2,026
Revisions	99	350	(24)	133
Production	(669)	(844)	(105)	(915)
December 31, 2021	47,021	77,486	13,471	73,407
Extensions and discoveries	9,949	13,178	2,651	14,796
Revisions	(4,871)	(1,417)	(1,224)	(6,331)
Production	(3,217)	(3,229)	(444)	(4,199)
December 31, 2022	48,882	86,018	14,454	77,673
Proved Developed Reserves, Included Above
September 30, 2021	26,170	46,173	7,650	41,516
December 31, 2021	27,096	47,974	7,949	43,041
December 31, 2022	29,632	59,314	9,604	49,122
Proved Undeveloped Reserves, Included Above
September 30, 2021	20,093	29,846	5,579	30,647
December 31, 2021	19,925	29,512	5,522	30,366
December 31, 2022	19,250	26,704	4,850	28,551

As of December 31, 2022, reserves were comprised of 62.9% oil, 18.5% natural gas and 18.6% NGL. 2022 proved reserves were estimated based on prices of $91.96 per Bbl of oil, $3.16 per Mcf of natural gas and $25.55 per Bbl of NGL. Prices used in the 2022 reserve report are based on the twelve month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January 2022 through December 2022. For oil and NGL volumes, the average West Texas Intermediate ("WTI") spot price of $94.14 per Bbl is adjusted for quality, transportation fees, and market differentials. The fees associated with the transportation contract are included as a deduction to oil revenue. For gas volumes, the average Henry Hub spot price of $6.36 per MMBtu is adjusted for energy content, transportation fees and market differentials.

As of December 31, 2021, reserves were comprised of 64.1% oil, 17.6% natural gas and 18.3% NGL. December 31, 2021 proved reserves were estimated based on prices of $64.60 per Bbl of oil, $1.65 per Mcf of natural gas and $13.75 per Bbl of NGL. Prices used in the December 31, 2021 reserve report are based on the twelve month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January 2021 through December 2021. For oil and NGL volumes, the average WTI spot price of $66.55 per Bbl is adjusted for quality, transportation fees, and market differentials. The fees associated with the transportation contract are included as a deduction to oil revenue. For gas volumes, the average Henry Hub spot price of $3.60 per MMBtu is adjusted for energy content, transportation fees and market differentials.

As of September 30, 2021, reserves were comprised of 64.1% oil, 17.6% natural gas and 18.3% NGL. September 30, 2021 proved reserves were estimated based on prices of $55.73 per Bbl of oil, $0.99 per Mcf of natural gas and $9.83 per Bbl of NGL. Prices used in the September 30, 2021 reserve report are based on the twelve month unweighted arithmetic average of the first-day-of-the-month price for each month in the period October 2020 through September 2021. For oil and NGL volumes, the average WTI spot price of $57.64 per Bbl is adjusted for quality, transportation fees, and market differentials. The fees associated with the transportation contract are included as a deduction to oil revenue. For gas volumes, the average Henry Hub spot price of $2.94 per MMBtu is adjusted for energy content, transportation fees and market differentials.

For the year ended December 31, 2022, the Company had downward revisions of previous estimates of 6,331 MBoe. These revisions are primarily the result of changes in well level projections in certain undeveloped areas and increases in service costs. The Company had extensions and discoveries to proved developed and proved non-developed reserves of 14,796 MBoe which consisted of 7,759 MBoe as a result of drilling successful wells that were previously classified as unproved locations, and the addition to proved undeveloped of 7,037 MBoe as a result of drilling successful wells offsetting locations that were previously unproven locations. During the fiscal year in 2022, the Company did not purchase any additional reserves.

For the three months ended December 31, 2021, the Company had net upward revisions of previous estimates of 133 MBoe. These revisions are primarily the result of increases in pricing. The Company had extensions and discoveries to proved developed and proved non-developed reserves of 2,026 MBoe as a result of drilling successful wells that were previously classified as unproved locations. During the three months ended December 31, 2021, the Company did not purchase any additional reserves.

For the year ended September 30, 2021, the Company had upward revisions of previous estimates of 4,772 MBoe. These revisions are primarily the result of increases in pricing. The Company had extensions and discoveries to proved developed and proved non-developed reserves of 13,759 MBoe which consisted of 6,564 MBoe as a result of drilling successful wells that were previously classified as unproved locations, and the addition to proved undeveloped of 7,195 MBoe as a result of drilling successful wells offsetting locations that were previously unproven locations. During the year ended September 30, 2021, the Company did not purchase any additional reserves.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves

The Company follows the guidelines prescribed in ASC Topic 932 Extractive Activities – Oil and Gas for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following summarizes the policies used in the preparation of the accompanying oil, natural gas and NGL reserve disclosures, standardized measures of discounted future net cash flows from proved oil, natural gas and NGL reserves and the reconciliations of standardized measures from year to year.

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (i) estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions; (ii) estimated future cash flows are compiled by applying the twelve month average of the first of the month prices of crude oil and natural gas relating to the Company’s proved reserves to the year-end quantities of those reserves for reserves; (iii) future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions, plus Company overhead incurred; (iv) future income tax expenses are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and natural gas properties, other deductions, credits and allowances relating to the Company’s proved oil and natural gas reserves; and, (v) future net cash flows are discounted to present value by applying a discount rate of 10%.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the Securities and Exchange Commission. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations, since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

The following summary sets forth the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure prescribed in ASC Topic 932:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Future crude oil, natural gas and NGLs sales (1)(2)(3)	$	5,135,650	$	3,350,506	$	2,783,910
Future production costs	(1,559,266)		(912,468)		(839,167)
Future development costs	(341,481)		(216,138)		(218,765)
Future income tax expense	(658,340)		(436,829)		(324,487)
Future net cash flows	2,576,563		1,785,071		1,401,491
10% annual discount	(1,468,187)		(1,081,602)		(848,555)
Standardized measure of discounted future net cash flows	$	1,108,376	$	703,469	$	552,936

_____________________________________________________

(1)    December 31, 2022 proved reserves were derived based on prices of $91.96 per barrel of oil, $3.16 per Mcf of natural gas and $25.55 per barrel of NGL.

(2)    December 31, 2021 proved reserves were derived based on prices of $64.60 per barrel of oil, $1.65 per Mcf of natural gas and $13.75 per barrel of NGL.

(3)    September 30, 2021 proved reserves were derived based on prices of $55.73 per barrel of oil, $0.99 per Mcf of natural gas and $9.83 per barrel of NGL.

Principal sources of change in the Standardized Measure are shown below:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Balance, beginning of period	$	703,469	$	552,936	$	302,338
Sales of crude oil, natural gas and NGLs, net	(267,612)		(46,226)		(118,030)
Net change in prices and production costs	406,803		194,596		237,475
Net changes in future development costs	(40,226)		1,267		(18,856)
Extensions and discoveries	321,009		35,111		144,392
Revisions of previous quantity estimates	(83,188)		(536)		50,283
Previously estimated development costs incurred	8,775		4,182		12,844
Net change in income taxes	(117,098)		(47,881)		(124,625)
Accretion of discount	87,914		17,018		30,551
Other	88,530		(6,998)		36,564
Balance, end of period	$	1,108,376	$	703,469	$	552,936

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

Consolidation

The accompanying consolidated financial statements include the accounts of Riley Permian and its wholly owned subsidiaries REP LLC, Riley Permian Operating Company, LLC ("RPOC"), Tengasco Pipeline Corporation, Tennessee Land & Mineral Corporation, and Manufactured Methane Corporation, and have been prepared in accordance with accounting principles generally accepted in the United States ("U.S. GAAP"). All intercompany balances and transactions have been eliminated upon consolidation. The Merger was accounted for as a reverse merger and, as such, the historical operations of REP LLC are deemed to be those of the Company. Thus, the consolidated financial statements included in this report reflect (i) the historical operating results of REP LLC prior to the Merger; (ii) the consolidated results of the Company following the Merger; (iii) the assets and liabilities of REP LLC at their historical cost; and (iv) the Company’s equity and earnings per share for all periods presented.

Reclassification

Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had an immaterial effect on the previously reported total assets, total liabilities, members'/shareholders' equity, results of operations or cash flows

Significant Estimates

Significant Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, accounts receivable, accrued capital expenditures and operating expenses, asset retirement obligations ("ARO"), the fair value determination of acquired assets and assumed liabilities, certain tax accruals and the fair value of derivatives.

Cash and Cash Equivalents

Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. The Company maintains cash at financial institutions which may at times exceed federally insured amounts. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on its cash and cash equivalents.

Accounts Receivable

Accounts Receivable

Our receivables arise primarily from the sale of oil, natural gas and NGLs and joint interest owner receivables for properties in which we serve as the operator. Accounts receivable are stated at amounts due, net of an allowance for credit losses, if necessary.

Accounts receivable from oil, natural gas and NGL sales are generally due within 30 to 60 days after the last day of each production month. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items.

To the extent actual volumes and prices of oil, natural gas and NGLs are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balance sheets. Oil is priced based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Natural gas pricing provisions are tied to a market index, with certain adjustments based on, among other factors, quality and heat content of natural gas, and prevailing supply and demand conditions. NGLs are priced based upon a market index with certain adjustments for transportation and fractionation. These market indices are determined on a monthly basis.

The Company estimates uncollectible amounts based on the length of time that the accounts receivable has been outstanding, historical collection experience and current and future economic and market conditions, if failure to collect is expected to occur. Allowances for credit losses are recorded as reductions to the carrying values of the accounts receivables included in the Company’s consolidated balance sheets and are recorded in Administrative costs in the consolidated statements of operations if failure to collect an estimable portion is determined to be probable.

Inventory

Inventory

The Company's inventory represents tangible assets such as drilling pipe, tubing, casing and operating supplies used in the Company's future drilling or repair operations. The Company accounts for its inventory using the first-in, first-out method and valued at the lower of cost or net realizable value.

Proved Oil and Natural Gas Properties, Unproved Oil and Natural Gas Properties and Impairment of Oil and Natural Gas Properties

Proved Oil and Natural Gas Properties

The Company uses the successful efforts method of accounting for its oil and natural gas producing activities. Under this method, all property acquisition costs and costs of development wells are capitalized as incurred. The costs of development wells are capitalized whether producing or non-producing. Costs to drill exploratory wells are capitalized pending the determination of whether proved reserves are found. If an exploratory well is determined to be unsuccessful, the costs of drilling the unsuccessful exploratory well are charged to exploration costs.

Geological and geophysical costs, including seismic studies, are charged to exploration costs as incurred. Expenditures incurred to operate and for maintenance, repairs and minor renewals necessary to maintain our oil and natural gas properties in operating condition are charged to lease operating expenses as incurred.

Capitalized costs of proved oil and natural gas properties are amortized using the units-of-production method based on production and estimates of proved reserve quantities. Leasehold acquisition costs of proved properties are depleted over total estimated proved reserves, and capitalized development costs of wells and related equipment and facilities are depleted over-estimated proved developed reserves.

On the sale or retirement of a complete unit of a proved property or field, the cost and related accumulated depletion, depreciation and amortization are eliminated from the oil and natural gas property accounts, and the resulting gain or loss is recognized. On the sale of a partial unit of proved property, the unamortized cost of the property is apportioned to the interest sold and the interest retained is accounted for on the basis of the fair value of the retained interests and a gain or loss is recognized if the divestiture significantly affects the depletion rate.

Unproved Oil and Natural Gas Properties

Unproved oil and natural gas properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we charge the associated unproved lease acquisition costs to exploration costs. Lease acquisition costs related to successful drilling are reclassified to proved oil and natural gas properties.

Upon the sale of an entire interest in an unproved property for cash or cash equivalents, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from the sale of partial interests in unproved oil and natural gas properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.

