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United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-K

Form 10-K

(Mark One)

☒Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 20172021

Or

Or☐Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from ___________to ___________to

Commission file number 001-36057

Ring Energy, Inc.

(Exact name of registrant as specified in its charter)

(432) 682-7464

(Registrant’s telephone number, including area code)

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Securities registered under Section 12(b) of the Exchange Act:

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Securities registered under Section 12(g) of the Exchange Act:None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes¨.☐ Nox☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes¨.☐ Nox☒

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act 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. Yesx.☒ No¨☐

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). Yesx.☒ No¨

Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.x

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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”,filer,” “accelerated filer,” and “smaller reporting company,” and emerging growth company” in Rule 12b-2 of the Exchange Act.

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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.¨

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 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

Indicate by check mark whether the registrant is shell company (as defined in Rule 12b-2 of the Act). Yes¨.☐ Nox

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As of June 30, 2017,2021, the aggregate market value of the common voting stock held by non-affiliates of the issuer, based upon the closing stock price on the NYSE MKTAmerican of $13.00$2.98 per share, was approximately $586,591,070.

$254,767,528.

As of March 14, 2018,16, 2022, the issuer had outstanding 60,388,029100,192,562 shares of common stock ($0.001 par value).

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of this 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 2021, 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 Report relates.

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Forward Looking Statements

This Annual Report on Form 10-K (herein, “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 included in this Annual Report on Form 10-K (herein, “Annual Report”) regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words “may,” “will,” “could,” “would,” “should,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “plan,” “pursue,” “target,” “continue,” “potential,” “guidance,” “project” andor other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. All forward-looking statements speak only as of the date of this Annual Report. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We discloseare making investors aware that such forward-looking statements, because they relate to future events, are by their very nature subject to many important factors that could cause our actual results to differ materially from those contemplated. Such factors include: declines or volatility in the prices we receive for our expectations underoil and natural gas; our ability to raise additional capital to fund future capital expenditures; our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop and produce our oil and natural gas properties; general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business; risks associated with drilling, including completion risks, cost overruns and the drilling of non-economic wells or dry holes; uncertainties associated with estimates of proved oil and natural gas reserves; the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs; risks and liabilities associated with acquired companies and properties; risks related to integration of acquired companies and properties; potential defects in title to our properties; cost and availability of drilling rigs, equipment, supplies, personnel and oilfield services; geological concentration of our reserves; environmental or other governmental regulations, including legislation of hydraulic fracture stimulation; our ability to secure firm transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices; exploration and development risks; management’s ability to execute our plans to meet our goals; our ability to retain key members of our management team on commercially reasonable terms; the occurrence of cybersecurity incidents, attacks or other breaches to our information technology systems or on systems and infrastructure used by the oil and gas industry; weather conditions; actions or inactions of third-party operators of our properties; costs and liabilities associated with environmental, health and safety laws; our ability to find and retain highly skilled personnel; operating hazards attendant to the oil and natural gas business; competition in the oil and natural gas industry; evolving geopolitical and military hostilities in the Middle East, Russia and Ukraine; the ongoing COVID-19 pandemic, including any reactive or proactive measures taken by businesses, governments and by other organizations related thereto, and the direct and indirect effects of COVID-19 on the market for and price of oil;  and the other factors discussed in Part I, Item 1A-- “Risk Factors,” “Management’s DiscussionFactors” in this Annual Report, as well as in our consolidated financial statements, related notes, and Analysis of Financial Condition and Results of Operations” andthe other financial information appearing elsewhere in this Annual Report. These cautionary statements qualify allReport and our other reports filed from time to time with the Securities and Exchange Commission (the “SEC”).

Readers are cautioned not to place undue reliance on forward-looking statements, attributablewhich speak only as of the date that such statements are made. We undertake no obligation to uspublicly update or persons acting on our behalf.

revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

Unless the context otherwise requires, references in this Annual Report to “Ring,” “the Company,“Ring Energy,” the “Company,” “we,” “us,” “our” or “ours” refer to Ring Energy, Inc.