Impairment of Oil and Natural Gas Properties

The cost of proved oil and natural gas properties are assessed on a field-by-field basis for impairment at least annually or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The expected undiscounted future cash flows of the oil and natural gas properties are compared to the carrying amount of the oil, natural gas and NGL properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the carrying amount of the oil and natural gas properties is adjusted to estimated fair value. Assumptions associated with discounted cash flow models or valuations used in the impairment evaluation include estimates of

future oil, natural gas and NGL prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. Unproved oil and natural gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. See further discussion in Note 7 - Fair Value Measurements.

Business Combinations

Business Combinations

In accordance with ASC 805 - Business Combinations, the Company accounts for its acquisitions that qualify as a business using the acquisition method. If the set of assets and activities acquired is not considered a business, it is accounted for as an asset acquisition using a cost accumulation model. In the cost accumulation model, the cost of the acquisition, including certain transaction costs, is allocated to the assets acquired on the basis of relative fair values.

The Company includes the results of operations of acquired businesses beginning on the respective acquisition dates. In accordance with the acquisition method, the Company allocates the purchase price of an acquired business to its identifiable assets and liabilities based on the estimated fair values. Transaction costs related to the business combination are expensed as incurred. This fair value measurement is based on unobservable (Level 3) inputs. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. The excess value of the net identifiable assets and liabilities acquired over the purchase price of an acquired business, if any, is recorded as a bargain purchase gain.

Other Property and Equipment, Net

Other Property and Equipment, Net

Property and equipment are capitalized and recorded at cost, while maintenance and repairs are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 5 to 39 years. Capitalized costs related to leasehold improvements are depreciated over the life of the lease. As of December 31, 2022 and 2021, the Company had capitalized property and equipment costs of $5.3 million and $3.6 million, respectively, with $2.0 million and $1.7 million, respectively, of accumulated depreciation on the consolidated balance sheet. Components of other property and equipment consists of computer equipment, office furniture, tools and equipment, buildings and improvements, and vehicles.

Land purchases are accounted for at cost and are not depreciated. As of December 31, 2022 and 2021, the Company had capitalized land costs of $16.7 million and $1.3 million, respectively, on the consolidated balance sheet.

Deferred Financing Costs

Deferred Financing Costs

Deferred financing costs include origination, arrangement, legal and other fees to issue or amend the terms of credit facility agreements. These deferred financing costs are reported as other non-current assets and recognized on the consolidated statement of operations as interest expense by amortizing the costs over the related financing using the straight-line method, which approximates the effective interest method.

Equity Issuance Cost

Equity Issuance Costs

Equity issuance costs include underwriter, legal, accounting, printing and other fees to issue common equity securities. These issuance costs are netted against offering proceeds at the time of issuance and are reported as other non-current assets when related to the issuance of common equity securities. The issuance costs are expensed to the consolidated statement of operations if the issuance is unsuccessful.

Asset Retirement Obligations

Asset Retirement Obligations

ARO consist of future plugging and abandonment expenses on oil and natural gas properties. The fair value of the ARO is recorded as a liability in the period in which wells are drilled with a corresponding increase in the carrying amount of oil and natural gas properties. The liability is accreted for the change in its present value each period and the capitalized cost is depreciated using the units-of-production method. The asset and liability are adjusted for changes resulting from revisions to the timing or the amount of the original estimate when deemed necessary. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Goodwill

Goodwill

Goodwill represents the future economic benefit arising from other assets acquired in a business combination that are not individually identified or separately recognized. Goodwill is initially recognized as the excess of the purchase price of a business combination over the fair value of the net assets acquired and is tested for impairment annually in accordance with ASC 350 - Intangibles - Goodwill and Other, or more frequently if there is a change in events or circumstances that indicate the carrying value of the goodwill may not be recoverable.

The impairment test should occur at the reporting unit level determined by the Company and an impairment should only exist if the Company has determined the carrying value of the goodwill no longer exceeds the implied fair value. If the Company determines it is more likely than not the fair value of the reporting unit is less than its carrying value, including goodwill, then a quantitative assessment is necessary. An impairment loss is recognized if the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill.

Revenue Recognition

Revenue Recognition

Oil Sales

Under the Company’s oil sales contracts, oil that is produced by the Company is delivered to the purchaser at a contractually agreed-upon delivery point at which point the purchaser takes custody, title and risk of loss of the product. Once control has been transferred, the purchaser transports the product to a third party and receives market-based prices from the third party. The Company receives a percentage of proceeds received by the purchaser less transportation costs in accordance with the pricing provisions in the Company's contracts. As transportation costs are incurred after the transfer of control, the costs are included in oil and natural gas sales and represent part of the transaction price of the contract. The pricing provisions also provide quantity requirements and grade and quality specifications. The Company recognizes revenue at the net price received when control transfers to the purchaser.

Natural Gas and NGL Sales

Under the Company’s natural gas gathering and processing contracts, natural gas is delivered to the purchaser at the inlet of the purchasers' gathering system, at which point title and risk of loss is transferred to the purchaser. The purchaser gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of natural gas and NGLs in accordance

with the pricing provisions of the Company's contracts. As the gathering, processing and transportation activities occur after the transfer of control, these costs are netted against our oil and natural gas sales and represent part of the transaction price of the contract, and may exceed the sales price. The pricing provisions also provide quantity requirements and grade and quality specifications. The Company recognizes revenue on a net basis for amounts expected to be received from third party customers through the marketing process.

Transaction Price Allocated to Remaining Performance Obligations

Based on the Company’s current product sales contracts, with contract terms ranging from one to ten years, each unit of production is considered a separate performance obligation and therefore future production volumes are wholly unsatisfied and do not require allocation or disclosure of the transaction price to remaining performance obligations.

Contract Balances

Under the Company’s product sales contracts, the Company has the right to invoice customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606.

Prior-Period Performance Obligations

Revenue is recorded in the month in which production is delivered to the purchaser. However, certain settlement statements for oil, natural gas and NGLs may not be received for thirty to ninety days after the date production is delivered and, as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences identified between the Company’s revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2022, the three months ended December 31, 2021, and year ended September 30, 2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Contract Services with Related Parties

Contract Services with Related Parties

The Company has contracts with related parties to provide certain contract operating, accounting and back-office support services. Revenue related to these contract services is recognized over time as the services are rendered, and the fee is stated within the contract at a fixed monthly rate. Costs directly attributable to performing these services are also recognized as the services are rendered. Refer to Note 8 - Transactions with Related Parties for a more detailed discussion regarding these contracts.

Revenue Payable

Revenue Payable

For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds that the Company has not yet distributed to other revenue and royalty owners are reflected as revenue payable in the consolidated balance sheets.

Lease Operating Expenses

Lease Operating Expenses

Lease operating costs, including payroll for field personnel, saltwater disposal, electricity, generator rentals, diesel fuel and other operating expenses, are expensed as incurred and included in lease operating expenses in our consolidated statements of operations.

Income Taxes

Income Taxes

The Company uses the asset and liability method of accounting for income taxes, which requires the establishment of deferred tax accounts for all temporary differences between: (i) financial reporting and tax bases of assets and liabilities, using currently enacted federal and state income tax rates, and (ii) operating loss and tax credit carryforwards. In addition, deferred tax accounts must be adjusted to reflect new rates if enacted into law.

Realization of deferred tax assets is contingent on the generation of future taxable income. As a result, management considers whether it is more likely than not that all or a portion of such assets will be realized during periods when they are available, and if not, management provides a valuation allowance for amounts not likely to be recognized.

Interest Expense

Interest ExpenseWe have financed a portion of our working capital requirements, capital expenditures and certain acquisitions with borrowings under our revolving credit facility. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Interest expense in the consolidated statements of operations reflects interest less amounts allocated to capital expenditures, unused commitment fees paid to our lender, interest rate swap settlements plus the amortization of deferred financing costs (including origination and amendment fees).

Concentrations of Credit Risk

Concentrations of Credit Risk

Our customer concentration may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry.

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, 2022, the three months ended December 31, 2021, and the year ended September 30, 2021, one purchaser accounted for 89%, 87%, and 87%, respectively, of our revenue purchased, with two end customers each accounting for more than 10% of the purchased revenue. During such periods, no other purchaser accounted for 10% or more of our revenues. The loss of this purchaser could materially and adversely affect our revenues in the short-term. However, the end customers include companies with lower credit risk. Further, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of any of our purchasers would not have a long-term material adverse effect on our financial condition and results of operations because oil, natural gas and NGLs are marketable products with well-established markets.

We manage credit risk related to accounts receivable through credit approvals, escrow accounts and monitoring procedures. Accounts receivable are generally not collateralized. However, we routinely assess the financial strength of our customers and, based upon factors surrounding the credit risk, establish an allowance for uncollectible accounts, if required. As a result, we believe that our accounts receivable credit risk exposure beyond such allowance is limited.

Environmental and Other Issues

Environmental and Other Issues

We are engaged in oil and natural gas exploration and production and may become subject to certain liabilities as they relate to environmental cleanup of well sites or other environmental restoration procedures. In connection with our acquisition of existing or previously drilled well bores, we may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental cleanup or restoration, we would be responsible for curing such a violation.

We account for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated.

Fair Value Measurements

Fair Value Measurements

Certain financial instruments are reported at fair value on our consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost). These approaches are considered Level 3 in the fair value hierarchy.

The carrying values of financial instruments comprising cash and cash equivalents, payables, receivables, related party accounts receivable/payable and advances from joint interest owners approximate fair values due to the short-term maturities of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value reported for the revolving credit facility approximates fair value because the underlying instruments are at interest rates which approximate current market rates and is considered Level 3 in the fair value hierarchy. Assets and liabilities accounted for at fair value on a non-recurring basis in accordance with the fair value hierarchy include the initial recognition of asset retirement obligations, the fair value of oil and natural gas properties, and goodwill when acquired in a business combination or assessed for impairment and are considered Level 3 in the fair value hierarchy.

Derivative Contracts

Derivative Contracts

We report the fair value of derivatives on the consolidated balance sheets in derivative assets and derivative liabilities as either current or non-current based on the timing of the settlement of individual trades. Trades that are scheduled to settle in the next twelve months are reported as current. The Company nets derivative assets and liabilities, in the consolidated balance sheets, whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract.

For the year ended December 31, 2022, the three months ended December 31, 2021, and year ended September 30, 2021, we have not designated our derivative contracts as hedges for accounting purposes, and therefore changes in the fair value of derivatives are recognized in earnings. Cash settlements of contracts are included in cash flows from operating activities in the consolidated statement of cash flows. Derivative contracts are settled on a monthly basis.

The fair value of the derivatives is established using index prices, volatility curves and discount factors. The value we report in our consolidated financial statements is as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors.

The use of derivatives involves the risk that the counterparties to such contracts will be unable to meet their obligations under the terms of the agreement. To minimize the credit risk with derivative instruments, it is our policy to enter into derivative contracts primarily with counterparties that are financial institutions that are also lenders within our revolving credit facility. Under the terms of the current counterparties' contracts, only those that are lenders under our revolving credit facility

are secured by the same collateral as outlined in our revolving credit facility. The counterparties are not required to provide credit support to the Company. See further discussion in Note 6 – Derivative Instruments.

Leases

Leases

The Company's current leases include office space and information technology equipment, comprised primarily of printers and copiers. The Company reviews all contracts to determine if a lease exists at contract inception. A lease exists when the Company has the right to obtain substantially all of the economic benefit of a specific asset and to control the use of that asset over the term of the agreement. Identified leases are classified as an operating or finance lease, which determines the recognition, measurement and presentation of expenses. As of December 31, 2022, the Company did not have any finance leases. Operating leases are capitalized on the consolidated balance sheet at commencement through a lease right-of-use ("ROU") asset and lease liability representing the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset includes any lease payments made to the lessor prior to lease commencement less any lease incentives and initial direct costs incurred. Options to extend or terminate leases are included in the lease term when it is reasonably certain the Company will exercise the option. For operating leases, lease costs are recognized on a straight-line basis over the term of the lease.

The present value of operating lease payments and amortization of the lease liability is calculated using a discount rate. When available, the Company uses the rate implicit in the lease as the discount rate; however, most of the Company’s leases do not provide a readily determinable implicit rate. In such cases, the Company is required to use its incremental borrowing rate ("IBR"). The Company’s IBR reflects the estimated rate of interest that the Company would pay to borrow on a collateralized basis over a similar term and amount equal to the lease payments in a similar economic environment. The Company is required to reassess the discount rate for any new and modified lease contracts as of the lease effective date. The weighted-average discount rate was 3.18% and 5.17%, respectively, at December 31, 2022 and 2021. The weighted average remaining lease term was 2.4 years and 0.5 years, respectively, at December 31, 2022 and 2021. Lease expense was $0.5 million, $0.1 million, and $0.4 million, respectively, for the year ended December 31, 2022, the three months ended December 31, 2021, and year ended September 30, 2021.

	December 31, 2022		December 31, 2021
	(In thousands)
ROU asset	$	1,370	$	208
Current lease liability	$	539	$	212
Long-term lease liability	$	838	$	—

The ROU asset and current lease liability was included in other non-current assets and other current liabilities and non-current lease liabilities, respectively, on the accompanying consolidated balance sheets. Lease expense for the Company was included in general and administrative costs on the accompanying consolidated statements of operations.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements

In December 2019, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2019-12, "Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes." This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance and is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company adopted this ASU effective October 1, 2021. The adoption of this ASU did not have a material impact on the Company's consolidated financial statements.

In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (“ASU 2020-04”), which provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates (e.g., London Interbank Offered Rate ("LIBOR")) that are expected to be discontinued. ASU 2020-04 allows, among other things, certain contract modifications, such as those within the scope of Topic 470 on debt, to be accounted for as a continuation of the existing contract. The Company adopted this ASU effective concurrent with the amendment of the Company's revolving credit facility in April 2022. See Note 9 - Revolving Credit Facility for additional information on the amendment of the revolving credit facility. The adoption of this ASU did not have a material impact on the Company's consolidated financial statements.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

Schedule of Accounts Receivable

Accounts receivable is summarized below:

	December 31, 2022		December 31, 2021
	(In thousands)
Oil, natural gas and NGL sales	$	24,136	$	17,562
Joint interest accounts receivable	793		409
Other accounts receivable	622		31
Total accounts receivable	$	25,551	$	18,002

Schedule of Other Non-current Assets, Net

Other non-current assets consisted of the following:

	December 31, 2022		December 31, 2021
	(In thousands)
Deferred financing costs, net	$	2,556	$	1,345
Prepayments to outside operators	186		690
Right of use assets	1,370		208
Other deposits	63		50
Total other non-current assets, net	$	4,175	$	2,293

Schedule of Accrued Liabilities

Accrued liabilities consisted of the following:

	December 31, 2022		December 31, 2021
	(In thousands)
Accrued capital expenditures	$	16,744	$	5,618
Accrued lease operating expenses	4,607		2,534
Accrued general and administrative costs	2,286		3,404
Accrued inventory	6,235		—
Accrued ad valorem tax	3,789		705
Other accrued expenditures	1,921		613
Total accrued liabilities	$	35,582	$	12,874

Schedule of Asset Retirement Obligations

Components of the changes in ARO consisted of the following and is shown below:

	December 31, 2022		December 31, 2021
	(In thousands)
ARO, beginning balance	$	2,453	$	2,434
Liabilities incurred	358		56
Revision of estimated obligations	326		—
Liability settlements and disposals	(178)		(58)
Accretion	79		21
ARO, ending balance	3,038		2,453
Less: current ARO(1)	(314)		(192)
ARO, long-term	$	2,724	$	2,261

_____________________

(1)Current ARO is included within other current liabilities on the accompanying consolidated balance sheets.

Summary of Disaggregation of Revenue

The following table presents oil and natural gas sales disaggregated by product:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Oil and natural gas sales:
Oil	$	298,723	$	50,623	$	136,421
Natural gas	10,755		2,705		7,500
Natural gas liquids	9,865		3,322		4,715
Total oil and natural gas sales, net	$	319,343	$	56,650	$	148,636

Schedule of Assets And Liabilities, Lessee

	December 31, 2022		December 31, 2021
	(In thousands)
ROU asset	$	1,370	$	208
Current lease liability	$	539	$	212
Long-term lease liability	$	838	$	—

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Acquisitions (Tables)

12 Months Ended

Dec. 31, 2022

Business Combination and Asset Acquisition [Abstract]

Schedule of Business Acquisitions, by Acquisition

The following table summarizes the consideration for the Merger (presented in thousands, except stock price):

Tengasco common stock price	$	29.64
Tengasco common stock - issued and outstanding as of February 26, 2021	891
Total consideration	$	26,392

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed based on their fair values on February 26, 2021 (in thousands):

Assets
Cash and cash equivalents	$	860
Accounts receivable	325
Prepaid and other current assets	759
Total current assets	1,944
Oil and gas properties	4,525
Other property and equipment	91
Right of use assets	42
Other non-current assets	4
Deferred tax assets	2,987
Total assets acquired	$	9,593
Liabilities
Accounts payable	$	130
Accrued liabilities	409
Current lease liabilities, operating	42
Current lease liabilities, financing	68
Total current liabilities	649
Asset retirement obligations	1,565
Total liabilities assumed	2,214
Net identifiable assets acquired	7,379
Goodwill	19,013
Net assets acquired	$	26,392

Schedule of Business Acquisition, Pro Forma Information

The following unaudited pro forma combined results for the year ended September 30, 2021 reflect the consolidated results of operations of the Company as if the Merger had occurred on October 1, 2019. Subsequent to the Merger, the Company changed its fiscal year period from October 1st through September 30th each year to January 1st to December 31st each year commencing with the 2022 calendar year. The unaudited pro forma information includes adjustments for $3.6 million of transaction costs being reclassified to the fourth quarter of calendar year 2019 which were incurred during the year ended September 30, 2021. Additionally, the Company adjusted for $0.9 million of oil and natural gas property impairment that Tengasco recognized under the full-cost method of accounting, which would not have been recognized under the successful efforts method, during the three months ended December 31, 2020. Also, the unaudited pro forma information has been tax

effected using a 21% tax rate. The common stock was also adjusted for the conversion of the REP LLC preferred units into common units and retroactively adjusted for the Exchange Ratio and one-for-twelve reverse stock split.

	For the year ended September 30, 2021
	(In thousands, except per share/unit amounts)
	(Unaudited)
Total Revenues	$	151,036
Pro Forma Net Loss before Taxes	(29,871)
Pro forma income tax benefit	6,273
Pro Forma Net Loss	$	(23,598)
Net Loss per Share/Unit from Continuing Operations:
Basic	$	(1.88)
Diluted	$	(1.88)
Net Income per Share/Unit from Discontinued Operations:
Basic	$	0.02
Diluted	$	0.02

Schedule of Transactions Costs

The Company recognized transaction costs for the periods presented below:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Business combination acquisition costs	$	2,638	$	1,258	$	3,572
Other	—		—		160
Total transaction costs	$	2,638	$	1,258	$	3,732

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Oil and Natural Gas Properties (Tables)

12 Months Ended

Dec. 31, 2022

Extractive Industries [Abstract]

Schedule of Oil and Gas Properties

Oil and natural gas properties are summarized below:

	December 31, 2022		December 31, 2021
	(In thousands)
Proved	$	516,011	$	421,779
Unproved	12,770		18,839
Work-in-progress	45,169		13,534
	573,950		454,152
Accumulated depletion, amortization and impairment	(133,848)		(95,021)
Total oil and natural gas properties, net	$	440,102	$	359,131

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Notional Amounts of Outstanding Derivative Positions

The following table summarizes the open financial derivative positions as of December 31, 2022, related to oil and natural gas production:

		Weighted Average Price
Calendar Quarter / Year	Notional Volume	Fixed		Put		Call
		($ per unit)
Oil Swaps (Bbl)
Q1 2023	225,000	$	53.65	$	—	$	—
Q2 2023	195,000	$	53.89	$	—	$	—
Q3 2023	126,000	$	53.79	$	—	$	—
Q4 2023	114,000	$	54.59	$	—	$	—
Oil Collars (Bbl)
Q1 2023	30,000	$	—	$	60.00	$	109.60
Q2 2023	30,000	$	—	$	60.00	$	109.60
Q3 2023	—	$	—	$	—	$	—
Q4 2023	—	$	—	$	—	$	—
2024	3,000	$	—	$	50.00	$	88.00

The

following table summarizes the Company's open derivative positions as of March 3, 2023, related to oil and natural gas production:

		Weighted Average Price
Period(1)	Notional Volume	Fixed		Put		Call
		($ per unit)
Oil Swaps (Bbl)
Q1 2023	225,000	$	53.65	$	—	$	—
Q2 2023	315,000	$	62.78	$	—	$	—
Q3 2023	216,000	$	63.04	$	—	$	—
Q4 2023	189,000	$	62.51	$	—	$	—
2024	240,000	$	71.60	$	—	$	—
Oil Collars (Bbl)
Q1 2023	210,000	$	—	$	70.95	$	89.96
Q2 2023	300,000	$	—	$	71.50	$	88.98
Q3 2023	330,000	$	—	$	68.64	$	88.85
Q4 2023	330,000	$	—	$	68.64	$	88.85
2024	1,293,000	$	—	$	61.02	$	86.39
2025	315,000	$	—	$	60.00	$	77.98
Natural Gas Swaps (MMBtu)
Q1 2023	—	$	—	$	—	$	—
Q2 2023	450,000	$	2.60	$	—	$	—
Q3 2023	450,000	$	2.60	$	—	$	—
Q4 2023	400,000	$	3.23	$	—	$	—
2024	1,500,000	$	3.43	$	—	$	—
2025	375,000	$	4.05	$	—	$	—
Natural Gas Collars (MMBtu)
Q1 2023	—	$	—	$	—	$	—
Q2 2023	300,000	$	—	$	2.55	$	3.20
Q3 2023	300,000	$	—	$	2.55	$	3.20
Q4 2023	300,000	$	—	$	3.12	$	4.07
2024	1,065,000	$	—	$	3.19	$	4.14
2025	255,000	$	—	$	3.65	$	4.95
Oil Basis (Bbl)
Q1 2023	240,000	$	1.28	$	—	$	—
Q2 2023	360,000	$	1.28	$	—	$	—
Q3 2023	360,000	$	1.28	$	—	$	—
Q4 2023	360,000	$	1.28	$	—	$	—
2024	960,000	$	0.87	$	—	$	—

___________________

(1)Q1 2023 derivative positions shown include January and February 2023 contracts, some of which have settled as of March 3, 2023.

Schedule of Derivative Instruments Location and Fair Value

The following tables present the location and fair value of the Company’s derivative contracts included in the consolidated balance sheets as of December 31, 2022 and 2021:

	December 31, 2022
Balance Sheet Classification	Gross Fair Value		Amounts Netted		Net Fair Value
	(In thousands)
Current derivative assets	$	64	$	(44)	$	20
Non-current derivative assets	9		(9)		—
Current derivative liabilities	(16,516)		44		(16,472)
Non-current derivative liabilities	(21)		9		(12)
Total	$	(16,464)	$	—	$	(16,464)
	December 31, 2021
Balance Sheet Classification	Gross Fair Value		Amounts Netted		Net Fair Value
	(In thousands)
Current derivative assets	$	281	$	(198)	$	83
Non-current derivative assets	267		—		267
Current derivative liabilities	(31,182)		198		(30,984)
Non-current derivative liabilities	(9,515)		—		(9,515)
Total	$	(40,149)	$	—	$	(40,149)

Schedule of Derivative Instruments, Gain (Loss)

The following table presents the components of the Company's gain (loss) on derivatives for the periods presented below:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Settlements on derivative contracts(1)	$	(75,257)	$	(16,014)	$	(16,304)
Non-cash gain (loss) on derivatives	23,683		10,821		(72,891)
Loss on derivatives	$	(51,574)	$	(5,193)	$	(89,195)

_____________________________________________________

(1) In December 2022, the Company settled a portion of its 2023 open oil fixed price swap contracts which resulted in a $1.5 million settlement.