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PART I

General

Ring was incorporated inEnergy, Inc., a Nevada corporation (“Ring,” “Ring Energy,” the State of Nevada in 2004 as “Blanca Corp.“Company,” The name of the corporation was changed to “Transglobal Mining Corp.“we,” in 2007 before being changed to “Ring Energy, Inc.“us,” in 2008. We are“our,” or similar terms), is a Midland-basedgrowth oriented independent exploration and production company thatbased in The Woodlands, Texas and is engaged in oil and natural gas development, production, acquisition, and exploration development and production activities. Our exploration and production interests areactivities currently focused in Texas. The Company takes a conventional approach to its drilling programTexas and seeks to develop its traditional core areas, as well as look for new growth opportunities.

The Company’sNew Mexico. Our primary drilling operations target the oil and liquids rich producing formations in the Northwest Shelf, the Central Basin Platform, in Andrews County and Gaines County, Texas and the Delaware Basin all of which are part of the Permian Basin in Reeves CountyTexas and Culberson County, Texas. As of December 31, 2017, Ring had 102,777 gross (69,874 net) acres in Andrews and Gaines counties and 20,218 gross (19,917 net) acres in Reeves and Culberson counties.

New Mexico.

As of December 31, 2017, Ring’s proved2021, our leasehold acreage positions totaled 83,604 gross (64,380 net) acres and we held interests in 491 gross (333 net) producing wells. Proved reserves as of December 31, 2021 were approximately 31.977.8 million BOE (barrel of oil equivalent), of which we are the operator of approximately 98%.  All of its reserves (based on the estimates above) relate toour properties are located in Texas.the Permian Basin in Texas and New Mexico. The Company’s proved reserves are oil-weighted with 91% of proved reservesapproximately 85% consisting of oil and 9%15% consisting of natural gas. Of those reserves, 45% of the proved reservesapproximately 56% are classified as proved developed producing, or “PDP,” 10% are classified as proved developed non-producing, or “PDNP,”“PD” and approximately 45%44% are classified as proved undeveloped, or “PUD.” For the calculation of BOE, oil is weighted on a 6 to 1 ratio against natural gas.

Our Mission

ProductionRing’s mission is to deliver competitive and sustainable returns to its shareholders by developing, acquiring, exploring for, and commercializing oil and natural-gas resources vital to the world’s health and welfare.

Our Business Strategy

Successfully achieving Ring’s mission requires a firm commitment to operating safely in a socially responsible and environmentally friendly manner. Key principles supporting Ring’s strategic vision are to:

Our strategic vision is guided by these key principles and implemented by pursuing the following five strategic objectives.

Attract and retain highly qualified people - Achieving our mission will only be possible through our employees. It is critical to have compensation, development, and human resource programs that attract, retain and motivate the types of people we need to succeed.

Pursue operational excellence with a sense of urgency - We plan to deliver low cost, consistent, timely and efficient execution of our drilling campaigns, work programs and operations. We will execute our operations in a safe and environmentally responsible manner, focus on reducing our emissions, apply advanced technologies, and continuously seek ways to reduce our operating cash costs on a per barrel basis. This objective is a foundational aspect of our culture and future success.

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Invest in high-margin, high rate-of-return projects - Another key to achieving our mission will be to prioritize our work programs and allocate capital to the highest return opportunities in our inventory. This objective is key to profitably growing our production and reserve levels and generating the excess cash from operations to pay down debt.

Focus on generating free cash flow and strengthen our balance sheet - Ring intends to reduce its long-term debt through the use of excess cash from operations and potentially through the sale of non-core assets. Continuing to generate free cash flow through a disciplined capital allocation program and reducing our operating and corporate costs are key components of this objective. Our capital program will be funded by operational cash flow and limited to balance our production and reserve growth versus paying down debt. Remaining focused and disciplined in this regard will lead to meaningful returns for our shareholders and provide additional financial flexibility to manage potential future swings in the business cycle. Our commodity hedges are designed to help ensure the necessary cash flow to adhere to these plans while retaining the flexibility to participate in prevailing commodity markets.

Pursue strategic acquisitions that maintain or reduce our break-even costs - We will actively pursue accretive acquisitions, mergers and dispositions that improve our margins, returns, and break-even costs of our investment portfolio. Financial strategies associated with these efforts will focus on delivering competitive debt-adjusted per share returns. This objective is key to delivering competitive returns to our shareholders on a sustainable basis.

2019 Acquisition

In 2019, a significant portion of the increase in acreage and reserves was the result of our acquisition of properties from Wishbone Energy Partners, LLC, Wishbone Texas Operating Company LLC and WB WaterWorks LLC on the Northwest Shelf in Gaines, Yoakum, Runnels and Coke Counties, Texas and Lea County, New Mexico that was completed in April 2019.  This acquisition contributed all of the acreage we have on the Northwest Shelf. It also contributed approximately 45.3 million BOE of our 81.1 million BOE of proved reserves as of December 31, 2019.

Appointment of Certain Officers and Directors

On March 24, 2021, the Company’s board of directors appointed Travis Thomas as Chief Financial Officer.

Primary Business Operations

The Company seeks to rigorously manage its asset portfolio to optimize shareholder value over the long term. As the weak commodity price environment began to recover and the contraction in oil demand seen from the COVID-19 pandemic began to ease, Ring initiated its Phase I four well program in the Northwest Shelf Asset by drilling two wells in December 2020 and two wells in January 2021.  All four wells were completed and placed on production during first quarter 2021.  During that quarter, the Company also performed nine conversions from electrical submersible pumps to rod pumps (such conversions, “CTRs”) with seven performed in the Northwest Shelf and two in the Central Basin Platform. New wells were added throughout the year ended December 31, 2017, was 1,438,647 BOE, as comparedby drilling in phases, to ensure the Company would continue operating within cash flow.  In the second quarter of 2021, the Company completed its Phase II drilling program and placed on production three new horizontal San Andres wells in the Northwest Shelf, along with four additional CTRs in the Northwest Shelf and one CTR in the Central Basin Platform. In third quarter 2021, the Phase III drilling program resulted in two horizontal San Andres wells in Northwest Shelf and two horizontal San Andres wells in the Central Basin Platform. During the third quarter of 878,066 BOE for2021, the year ended December 31, 2016, a 64% increaseCompany also performed seven CTRs in BOE. The stated production amount reflects only the oilNorthwest Shelf and gas that was produced and shipped prior tothree CTRs in the end of the fourth quarter. Any oil and gas produced inCentral Basin Platform.  In the fourth quarter but still held on site after December 31, 2017, will be creditedof 2021, the Company drilled one new well and performed one CTR in the first quarter of 2018.

Northwest Shelf and drilled one new well in the Central Basin Platform.  Lastly, during 2021 the Company participated with offset operators in two wells in the Northwest Shelf Asset as a non-operating working interest owner.

Ring believes that there is significant value to be created by drilling the identified undeveloped opportunities on its Texas properties.and New Mexico properties and intends to focus its drilling efforts in 2022 primarily in the Northwest Shelf and Central Basin Platform.

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Table of December 31, 2017, Ring owned interests in a total of 11,917 gross (8,102 net) developed acres and 90,860 gross (61,772 net) undeveloped acres in Andrews and Gaines County, Texas. In these counties, the Company has 140 identified proven vertical drilling locations and 11 identified proven horizontal locations based on the reserve reports as of December 31, 2017, and an additional 396 potential vertical drilling locations based on 10-acre downspacing and 796 potential horizontal drilling locations based on 6 wells per section or 106 acres per well. Also as of December 31, 2017, Ring owned interests in a total of 10,390 gross (10,235 net) developed acres and 9,828 (9,682 net) undeveloped acres in Culberson and Reeves County, Texas. In these counties, the Company has 39 identified proven vertical drilling locations based on the reserve reports as of December 31, 2017 and an additional 452 potential vertical drilling locations based on 20-acre downspacing. Contents

Ring intends to grow its reserves and production through development, drilling, exploitation and exploration activities on this multi-year project inventory of identified potential drilling locations and through acquisitions that meet the Company’s strategic and financial objectives, targeting oil-weighted reserves.

Business Segments

Our operations are all oil and gas exploration and production related activities in the United States.

Principal Executive Office

Our principal executive offices are located at 901 West Wall St., 3^rd Floor, Midland, TX 79702, and our telephone number is (432) 682-7464. Our Internet website can be found at www.ringenergy.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 will be available through our Internet website as soon as reasonably practical after we electronically file such material with, or furnish it to, the SEC. The information on, or that can be accessed through, our website is not incorporated by reference into this Annual Report and should not be considered part of this Annual Report.