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2022

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

The following table presents the Company’s

financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2022 and 2021, by level within the fair value hierarchy:

	December 31, 2022
	Level 1		Level 2		Level 3		Total
	(In thousands)
Financial assets:
Commodity derivative assets	$	—	$	73	$	—	$	73
Financial liabilities:
Commodity derivative liabilities	$	—	$	(16,537)	$	—	$	(16,537)
	December 31, 2021
	Level 1		Level 2		Level 3		Total
	(In thousands)
Financial assets:
Commodity derivative assets	$	—	$	187	$	—	$	187
Interest rate assets	$	—	$	361	$	—	$	361
Financial liabilities:
Commodity derivative liabilities	$	—	$	(40,687)	$	—	$	(40,687)
Interest rate liabilities	$	—	$	(10)	$	—	$	(10)

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Transactions with Related Parties (Tables)

12 Months Ended

Dec. 31, 2022

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

The following table presents revenues from and related cost for contract services for related parties:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Combo	$	1,200	$	300	$	1,200
REG	1,200		300		1,200
Contract services - related parties	$	2,400	$	600	$	2,400
Cost of contract services	$	450	$	150	$	477

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Revolving Credit Facility (Tables)

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

Components of Interest Expense

The following table summarizes the Company's interest expense:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Interest expense(1)	$	864	$	512	$	3,686
Capitalized interest	(1,022)		$	—	—
Amortization of deferred financing costs	731		282		653
Unused commitment fees	517		102		195
Total interest expense, net	$	1,090	$	896	$	4,534

_____________________

(1)In December 2022, the Company settled the remaining open positions for the interest rate swap which resulted in a $1.5 million settlement. The Company recognizes settlements on its interest rate swaps in interest expense on the consolidated statements of operations.

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Members’/Shareholders' Equity (Tables)

12 Months Ended

Dec. 31, 2022

Equity [Abstract]

Cash Distributions Declared

The table below summarizes the following cash distributions declared to common shareholders and unitholders during the periods presented below:

Quarter Ended	Per Share/Unit Distribution(1)		Total Distribution
			(In millions)
2022
December 31, 2022	$	0.34	$	6.7
September 30, 2022	$	0.31	$	6.2
June 30, 2022	$	0.31	$	6.2
March 31, 2022	$	0.31	$	6.2
2021
December 31, 2021	$	0.31	$	6.2
September 30, 2021	$	0.28	$	5.5
June 30, 2021	$	—	$	—
March 31, 2021(2)	$	0.29	$	8.8
2020
December 31, 2020	$	0.30	$	3.8

_____________________

(1)Per unit amounts for dividends declared before the Closing Date of the Merger have been effected by giving adjustment to the 1-for-12 reverse stock split and exchange ratio of 97.796467.

(2)On February 4, 2021, the Board of Managers of REP LLC declared a $3.8 million cash dividend, paid on February 5, 2021. On March 4, 2021, the Board of Directors of the Company declared a cash dividend of $0.28 per share or $5.0 million total, paid on May 7, 2021.

Restricted Stock, Activity

The following table presents the Company's restricted stock activity during the year ended December 31, 2022 under the 2021 LTIP:

2021 Long-Term Incentive Plan
	Restricted Shares	Weighted Average Grant Date Fair Value(1)
Unvested at December 31, 2021	366,789	$	19.41
Granted	367,420	$	17.63
Vested	(192,899)	$	19.25
Forfeited	(5,101)	$	23.46
Unvested at December 31, 2022	536,209	$	18.39

_____________________________________________________

(1) For the three months ended December 31, 2021, the Company granted 174,575 restricted shares at a weighted average grant date fair value of $23.46. For the year ended September 30, 2021, the Company granted 397,739 restricted shares at a weighted average grant date fair value of $21.16.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2022

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

The components of the Company's consolidated provision for income taxes from continuing operations are as follows:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Current income tax expense:
Federal	$	4,026	$	—	$	2
State	446		113		52
Total current income tax expense	$	4,472	$	113	$	54
Deferred income tax expense (benefit):
Federal	$	27,393	$	5,669	$	14,202
State	979		87		(1,240)
Total deferred income tax expense (benefit)	$	28,372	$	5,756	$	12,962
Total income tax expense (benefit)	$	32,844	$	5,869	$	13,016

Schedule of Deferred Tax Assets and Liabilities

The Company's net deferred tax position is as follows:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Deferred tax assets
Non-cash gain on derivatives	$	3,563	$	10,286	$	11,006
Intangibles	182		215		222
Inventory	—		23		23
Share-based compensation	421		690		480
Accruals and other	484		558		578
Net operating loss	2,812		3,172		5,422
Total deferred tax assets	7,462		14,944		17,731
Oil and natural gas assets	(52,665)		(32,154)		(29,161)
Other fixed assets	(553)		(174)		(198)
Total deferred tax liabilities	(53,218)		(32,328)		(29,359)
Net deferred tax liabilities	$	(45,756)	$	(17,384)	$	(11,628)

Schedule of Effective Income Tax Rate Reconciliation

A reconciliation of the statutory federal income tax rate to the Company's effective income tax rate is as follows:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
Tax at statutory rate	21.0	%	21.0	%	21.0	%
Nondeductible compensation	0.2	%	0.1	%	(1.0)	%
Transaction costs	—	%	—	%	(1.5)	%
Share-based compensation	—	%	(0.3)	%	(0.1)	%
State income taxes, net of federal benefit	0.7	%	0.7	%	0.4	%
Change in tax status	—	%	—	%	(40.1)	%
Income subject to taxation by REP LLC's unitholders	—	%	—	%	(17.1)	%
Other	(0.2)	%	—	%	—	%
Effective income tax rate	21.7	%	21.5	%	(38.4)	%

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Discontinued Operations and Assets Held For Sale (Tables)

12 Months Ended

Dec. 31, 2022

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations

The following table presents the components of the loss on discontinued operations reported in the consolidated statements of operations for the periods ended September 30, 2021:

		Year Ended
		September 30, 2021
	(In thousands)
Oil and natural gas sales		$	—
Total revenues		—
Lease operating expenses		115
Goodwill impairment		18,516
Total expenses		18,631
Other expenses		(107)
Loss from discontinued operations before income taxes		(18,738)
Income tax expense		(59)
Loss from discontinued operations, net of tax		$	(18,797)

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Net Income (Loss) Per Share/Unit (Tables)

12 Months Ended

Dec. 31, 2022

Earnings Per Share [Abstract]

Computation of Basic and Diluted Net Loss Per Shares/Units

The table below sets forth the computation of basic and diluted net income (loss) per share/unit for the periods presented below:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands, except per share/unit)
Continuing Operations:
Net income (loss) - Diluted	$	118,011	$	21,398	$	(46,869)
Less: Dividends on preferred units	—		—		(1,491)
Net income (loss) attributable to common shareholders/unitholders - Basic(1)	$	118,011	$	21,398	$	(48,360)
Basic weighted-average common shares/units outstanding	19,553		19,470		16,021
Effecting of dilutive securities:
Restricted shares/units	133		99		—
Diluted weighted-average common shares/units outstanding	19,686		19,569		16,021
Continuing Operations:
Basic net income (loss) per common share/unit	$	6.04	$	1.10	$	(3.02)
Diluted net income (loss) per common share/unit	$	5.99	$	1.09	$	(3.02)

_____________________________________________________

(1) Used in the basic and diluted net loss per share/unit calculation when the Company is in a net loss position.

Schedule of Anti-Dilutive Shares/Units

The following shares/units were excluded from the calculation of diluted net income (loss) per share/unit due to their anti-dilutive effect for the periods presented:

	Year Ended December 31, 2022	Three Months Ended December 31, 2021	Year Ended September 30, 2021
	(In thousands)
Restricted shares/units	405	268	228

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Subsequent Events (Tables)

12 Months Ended

Dec. 31, 2022

Subsequent Events [Abstract]

Schedule of Notional Amounts of Outstanding Derivative Positions

The following table summarizes the open financial derivative positions as of December 31, 2022, related to oil and natural gas production:

		Weighted Average Price
Calendar Quarter / Year	Notional Volume	Fixed		Put		Call
		($ per unit)
Oil Swaps (Bbl)
Q1 2023	225,000	$	53.65	$	—	$	—
Q2 2023	195,000	$	53.89	$	—	$	—
Q3 2023	126,000	$	53.79	$	—	$	—
Q4 2023	114,000	$	54.59	$	—	$	—
Oil Collars (Bbl)
Q1 2023	30,000	$	—	$	60.00	$	109.60
Q2 2023	30,000	$	—	$	60.00	$	109.60
Q3 2023	—	$	—	$	—	$	—
Q4 2023	—	$	—	$	—	$	—
2024	3,000	$	—	$	50.00	$	88.00

The

following table summarizes the Company's open derivative positions as of March 3, 2023, related to oil and natural gas production:

		Weighted Average Price
Period(1)	Notional Volume	Fixed		Put		Call
		($ per unit)
Oil Swaps (Bbl)
Q1 2023	225,000	$	53.65	$	—	$	—
Q2 2023	315,000	$	62.78	$	—	$	—
Q3 2023	216,000	$	63.04	$	—	$	—
Q4 2023	189,000	$	62.51	$	—	$	—
2024	240,000	$	71.60	$	—	$	—
Oil Collars (Bbl)
Q1 2023	210,000	$	—	$	70.95	$	89.96
Q2 2023	300,000	$	—	$	71.50	$	88.98
Q3 2023	330,000	$	—	$	68.64	$	88.85
Q4 2023	330,000	$	—	$	68.64	$	88.85
2024	1,293,000	$	—	$	61.02	$	86.39
2025	315,000	$	—	$	60.00	$	77.98
Natural Gas Swaps (MMBtu)
Q1 2023	—	$	—	$	—	$	—
Q2 2023	450,000	$	2.60	$	—	$	—
Q3 2023	450,000	$	2.60	$	—	$	—
Q4 2023	400,000	$	3.23	$	—	$	—
2024	1,500,000	$	3.43	$	—	$	—
2025	375,000	$	4.05	$	—	$	—
Natural Gas Collars (MMBtu)
Q1 2023	—	$	—	$	—	$	—
Q2 2023	300,000	$	—	$	2.55	$	3.20
Q3 2023	300,000	$	—	$	2.55	$	3.20
Q4 2023	300,000	$	—	$	3.12	$	4.07
2024	1,065,000	$	—	$	3.19	$	4.14
2025	255,000	$	—	$	3.65	$	4.95
Oil Basis (Bbl)
Q1 2023	240,000	$	1.28	$	—	$	—
Q2 2023	360,000	$	1.28	$	—	$	—
Q3 2023	360,000	$	1.28	$	—	$	—
Q4 2023	360,000	$	1.28	$	—	$	—
2024	960,000	$	0.87	$	—	$	—

___________________

(1)Q1 2023 derivative positions shown include January and February 2023 contracts, some of which have settled as of March 3, 2023.

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Supplemental Information on Oil and Natural Gas Operations (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2022

Extractive Industries [Abstract]

Schedule of Exploration Expenses

The following summarizes the costs incurred for oil and natural gas property acquisition, exploration and development activities for the periods presented below:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Acquisition of properties
Proved	$	450	$	67	$	74
Unproved	1,468		193		1,562
Exploration costs	157		—		7,993
Development costs	119,673		20,348		59,948
Total costs incurred	$	121,748	$	20,608	$	69,577

Summary of Results of Operations for Oil and Gas Producing Activities Disclosure

The following table includes revenues and expenses associated with the Company's oil and natural gas producing activities. They do not include any allocation of the Company's interest costs or general corporate overhead. Therefore, the following schedule is not necessarily indicative of the contribution of net earnings of the Company's oil and natural gas operations.

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Oil, natural gas and NGL sales	$	319,343	$	56,650	$	148,636
Lease operating expenses	32,458		7,419		21,975
Production and ad valorem taxes	19,273		3,005		8,636
Exploration costs	2,032		611		9,566
Depletion, accretion and amortization	31,500		6,742		25,347
Impairment of oil and natural gas properties	7,325		—		—
Results of operations	226,755		38,873		83,112
Income tax expense (1)	48,957		(8,393)		(13,505)
Results of operations, net of income tax expense	$	275,712	$	30,480	$	69,607

_____________________________________________________

(1)    Subsequent to the Closing Date of the Merger, the statutory combined federal and state tax rate of 21.59% is used for the year ended December 31, 2022, three months ended December 31, 2021, and year ended September 30, 2021.

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities

The following table sets forth information for the periods below with respect to changes in the Company’s proved (i.e. proved developed and undeveloped) reserves:

	Oil	Natural Gas	NGLs	Total
	(MBbl)	(MMcf)	(MBbl)	(MBoe)
September 30, 2020	37,158	53,683	10,681	56,787
Extensions and discoveries	9,308	12,089	2,436	13,759
Revisions	2,138	12,850	492	4,772
Production	(2,341)	(2,603)	(380)	(3,155)
September 30, 2021	46,263	76,019	13,229	72,163
Extensions and discoveries	1,328	1,961	371	2,026
Revisions	99	350	(24)	133
Production	(669)	(844)	(105)	(915)
December 31, 2021	47,021	77,486	13,471	73,407
Extensions and discoveries	9,949	13,178	2,651	14,796
Revisions	(4,871)	(1,417)	(1,224)	(6,331)
Production	(3,217)	(3,229)	(444)	(4,199)
December 31, 2022	48,882	86,018	14,454	77,673
Proved Developed Reserves, Included Above
September 30, 2021	26,170	46,173	7,650	41,516
December 31, 2021	27,096	47,974	7,949	43,041
December 31, 2022	29,632	59,314	9,604	49,122
Proved Undeveloped Reserves, Included Above
September 30, 2021	20,093	29,846	5,579	30,647
December 31, 2021	19,925	29,512	5,522	30,366
December 31, 2022	19,250	26,704	4,850	28,551

Summary of Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure

The following summary sets forth the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure prescribed in ASC Topic 932:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Future crude oil, natural gas and NGLs sales (1)(2)(3)	$	5,135,650	$	3,350,506	$	2,783,910
Future production costs	(1,559,266)		(912,468)		(839,167)
Future development costs	(341,481)		(216,138)		(218,765)
Future income tax expense	(658,340)		(436,829)		(324,487)
Future net cash flows	2,576,563		1,785,071		1,401,491
10% annual discount	(1,468,187)		(1,081,602)		(848,555)
Standardized measure of discounted future net cash flows	$	1,108,376	$	703,469	$	552,936

_____________________________________________________

(1)    December 31, 2022 proved reserves were derived based on prices of $91.96 per barrel of oil, $3.16 per Mcf of natural gas and $25.55 per barrel of NGL.

(2)    December 31, 2021 proved reserves were derived based on prices of $64.60 per barrel of oil, $1.65 per Mcf of natural gas and $13.75 per barrel of NGL.

(3)    September 30, 2021 proved reserves were derived based on prices of $55.73 per barrel of oil, $0.99 per Mcf of natural gas and $9.83 per barrel of NGL.

Principal sources of change in the Standardized Measure are shown below:

	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Balance, beginning of period	$	703,469	$	552,936	$	302,338
Sales of crude oil, natural gas and NGLs, net	(267,612)		(46,226)		(118,030)
Net change in prices and production costs	406,803		194,596		237,475
Net changes in future development costs	(40,226)		1,267		(18,856)
Extensions and discoveries	321,009		35,111		144,392
Revisions of previous quantity estimates	(83,188)		(536)		50,283
Previously estimated development costs incurred	8,775		4,182		12,844
Net change in income taxes	(117,098)		(47,881)		(124,625)
Accretion of discount	87,914		17,018		30,551
Other	88,530		(6,998)		36,564
Balance, end of period	$	1,108,376	$	703,469	$	552,936

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Basis of Presentation (Details)	Aug. 19, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Percentage of holders with outstanding common stock who acted upon written consent	75.00%

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Summary of Significant Accounting Policies - Narrative (Details)		3 Months Ended	7 Months Ended	12 Months Ended
	Apr. 02, 2021 reportingUnit	Dec. 31, 2021 USD ($)	Oct. 31, 2022 USD ($)	Dec. 31, 2022 USD ($)	Sep. 30, 2021 USD ($)	Mar. 31, 2021 USD ($)
Property, Plant and Equipment [Line Items]
Allowance for credit losses		$ 0		$ 0
Property, plant and equipment, costs		3,600,000		5,300,000
Property, plant and equipment, accumulated depreciation		1,700,000		2,000,000
Land, costs		1,300,000		16,700,000
Number of reporting units | reportingUnit	2
Unrecognized tax benefits		0		0
Interest expense		$ 900,000		$ 1,100,000	$ 4,500,000
Weighted average discount rate		5.17%		3.18%
Weighted average remaining lease term		6 months		2 years 4 months 24 days
Lease expense		$ 100,000		$ 500,000	$ 400,000
ROU asset [Extensible Enumeration]		Other non-current assets, net		Other non-current assets, net	Other non-current assets, net
Current lease liability [Extensible Enumeration]		Other current liabilities		Other current liabilities	Other current liabilities
Long-term lease liability [Extensible Enumeration]		Other non-current liabilities		Other non-current liabilities	Other non-current liabilities
Customer Concentration Risk | One Purchaser | Revenue Benchmark
Property, Plant and Equipment [Line Items]
Concentration risk, percentage		87.00%		89.00%	87.00%
Kansas Properties
Property, Plant and Equipment [Line Items]
Disposal group, fair value						$ 3,500,000
Goodwill impairment					$ 18,500,000
Revolving Credit Facility | Line of Credit
Property, Plant and Equipment [Line Items]
Additional financing costs			$ 1,900,000
Interest expense		$ 896,000		$ 1,090,000	$ 4,534,000
Maximum
Property, Plant and Equipment [Line Items]
Property and equipment, useful life				39 years
Contract Term				10 years
Minimum
Property, Plant and Equipment [Line Items]
Property and equipment, useful life				5 years
Contract Term				1 year

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Summary of Significant Accounting Policies - Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Oil, natural gas and NGL sales	$ 24,136	$ 17,562
Joint interest accounts receivable	793	409
Other accounts receivable	622	31
Total accounts receivable	$ 25,551	$ 18,002

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Summary of Significant Accounting Policies - Other Non-current Assets, Net (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Deferred financing costs, net	$ 2,556	$ 1,345
Prepayments to outside operators	186	690
Right of use assets	1,370	208
Other deposits	63	50
Total other non-current assets, net	$ 4,175	$ 2,293

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Summary of Significant Accounting Policies - Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Accrued capital expenditures	$ 16,744	$ 5,618
Accrued lease operating expenses	4,607	2,534
Accrued general and administrative costs	2,286	3,404
Accrued inventory	6,235	0
Accrued ad valorem tax	3,789	705
Other accrued expenditures	1,921	613
Total accrued liabilities	$ 35,582	$ 12,874

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Summary of Significant Accounting Policies - Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO, beginning balance	$ 2,453	$ 2,434
Liabilities incurred	358	56
Revision of estimated obligations	326	0
Liability settlements and disposals	(178)	(58)
Accretion	79	21
ARO, ending balance	3,038	2,453
Less: current ARO	(314)	(192)
ARO, long-term	$ 2,724	$ 2,261

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Summary of Significant Accounting Policies - Revenue (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Sep. 30, 2021
Disaggregation of Revenue [Line Items]
Total Revenues	$ 57,250	$ 321,743	$ 151,036
Oil and natural gas sales, net
Disaggregation of Revenue [Line Items]
Total Revenues	56,650	319,343	148,636
Oil
Disaggregation of Revenue [Line Items]
Total Revenues	50,623	298,723	136,421
Natural Gas
Disaggregation of Revenue [Line Items]
Total Revenues	2,705	10,755	7,500
Natural gas liquids
Disaggregation of Revenue [Line Items]
Total Revenues	$ 3,322	$ 9,865	$ 4,715

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Summary of Significant Accounting Policies - ROU Assets and Lease Liability (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
ROU asset	$ 1,370	$ 208
Current lease liability	539	212
Long-term lease liability	$ 838	$ 0

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Acquisitions - Narrative (Details) $ / shares in Units, $ in Thousands			3 Months Ended			12 Months Ended
	Apr. 02, 2021 USD ($)	Feb. 26, 2021 USD ($) $ / shares shares	Dec. 31, 2021 USD ($) $ / shares shares	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2022 USD ($) $ / shares shares	Sep. 30, 2021 USD ($)	Mar. 10, 2021 USD ($)
Business Acquisition [Line Items]
Common stock, par value (USD per Share) | $ / shares			$ 0.001			$ 0.001
Reverse stock split							0.083
Common stock outstanding post merger (in Shares) | shares		17,800,000	19,836,885			20,160,980
Transaction costs			$ 1,258			$ 2,638	$ 3,732
Impairment of oil and natural gas properties			0			7,325	0
Business combination acquisition costs			$ 1,258			$ 2,638	3,572
Discontinued Operations, Disposed of by Sale | Kansas Properties
Business Acquisition [Line Items]
Consideration from discontinued operations	$ 3,500							$ 3,500
Discontinued operation, closing costs	$ 200
Riley Exploration
Business Acquisition [Line Items]
Total consideration		$ 26,392
Transaction costs, cumulative							5,000
Transaction costs							$ 3,600
Impairment of oil and natural gas properties				$ 900
Riley Exploration | Transaction-related costs reclassification
Business Acquisition [Line Items]
Transaction costs					$ 3,600
Tengasco
Business Acquisition [Line Items]
Common stock, par value (USD per Share) | $ / shares		$ 0.001
Stock conversion ratio		97.796467
Reverse stock split		0.083

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Acquisitions - Purchase Price or Consideration for the Transaction (Details) - Riley Exploration $ / shares in Units, $ in Thousands	Feb. 26, 2021 USD ($) $ / shares
Business Acquisition [Line Items]
Common stock price (USD per Share) | $ / shares	$ 29.64
Common stock - issued and outstanding	$ 891
Total consideration	$ 26,392

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Acquisitions - Allocation of the Purchase Price (Details) - Riley Exploration $ in Thousands	Feb. 26, 2021 USD ($)
Current assets
Cash and cash equivalents	$ 860
Accounts receivable	325
Prepaid and other current assets	759
Total current assets	1,944
Oil and gas properties	4,525
Other property and equipment	91
Right of use assets	42
Other non-current assets	4
Deferred tax assets	2,987
Total assets acquired	9,593
Current liabilities
Accounts payable	130
Accrued liabilities	409
Current lease liabilities, operating	42
Current lease liabilities, financing	68
Total current liabilities	649
Asset retirement obligations	1,565
Total liabilities assumed	2,214
Net identifiable assets acquired	7,379
Goodwill	19,013
Net assets acquired	$ 26,392