Ring Energy’s Business Strategy and Development

Ring Energy’s Strengths

Competitive Business Conditions

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 of our 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. Also, there is substantial competition for capital available for investment in the oil

Marketing and natural gas industry.

Pricing

The actual price range of crude oil is largely established by major crude oil purchasers and commodities trading. Pricing for natural gas is based on regional supply and demand conditions. To this extent, we believe we receive oil and natural gas prices comparable to other producers. ThereWe believe there is little risk in our ability to sell all our current production at current prices with a reasonable profit margin. The risk of domestic overproduction at current prices is not deemed significant.prevailing prices. We view our primary pricing risk to be related to a potential declinedeclines in oil and gas prices to a level which could render our current production uneconomical.

uneconomical as our primary pricing risk.

We are presently committed to use the services of the existing gathering systems of the companies that purchase our natural gas production. This commitment is tied to existing natural gas purchase contracts associated with our production, This commitmentwhich potentially gives such gathering companies certain short-term relative monopolistic powers to set gathering and transportation costs, because obtainingcosts. Obtaining the services of an alternative gathering company would require substantial additional costs (since an alternative gathering company would be required to lay new pipeline and/or obtain new rights of way to any lease from which we are selling production).

We are not subject to third partythird-party gathering systems forwith respect to our oil production. Some of our oil production is sold through a third partythird-party pipeline which has no regional competition. Allcompetition and all other oil production is transported by the oil purchaser by trucks with competitive trucking costs in the area.

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Major Customers

We principally sell our oil and natural gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities. In areas where there is no practical access to pipelines, oil is trucked to storage facilities. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted.

For the fiscal year ended December 31, 2017,2021, sales to twothree customers, OccidentalPhillips 66 Company (“Phillips”), NGL Crude Partners (“NGL Crude”), and BP Energy MarketingCompany (“Oxy”) and Enterprise Crude Oil LLC (“Enterprise”BP”) represented 76%, 7% and 18%6%, respectively, of our oil and natural gas revenues. AtAs of December 31, 2017, Oxy2021, Phillips represented 88%75% of our accounts receivable, NGL Crude represented 8% of our accounts receivable and Plains Marketing, L.P. (“Plains”)BP represented 10%. Effective December 1, 2017, the production previously being sold to Enterprise was sold to Plains.4% of our accounts receivable. We believe that the loss of any of these customers would not materially impact our business because we could readily find other purchasers for our oil and gas produced.

natural gas.

Delivery Commitments

As of December 31, 2017,2021, we were not committed to providing a fixed quantity of oil or gas under any existing contracts.

Governmental Regulations

Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affectscan affect our profitability.

Regulation of Drilling and Production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. AllThe trend in oil and natural gas regulation has been to increase regulatory restrictions and limitations on such activities. Any changes in, or more stringent enforcement of, these laws and regulations may result in delays or restrictions in permitting or development of projects or more stringent or costly construction, drilling, water management or completion activities or waste handling, storage, transport, remediation, or disposal emission or discharge requirements which could have a material adverse effect on the Company. For example, in January 2021, President Biden signed an Executive Order directing the Department of Interior (the “DOI”) to temporarily pause new oil and gas leases on federal lands and waters pending completion of a comprehensive review of the statesfederal government’s existing oil and gas leasing and permitting program. In June 2021, a federal district court enjoined the DOI from implementing the pause and leasing resumed, although litigation over the leasing pause remains ongoing. In February 2022, another judge ruled that the Biden Administration’s efforts to raise the cost of climate change in whichits environmental assessments, would increase energy costs and damage state revenues from energy production. This ruling has cause federal agencies to delay issuing new oil and gas leases and permits on federal lands and waters. The Biden Administration has also announced that it intends to review the Trump Administration’s 2017 repeal of the 2015 rule regulating hydraulic fracturing activities in federal land under the Presidential Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis. While we owndo not have a significant federal lands acreage position (240 net acres as of December 31, 2021), these actions could have a material adverse effect on our industry and operatethe Company.