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Acquisitions - Pro Forma Operating Results (Unaudited) (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Sep. 30, 2021 USD ($) $ / shares
Business Combination and Asset Acquisition [Abstract]
Total Revenues | $	$ 151,036
Pro Forma Net Loss before Taxes | $	(29,871)
Pro forma income tax benefit | $	6,273
Pro Forma Net Loss | $	$ (23,598)
Net Loss per Share/Unit from Continuing Operations, Basic (USD per Share) | $ / shares	$ (1.88)
Net Loss per Share/Unit from Continuing Operations, Diluted (USD per Share) | $ / shares	(1.88)
Net Income per Share/Unit from Discontinued Operations, Basic (USD per share) | $ / shares	0.02
Net Income per Share/Unit from Discontinued Operations, Diluted (USD per share) | $ / shares	$ 0.02

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Acquisitions - Transaction Costs (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Sep. 30, 2021
Business Combination and Asset Acquisition [Abstract]
Business combination acquisition costs	$ 1,258	$ 2,638	$ 3,572
Other	0	0	160
Total transaction costs	$ 1,258	$ 2,638	$ 3,732

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Oil and Natural Gas Properties - Schedule of Properties (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Extractive Industries [Abstract]
Proved	$ 516,011	$ 421,779
Unproved	12,770	18,839
Work-in-progress	45,169	13,534
Total oil and natural gas properties, gross	573,950	454,152
Accumulated depletion, amortization and impairment	(133,848)	(95,021)
Total oil and natural gas properties, net	$ 440,102	$ 359,131

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Oil and Natural Gas Properties - Narrative (Details) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2021 USD ($)	Dec. 31, 2022 USD ($) well	Dec. 31, 2021 USD ($) well	Sep. 30, 2021 USD ($)
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Number of exploratory drilled | well		1	1
Exploratory well costs	$ 3,700	$ 3,800	$ 3,700
Depletion and amortization	6,700	31,500		$ 25,200
Exploration costs	611	2,032		9,566
Impairment of oil and natural gas properties	$ 0	7,325		$ 0
New Mexico
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Impairment of oil and natural gas properties		$ 7,300
Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | New Mexico
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Oil and gas properties, measurement input		10.25%
Maximum
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Capitalized period		2 years

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Derivative Instruments - Notional Amounts, Crude Oil and Natural Gas (Details) bbl in Thousands	12 Months Ended
	Dec. 31, 2022 $ / bbl bbl
Oil Swaps Q1 2023
Derivative [Line Items]
Notional Volume | bbl	225
Weighted average price (in usd per bbl/mmbtu)	53.65
Oil Swaps Q2 2023
Derivative [Line Items]
Notional Volume | bbl	195
Weighted average price (in usd per bbl/mmbtu)	53.89
Oil Swaps Q3 2023
Derivative [Line Items]
Notional Volume | bbl	126
Weighted average price (in usd per bbl/mmbtu)	53.79
Oil Swaps Q4 2023
Derivative [Line Items]
Notional Volume | bbl	114
Weighted average price (in usd per bbl/mmbtu)	54.59
Oil Collars Q1 2023
Derivative [Line Items]
Notional Volume | bbl	30
Oil Collars Q1 2023 | Short
Derivative [Line Items]
Weighted average price (in usd per bbl/mmbtu)	60.00
Oil Collars Q1 2023 | Long
Derivative [Line Items]
Weighted average price (in usd per bbl/mmbtu)	109.60
Oil Collars Q2 2023
Derivative [Line Items]
Notional Volume | bbl	30
Oil Collars Q2 2023 | Short
Derivative [Line Items]
Weighted average price (in usd per bbl/mmbtu)	60.00
Oil Collars Q2 2023 | Long
Derivative [Line Items]
Weighted average price (in usd per bbl/mmbtu)	109.60
Oil Collars 2024
Derivative [Line Items]
Notional Volume | bbl	3
Oil Collars 2024 | Short
Derivative [Line Items]
Weighted average price (in usd per bbl/mmbtu)	50.00
Oil Collars 2024 | Long
Derivative [Line Items]
Weighted average price (in usd per bbl/mmbtu)	88.00

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Derivative Instruments - Narrative (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2022	Sep. 30, 2021
Derivative [Line Items]
Settlements on derivative contracts		$ 16,014	$ 75,257	$ 16,304
Interest Rate Swap
Derivative [Line Items]
Settlements on derivative contracts	$ 1,500		$ 1,500

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Derivative Instruments - Statement Of Financial Position (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Derivative asset, net, gross fair value	$ (16,464)	$ (40,149)
Derivative assets, net, net fair value	(16,464)	(40,149)
Current derivative assets
Derivative [Line Items]
Derivative asset, gross fair value	64	281
Derivative asset, amounts netted	(44)	(198)
Derivative assets, net fair value	20	83
Non-current derivative assets
Derivative [Line Items]
Derivative asset, gross fair value	9	267
Derivative asset, amounts netted	(9)	0
Derivative assets, net fair value	0	267
Current derivative liabilities
Derivative [Line Items]
Derivative liability, gross fair value	(16,516)	(31,182)
Derivative liability, amounts netted	44	198
Derivative liability, net fair value	(16,472)	(30,984)
Non-current derivative liabilities
Derivative [Line Items]
Derivative liability, gross fair value	(21)	(9,515)
Derivative liability, amounts netted	9	0
Derivative liability, net fair value	$ (12)	$ (9,515)

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Derivative Instruments - Derivative Activities (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2022	Sep. 30, 2021
Derivative [Line Items]
Settlements on derivative contracts		$ (16,014)	$ (75,257)	$ (16,304)
Non-cash gain (loss) on derivatives		10,821	23,683	(72,891)
Loss on derivatives		$ (5,193)	$ (51,574)	$ (89,195)
Oil Swap, 2023
Derivative [Line Items]
Settlements on derivative contracts	$ (1,500)

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Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Commodity derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial assets	$ 73	$ 187
Financial liabilities	(16,537)	(40,687)
Commodity derivative | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial assets	0	0
Financial liabilities	0	0
Commodity derivative | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial assets	73	187
Financial liabilities	(16,537)	(40,687)
Commodity derivative | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial assets	0	0
Financial liabilities	$ 0	0
Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial assets		361
Financial liabilities		(10)
Interest rate | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial assets		0
Financial liabilities		0
Interest rate | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial assets		361
Financial liabilities		(10)
Interest rate | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial assets		0
Financial liabilities		$ 0

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Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Asset retirement obligation, fair value disclosure	$ 0.1	$ 0.4

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Transactions with Related Parties - Narrative (Details) - USD ($)	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Sep. 30, 2021
Legal Services | Director | di Santo Law PLLC
Related Party Transaction [Line Items]
Expenses with related parties	$ 200,000	$ 700,000	$ 1,000,000
Due to related parties	200,000	0
Affiliated Entity | Contract Services Agreement | Combo Resources, LLC
Related Party Transaction [Line Items]
Monthly servicing fee		100,000
Due from (to) related party	$ (200,000)	(400,000)
Affiliated Entity | Contract Services Agreement | Riley Exploration Group, Inc
Related Party Transaction [Line Items]
Monthly servicing fee		$ 100,000

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Transactions with Related Parties - Components (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Sep. 30, 2021
Related Party Transaction [Line Items]
Cost of contract services	$ 150	$ 450	$ 477
Affiliated Entity | Contract Services Agreement
Related Party Transaction [Line Items]
Contract services - related parties	600	2,400	2,400
Affiliated Entity | Contract Services Agreement | Combo Resources, LLC
Related Party Transaction [Line Items]
Contract services - related parties	300	1,200	1,200
Affiliated Entity | Contract Services Agreement | Riley Exploration Group, Inc
Related Party Transaction [Line Items]
Contract services - related parties	$ 300	$ 1,200	$ 1,200

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Revolving Credit Facility - Narrative (Details)		1 Months Ended	3 Months Ended	12 Months Ended
	Sep. 28, 2017 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2022 USD ($)	Sep. 30, 2021 USD ($)	Oct. 25, 2022 USD ($)	Apr. 30, 2022 USD ($)
Line of Credit Facility [Line Items]
Settlements on derivative contracts			$ 16,014,000	$ 75,257,000	$ 16,304,000
Outstanding borrowings		$ 56,000,000	$ 65,000,000	56,000,000
Interest Rate Swap
Line of Credit Facility [Line Items]
Settlements on derivative contracts		$ 1,500,000		$ 1,500,000
Line of Credit | Revolving Credit Facility
Line of Credit Facility [Line Items]
Borrowing base	$ 25,000,000					$ 225,000,000	$ 225,000,000
Maximum facility amount	$ 500,000,000
Cash balance threshold, borrowing base	10.00%
Hedging requirement ratio for proved developed producing volumes, minimum	0.00%
Hedging requirement ratio for proved developed producing volumes, maximum	50.00%
Hedging requirement ratio for proved developed producing volumes, term	24 months
Hedging requirement ratio for proved developed producing volumes		0.00%		0.00%
Weighted average interest rate		7.17%	3.10%	7.17%
Available under the credit facility		$ 169,000,000	$ 110,000,000	$ 169,000,000
Line of Credit | Revolving Credit Facility | Minimum
Line of Credit Facility [Line Items]
Unused capacity, commitment fee percentage	0.375%
Current ratio	1.0
Leverage ratio for restricted payments after pro forma effect	2.0
Line of Credit | Revolving Credit Facility | Minimum | SOFR Loan | Secured Overnight Financing Rate (SOFR)
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.75%
Line of Credit | Revolving Credit Facility | Minimum | Base Rate Loan
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.75%
Line of Credit | Revolving Credit Facility | Maximum
Line of Credit Facility [Line Items]
Unused capacity, commitment fee percentage	0.50%
Leverage ratio	3.25
Leverage ratio for restricted payments	2.50
Cash balance threshold, prepayment of lines of credit	$ 15,000,000
Line of Credit | Revolving Credit Facility | Maximum | SOFR Loan | Secured Overnight Financing Rate (SOFR)
Line of Credit Facility [Line Items]
Basis spread on variable rate	3.75%
Line of Credit | Revolving Credit Facility | Maximum | Base Rate Loan
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.75%

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Revolving Credit Facility - Components of Interest Expense (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Sep. 30, 2021
Line of Credit Facility [Line Items]
Total interest expense, net	$ 900	$ 1,100	$ 4,500
Line of Credit | Revolving Credit Facility
Line of Credit Facility [Line Items]
Interest expense	512	864	3,686
Capitalized interest	0	(1,022)	0
Amortization of deferred financing costs	282	731	653
Unused commitment fees	102	517	195
Total interest expense, net	$ 896	$ 1,090	$ 4,534

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Members’/Shareholders' Equity - Narrative (Details) $ / shares in Units, $ in Thousands			2 Months Ended	3 Months Ended		12 Months Ended
	Jul. 02, 2022 USD ($) $ / shares shares	Feb. 26, 2021 shares	Feb. 26, 2021 USD ($) shares	Dec. 31, 2022 USD ($) shares	Dec. 31, 2021 USD ($) shares	Dec. 31, 2022 USD ($) shares	Sep. 30, 2021 USD ($) shares
Class of Stock [Line Items]
Proceeds from issuance of common stock | $	$ 46,700				$ 0	$ 0	$ 50,000
Reverse stock split							0.083
Common stock outstanding post merger (in Shares)		17,800,000	17,800,000	20,160,980	19,836,885	20,160,980
Share-based compensation expense | $					$ 951	$ 3,439	$ 6,104
Unit-based compensation expense | $			$ 700		0	0	689
General and Administrative Expense
Class of Stock [Line Items]
Share-based compensation expense | $					$ 900	$ 3,900	$ 6,100
Minimum | Restricted Stock
Class of Stock [Line Items]
Granted service period						3 months
Maximum | Restricted Stock
Class of Stock [Line Items]
Granted service period						36 months
2021 Long-Term Incentive Plan
Class of Stock [Line Items]
Common stock reserved for future issuance (in Shares)		1,387,022	1,387,022
Common stock outstanding post merger (in Shares)				440,784		440,784
2021 Long-Term Incentive Plan | Restricted Stock
Class of Stock [Line Items]
Granted (in Shares)				174,575	174,575	367,420	397,739
Additional share based compensation to be recognized | $				$ 8,300		$ 8,300
Weighted average life						28 months
2028 Long-Term Incentive Plan | Restricted Stock Units
Class of Stock [Line Items]
Granted (in Shares)							13,309
Tengasco
Class of Stock [Line Items]
Reverse stock split		0.083
Public Stock Offering
Class of Stock [Line Items]
Sale of stock, number of shares issued in transaction (in Shares)	1,666,667
Public Stock Offering | Common Stock
Class of Stock [Line Items]
Sale of stock, price per share (USD per Share) | $ / shares	$ 30.00

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Members’/Shareholders' Equity - Distributions (Details) $ / shares in Units, $ in Millions				3 Months Ended									12 Months Ended
	Mar. 04, 2021 USD ($) $ / shares	Feb. 26, 2021	Feb. 04, 2021 USD ($)	Dec. 31, 2022 USD ($) $ / shares	Sep. 30, 2022 USD ($) $ / shares	Jun. 30, 2022 USD ($) $ / shares	Mar. 31, 2022 USD ($) $ / shares	Dec. 31, 2021 USD ($) $ / shares	Sep. 30, 2021 USD ($) $ / shares	Jun. 30, 2021 USD ($) $ / shares	Mar. 31, 2021 USD ($) $ / shares	Dec. 31, 2020 USD ($) $ / shares	Sep. 30, 2021
Dividends Payable [Line Items]
Cash dividend declared (USD per Share/Unit) | $ / shares	$ 0.28			$ 0.34	$ 0.31	$ 0.31	$ 0.31	$ 0.31	$ 0.28	$ 0	$ 0.29	$ 0.30
Total Distribution | $	$ 5.0		$ 3.8	$ 6.7	$ 6.2	$ 6.2	$ 6.2	$ 6.2	$ 5.5	$ 0.0	$ 8.8	$ 3.8
Reverse stock split													0.083
Tengasco
Dividends Payable [Line Items]
Reverse stock split		0.083
Stock conversion ratio		97.796467

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Members’/Shareholders' Equity - Restricted Stock Units Activity (Details) - Restricted Stock - 2021 Long-Term Incentive Plan - $ / shares	3 Months Ended		12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2022	Sep. 30, 2021
Awards
Unvested, beginning balance (in Shares/Units)			366,789
Granted (in Shares/Units)	174,575	174,575	367,420	397,739
Vested (in Shares/Units)			(192,899)
Forfeited (in Shares/Units)			(5,101)
Unvested, ending balance (in Shares/Units)	536,209	366,789	536,209
Weighted Average Grant Date Fair Value(1)
Unvested, beginning balance (USD per Share/Unit)			$ 19.41
Granted (USD per Share/Unit)		$ 23.46	17.63	$ 21.16
Vested (USD per Share/Unit)			19.25
Forfeited (USD per Share/Unit)			23.46
Unvested, ending balance (USD per Share/Unit)	$ 18.39	$ 19.41	$ 18.39

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Income Taxes - Narrative (Details) - USD ($) $ in Thousands		3 Months Ended	9 Months Ended	12 Months Ended
	Feb. 26, 2021	Dec. 31, 2021	Sep. 30, 2021	Dec. 31, 2022	Sep. 30, 2021
Income Tax Disclosure [Abstract]
Deferred income tax expense	$ 13,600	$ 5,756	$ 12,962	$ 28,372	$ 12,962
Operating loss carryforwards				13,400
Operating loss carryforwards, subject to expiration				4,600
Operating loss carryforwards, not subject to expiration				$ 8,800

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Income Taxes - Components (Details) - USD ($) $ in Thousands		3 Months Ended	9 Months Ended	12 Months Ended
	Feb. 26, 2021	Dec. 31, 2021	Sep. 30, 2021	Dec. 31, 2022	Sep. 30, 2021
Current income tax expense:
Federal		$ 0	$ 2	$ 4,026
State		113	52	446
Total current income tax expense		113	54	4,472
Deferred income tax expense (benefit):
Federal		5,669	14,202	27,393
State		87	(1,240)	979
Total deferred income tax expense (benefit)	$ 13,600	5,756	12,962	28,372	$ 12,962
Total income tax expense (benefit)		$ 5,869	$ 13,016	$ 32,844	$ 13,016

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Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Sep. 30, 2021
Income Tax Disclosure [Abstract]
Non-cash gain on derivatives	$ 3,563	$ 10,286	$ 11,006
Intangibles	182	215	222
Inventory	0	23	23
Share-based compensation	421	690	480
Accruals and other	484	558	578
Net operating loss	2,812	3,172	5,422
Total deferred tax assets	7,462	14,944	17,731
Oil and natural gas assets	(52,665)	(32,154)	(29,161)
Other fixed assets	(553)	(174)	(198)
Total deferred tax liabilities	(53,218)	(32,328)	(29,359)
Net deferred tax liabilities	$ (45,756)	$ (17,384)	$ (11,628)

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Income Taxes - Reconciliation (Details)	3 Months Ended		12 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2021
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Tax at statutory rate	21.00%	21.00%	21.00%
Nondeductible compensation	0.20%	0.10%	(1.00%)
Transaction costs	0.00%	0.00%	(1.50%)
Share-based compensation	0.00%	(0.30%)	(0.10%)
State income taxes, net of federal benefit	0.70%	0.70%	0.40%
Change in tax status	0.00%	0.00%	(40.10%)
Income subject to taxation by REP LLC's unitholders	0.00%	0.00%	(17.10%)
Other	(0.20%)	0.00%	0.00%
Effective income tax rate	21.70%	21.50%	(38.40%)

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Discontinued Operations and Assets Held For Sale - Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Sep. 30, 2021	Apr. 02, 2021	Mar. 10, 2021
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss from discontinued operations before income taxes	$ 0	$ 0	$ (18,738)
Income tax expense	0	0	(59)
Loss on Discontinued Operations	$ 0	$ 0	(18,797)
Kansas Properties | Discontinued Operations, Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration from discontinued operations				$ 3,500	$ 3,500
Consideration from discontinued operations including closing adjustments				$ 3,300
Total revenues			0
Lease operating expenses			115
Goodwill impairment			18,516
Total expenses			18,631
Other expenses			(107)
Loss from discontinued operations before income taxes			(18,738)
Income tax expense			(59)
Loss on Discontinued Operations			(18,797)
Kansas Properties | Discontinued Operations, Disposed of by Sale | Oil and natural gas sales, net
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues			$ 0

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Net Income (Loss) Per Share/Unit - Narrative (Details)		12 Months Ended
	Feb. 26, 2021	Sep. 30, 2021
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Reverse stock split		0.083
Tengasco
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Reverse stock split	0.083

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Net Income (Loss) Per Share/Unit - Computation of Basic and Diluted Net Loss Per Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Sep. 30, 2021
Earnings Per Share [Abstract]
Net income (loss) - Diluted	$ 21,398	$ 118,011	$ (46,869)
Less: Dividends on preferred units	0	0	(1,491)
Net income (loss) attributable to common shareholders/unitholders - Basic	$ 21,398	$ 118,011	$ (48,360)
Basic weighted-average common shares/units outstanding (in Shares/Units)	19,470	19,553	16,021
Effecting of dilutive securities:
Restricted shares/units (in Shares/Units)	99	133	0
Diluted weighted-average common shares/units outstanding (in Shares/Units)	19,569	19,686	16,021
Basic net income (loss) per common share/unit (USD per Share/Unit)	$ 1.10	$ 6.04	$ (3.02)
Diluted net income (loss) per common share/unit (USD per Share/Unit)	$ 1.09	$ 5.99	$ (3.02)

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Net Income (Loss) Per Share/Unit - Schedule of Anti-Dilutive Shares/Units (Details) - shares shares in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Sep. 30, 2021
Restricted shares/units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive units (in Shares/Units)	268	405	228

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Commitment and Contingencies (Details)		1 Months Ended
	Oct. 13, 2022 USD ($)	Aug. 31, 2022	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Oct. 31, 2021 agreement
Loss Contingencies [Line Items]
Environmental liabilities			$ 0	$ 0
EOR Project
Loss Contingencies [Line Items]
Purchase obligation, number of agreements entered into | agreement					2
Drilling Program, Fiscal 2023
Loss Contingencies [Line Items]
Purchase obligation			$ 2,800,000
Stakeholder
Loss Contingencies [Line Items]
Purchase obligation, delivery period		7 years
Hoactzin Partners, L.P. | Settled Litigation
Loss Contingencies [Line Items]
Litigation settlement, amount awarded to other party	$ 80,000

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Subsequent Events - Narrative (Details) - USD ($)				3 Months Ended									4 Months Ended	12 Months Ended
	Feb. 22, 2023	Jan. 11, 2023	Mar. 04, 2021	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Jun. 30, 2023	Dec. 31, 2022	Sep. 30, 2021	Feb. 21, 2023	Oct. 25, 2022	Apr. 30, 2022	Sep. 28, 2017
Subsequent Event [Line Items]
Cash dividend declared (USD per Share/Unit)			$ 0.28	$ 0.34	$ 0.31	$ 0.31	$ 0.31	$ 0.31	$ 0.28	$ 0	$ 0.29	$ 0.30
Proceeds from revolving credit facility								$ 5,000,000						$ 22,000,000	$ 5,500,000
Revolving Credit Facility | Line of Credit
Subsequent Event [Line Items]
Borrowing base																	$ 225,000,000	$ 225,000,000	$ 25,000,000
Subsequent Event
Subsequent Event [Line Items]
Cash dividend declared (USD per Share/Unit)		$ 0.34
Subsequent Event | Revolving Credit Facility | Line of Credit
Subsequent Event [Line Items]
Borrowing base	$ 475,000,000															$ 225,000,000
NM Acquisition | Subsequent Event | Senior Notes | EOC Partners Advisors L.P
Subsequent Event [Line Items]
Debt Instrument, face amount	$ 200,000,000
Stated interest rate	10.50%
Maturity term	5 years
NM Acquisition | Subsequent Event | Forecast
Subsequent Event [Line Items]
Total consideration													$ 330,000,000
Escrow deposits related to property sales													33,000,000
NM Acquisition | Subsequent Event | Forecast | Revolving Credit Facility | Line of Credit
Subsequent Event [Line Items]
Proceeds from revolving credit facility													$ 130,000,000

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Subsequent Events - Derivative Instrument and Hedging Activities (Details) bbl in Thousands, MMBTU in Thousands		12 Months Ended
	Mar. 03, 2023 MMBTU $ / MMBTU $ / bbl bbl	Dec. 31, 2022 $ / bbl bbl
Oil Swaps Q1 2023
Subsequent Event [Line Items]
Notional Volume | bbl		225
Weighted average price (in usd per bbl/mmbtu)		53.65
Oil Swaps Q1 2023 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | bbl	225
Weighted average price (in usd per bbl/mmbtu)	53.65
Oil Swaps Q2 2023
Subsequent Event [Line Items]
Notional Volume | bbl		195
Weighted average price (in usd per bbl/mmbtu)		53.89
Oil Swaps Q2 2023 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | bbl	315
Weighted average price (in usd per bbl/mmbtu)	62.78
Oil Swaps Q3 2023
Subsequent Event [Line Items]
Notional Volume | bbl		126
Weighted average price (in usd per bbl/mmbtu)		53.79
Oil Swaps Q3 2023 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | bbl	216
Weighted average price (in usd per bbl/mmbtu)	63.04
Oil Swaps Q4 2023
Subsequent Event [Line Items]
Notional Volume | bbl		114
Weighted average price (in usd per bbl/mmbtu)		54.59
Oil Swaps Q4 2023 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | bbl	189
Weighted average price (in usd per bbl/mmbtu)	62.51
Oil Swap 2024 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | bbl	240
Weighted average price (in usd per bbl/mmbtu)	71.60
Oil Collars Q1 2023
Subsequent Event [Line Items]
Notional Volume | bbl		30
Oil Collars Q1 2023 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | bbl	210
Oil Collars Q1 2023 | Short
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu)		60.00
Oil Collars Q1 2023 | Short | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu)	70.95
Oil Collars Q1 2023 | Long
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu)		109.60
Oil Collars Q1 2023 | Long | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu)	89.96
Oil Collars Q2 2023
Subsequent Event [Line Items]
Notional Volume | bbl		30
Oil Collars Q2 2023 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | bbl	300
Oil Collars Q2 2023 | Short
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu)		60.00
Oil Collars Q2 2023 | Short | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu)	71.50
Oil Collars Q2 2023 | Long
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu)		109.60
Oil Collars Q2 2023 | Long | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu)	88.98
Oil Collars Q3 2023 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | bbl	330
Oil Collars Q3 2023 | Short | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu)	68.64
Oil Collars Q3 2023 | Long | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu)	88.85
Oil Collars Q4 2023 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | bbl	330
Oil Collars Q4 2023 | Short | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu)	68.64
Oil Collars Q4 2023 | Long | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu)	88.85
Oil Collars 2024
Subsequent Event [Line Items]
Notional Volume | bbl		3
Oil Collars 2024 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | bbl	1,293
Oil Collars 2024 | Short
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu)		50.00
Oil Collars 2024 | Short | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu)	61.02
Oil Collars 2024 | Long
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu)		88.00
Oil Collars 2024 | Long | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu)	86.39
Oil Collars 2025 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | bbl	315
Oil Collars 2025 | Short | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu)	60.00
Oil Collars 2025 | Long | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu)	77.98
Natural Gas Swaps Q2 2023 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | MMBTU	450
Weighted average price (in usd per bbl/mmbtu) | $ / MMBTU	2.60
Natural Gas Swaps Q3 2023 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | MMBTU	450
Weighted average price (in usd per bbl/mmbtu) | $ / MMBTU	2.60
Natural Gas Swaps Q4 2023 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | MMBTU	400
Weighted average price (in usd per bbl/mmbtu) | $ / MMBTU	3.23
Natural Gas Swaps 2024 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | MMBTU	1,500
Weighted average price (in usd per bbl/mmbtu) | $ / MMBTU	3.43
Natural Gas Swaps 2025 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | MMBTU	375
Weighted average price (in usd per bbl/mmbtu) | $ / MMBTU	4.05
Natural Gas Collars Q2 2023 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | MMBTU	300
Natural Gas Collars Q2 2023 | Short | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu) | $ / MMBTU	2.55
Natural Gas Collars Q2 2023 | Long | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu) | $ / MMBTU	3.20
Natural Gas Collars Q3 2023 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | MMBTU	300
Natural Gas Collars Q3 2023 | Short | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu) | $ / MMBTU	2.55
Natural Gas Collars Q3 2023 | Long | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu) | $ / MMBTU	3.20
Natural Gas Collars Q4 2023 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | MMBTU	300
Natural Gas Collars Q4 2023 | Short | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu) | $ / MMBTU	3.12
Natural Gas Collars Q4 2023 | Long | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu) | $ / MMBTU	4.07
Natural Gas Collars 2024 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | MMBTU	1,065
Natural Gas Collars 2024 | Short | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu) | $ / MMBTU	3.19
Natural Gas Collars 2024 | Long | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu) | $ / MMBTU	4.14
Natural Gas Collars 2025 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | MMBTU	255
Natural Gas Collars 2025 | Short | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu) | $ / MMBTU	3.65
Natural Gas Collars 2025 | Long | Subsequent Event
Subsequent Event [Line Items]
Weighted average price (in usd per bbl/mmbtu) | $ / MMBTU	4.95
Oil Basis Q1 2023 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | bbl	240
Weighted average price (in usd per bbl/mmbtu)	1.28
Oil Basis Q2 2023 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | bbl	360
Weighted average price (in usd per bbl/mmbtu)	1.28
Oil Basis Q3 2023 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | bbl	360
Weighted average price (in usd per bbl/mmbtu)	1.28
Oil Basis Q4 2023 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | bbl	360
Weighted average price (in usd per bbl/mmbtu)	1.28
Oil Basis 2024 | Subsequent Event
Subsequent Event [Line Items]
Notional Volume | bbl	960
Weighted average price (in usd per bbl/mmbtu)	0.87

XML

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Costs Incurred for Property Acquisition, Exploration and Development (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Sep. 30, 2021
Acquisition of properties
Proved	$ 67	$ 450	$ 74
Unproved	193	1,468	1,562
Exploration costs	0	157	7,993
Development costs	20,348	119,673	59,948
Total costs incurred	$ 20,608	$ 121,748	$ 69,577

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Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Results of Operations (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Sep. 30, 2021
Extractive Industries [Abstract]
Oil, natural gas and NGL sales	$ 56,650	$ 319,343	$ 148,636
Lease operating expenses	7,419	32,458	21,975
Production and ad valorem taxes	3,005	19,273	8,636
Exploration costs	611	2,032	9,566
Depletion, accretion and amortization	6,742	31,500	25,347
Impairment of oil and natural gas properties	0	7,325	0
Results of operations	38,873	226,755	83,112
Income tax expense	(8,393)	48,957	(13,505)
Results of operations, net of income tax expense	$ 30,480	$ 275,712	$ 69,607
Combined federal and state statutory income tax rate, percent	21.59%	21.59%	21.59%

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Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Oil, Natural Gas and NGL Quantities (Details) bbl in Thousands, Mcf in Thousands, Boe in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2021 Boe bbl Mcf	Dec. 31, 2022 Boe bbl Mcf	Sep. 30, 2021 Boe bbl Mcf
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Beginning balance | Boe	72,163	73,407	56,787
Extensions and discoveries | Boe	2,026	14,796	13,759
Revisions | Boe	133	(6,331)	4,772
Production | Boe	(915)	(4,199)	(3,155)
Ending balance | Boe	73,407	77,673	72,163
Proved Developed Reserves, Included Above | Boe	43,041	49,122	41,516
Proved Undeveloped Reserves, Included Above | Boe	30,366	28,551	30,647
Oil
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	46,263	47,021	37,158
Extensions and discoveries	1,328	9,949	9,308
Revisions	99	(4,871)	2,138
Production	(669)	(3,217)	(2,341)
Ending balance	47,021	48,882	46,263
Proved Developed Reserves, Included Above	27,096	29,632	26,170
Proved Undeveloped Reserves, Included Above	19,925	19,250	20,093
Natural Gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | Mcf	76,019	77,486	53,683
Extensions and discoveries | Mcf	1,961	13,178	12,089
Revisions | Mcf	350	(1,417)	12,850
Production | Mcf	(844)	(3,229)	(2,603)
Ending balance | Mcf	77,486	86,018	76,019
Proved Developed Reserves, Included Above | Mcf	47,974	59,314	46,173
Proved Undeveloped Reserves, Included Above | Mcf	29,512	26,704	29,846
NGLs
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	13,229	13,471	10,681
Extensions and discoveries	371	2,651	2,436
Revisions	(24)	(1,224)	492
Production	(105)	(444)	(380)
Ending balance	13,471	14,454	13,229
Proved Developed Reserves, Included Above	7,949	9,604	7,650
Proved Undeveloped Reserves, Included Above	5,522	4,850	5,579

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Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Narrative (Details) Boe in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2021 Boe	Dec. 31, 2021 $ / bbl	Dec. 31, 2021 $ / MMBTU	Dec. 31, 2021 $ / Mcf	Dec. 31, 2022 Boe $ / Mcf $ / bbl $ / MMBTU	Sep. 30, 2021 Boe	Sep. 30, 2021 $ / bbl	Sep. 30, 2021 $ / MMBTU	Sep. 30, 2021 $ / Mcf
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Revisions	133				(6,331)	4,772
Extensions and discoveries	2,026				14,796	13,759
Result of drilling successful wells that were previously classified as unproved locations					7,759	6,564
Result of drilling successful wells offsetting locations that were previously unproven locations					7,037	7,195
West Texas Intermediate (WTI)
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Oil and natural gas liquids, average WTI intermediate spot price (USD per bbl) | $ / bbl		66.55			94.14		57.64
Henry Hub
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Gas, average henry hub spot price (USD per mmbtu) | $ / MMBTU			3.60		6.36			2.94
Oil
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Percentage of reserves	64.10%	64.10%	64.10%	64.10%	62.90%	64.10%	64.10%	64.10%	64.10%
Price (USD per bbl/mcf) | $ / bbl		64.60			91.96		55.73
Natural Gas
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Percentage of reserves	17.60%	17.60%	17.60%	17.60%	18.50%	17.60%	17.60%	17.60%	17.60%
Price (USD per bbl/mcf)		1.65		1.65	3.16		0.99		0.99
NGLs
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Percentage of reserves	18.30%	18.30%	18.30%	18.30%	18.60%	18.30%	18.30%	18.30%	18.30%
Price (USD per bbl/mcf)		13.75		13.75	25.55		9.83		9.83

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Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves (Details) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2021 USD ($) $ / bbl	Dec. 31, 2021 USD ($) $ / Mcf	Dec. 31, 2022 USD ($) $ / Mcf $ / bbl	Sep. 30, 2021 USD ($) $ / bbl	Sep. 30, 2021 USD ($) $ / Mcf	Sep. 30, 2020 USD ($)
Extractive Industries [Abstract]
Future crude oil, natural gas and NGLs sales	$ 3,350,506	$ 3,350,506	$ 5,135,650	$ 2,783,910	$ 2,783,910
Future production costs	(912,468)	(912,468)	(1,559,266)	(839,167)	(839,167)
Future development costs	(216,138)	(216,138)	(341,481)	(218,765)	(218,765)
Future income tax expense	(436,829)	(436,829)	(658,340)	(324,487)	(324,487)
Future net cash flows	1,785,071	1,785,071	2,576,563	1,401,491	1,401,491
10% annual discount	(1,081,602)	(1,081,602)	(1,468,187)	(848,555)	(848,555)
Standardized measure of discounted future net cash flows	$ 703,469	$ 703,469	$ 1,108,376	$ 552,936	$ 552,936	$ 302,338
Oil
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Price (USD per bbl/mcf) | $ / bbl	64.60		91.96	55.73
Natural Gas
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Price (USD per bbl/mcf)	1.65	1.65	3.16	0.99	0.99
NGLs
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Price (USD per bbl/mcf)	13.75	13.75	25.55	9.83	9.83

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Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves Rollforward (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Sep. 30, 2021
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance, beginning of period	$ 552,936	$ 703,469	$ 302,338
Sales of crude oil, natural gas and NGLs, net	(46,226)	(267,612)	(118,030)
Net change in prices and production costs	194,596	406,803	237,475
Net changes in future development costs	1,267	(40,226)	(18,856)
Extensions and discoveries	35,111	321,009	144,392
Revisions of previous quantity estimates	(536)	(83,188)	50,283
Previously estimated development costs incurred	4,182	8,775	12,844
Net change in income taxes	(47,881)	(117,098)	(124,625)
Accretion of discount	17,018	87,914	30,551
Other	(6,998)	88,530	36,564
Balance, end of period	$ 703,469	$ 1,108,376	$ 552,936

XML

Label	Element	Value
Member Units [Member]
Net Income (Loss) Attributable to Parent	us-gaap_NetIncomeLoss	$ (27,058,000)
Retained Earnings [Member]
Net Income (Loss) Attributable to Parent	us-gaap_NetIncomeLoss	$ (38,608,000)