Currently, all of our properties and operations are in Texas and New Mexico, which have regulations governing conservation matters, including provisions forsuch as 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, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposesboth Texas and New Mexico impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

their jurisdictions.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

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Regulation of Transportation of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless,prices, however, Congress could reenact price controls in the future.

Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission, or the FERC,(“FERC”), regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. 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 are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors. Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Regulation of Transportation and Sale of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those Acts by the 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.

Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Therefore, we cannot provide any assurance that the less stringent regulatory approach established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

Intrastate natural gas transportation is 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, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors.

Environmental Compliance and Risks

Our oil and natural gas exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Historically, mostAt the federal level, among the more significant laws that may affect our business and the oil and natural gas industry generally are: the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”); the Oil Pollution Act of 1990 (“OPA”); the Resource Conservation and Recovery Act (“RCRA”); the Clean Air Act (“CAA”); Federal Water Pollution Control Act of 1972, or the Clean Water Act (“CWA”); and the Safe Drinking Water Act of 1974 (“SWDA”). These federal laws are administered by the United States Environmental Protection Agency (“EPA”). Generally, these laws (i) regulate air and water quality, impose limitations on the discharge of pollutants and establish standards for the handling of solid and hazardous wastes; (ii) subject our operations to certain permitting and registration requirements; (iii) require remedial measures to mitigate pollution from former or

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ongoing operations; and (iv) may result in the assessment of administrative, civil and criminal penalties for failure to comply with such laws. In addition, there is environmental regulation of oil and gas production has been left toby state regulatory boards or agenciesand local governments in thosethe jurisdictions where there is significant gas and oil production, with limited direct regulation by such federal agencies as the Environmental Protection Agency. However, while we believe this generally to be the case for our production activities in Texas,operate. As described below, there are various regulations issued by the Environmental Protection Agency (“EPA”)EPA and other governmental agencies pursuant to these federal statutes that would govern significant spills, blow-outs, or uncontrolled emissions.

our operations.

In Texas and New Mexico, specific oil and natural gas regulations apply to oil and gas operations, including the drilling, completion and operations of wells, and the disposal of waste oil and salt water.saltwater. There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency.

At the federal level, among the more significant laws and regulations that may affect our business and the oil and natural gas industry are: The Comprehensive Environmental Response, Compensation

Hazardous Substances and Liability Act of 1980,Wastes

CERCLA, also known as “CERCLA” or “Superfund; the Oil Pollution ActSuperfund law, and analogous state laws impose liability on certain classes of 1990; the Resource Conservation and Recovery Act, alsopersons, known as “RCRA,“potentially responsible parties,”; for the Clean Air Act;disposal or release of a regulated hazardous substance into the environment. These potentially responsible parties include (1) the current owners and operators of a facility, (2) the past owners and operators of a facility at the time the disposal or release of a hazardous substance occurred, (3) parties that arranged for the offsite disposal or treatment of a hazardous substance, and (4) transporters of hazardous substances to off-site disposal or treatment facilities. While petroleum and natural gas liquids are not designated as a “hazardous substance” under CERCLA, other chemicals used in or generated by our operations may be regulated as hazardous substances. Potentially responsible parties under CERCLA may be subject to strict, joint and several liability for the costs of investigating and cleaning up environmental contamination, for damages to natural resources and for the costs of certain health studies. In addition to statutory liability under CERCLA, common law claims for personal injury or property damage can also be brought by neighboring landowners and other third parties related to contaminated sites.

RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of solid and hazardous wastes. Under a delegation of authority from the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal Water Pollution Control Actand state regulatory agencies can seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Certain wastes associated with the production of 1972,oil and natural gas, as well as certain types of petroleum-contaminated media and debris, are excluded from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead, are regulated as solid waste (i.e. non-hazardous waste) under the less stringent provisions of Subtitle D of RCRA. It is possible, however, that certain wastes now classified as non-hazardous could be classified as hazardous wastes in the future and therefore be subject to more rigorous and costly disposal requirements. Legislation has been proposed from time to time in Congress to regulate certain oil and natural gas wastes as hazardous waste under RCRA. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our consolidated results of operations and financial position.

Under CERCLA, RCRA and analogous state laws, we could be required to remove or the Clean Water Act;remediate environmental impacts on properties we currently own and the Safe Drinking Water Actlease or formerly owned or leased (including hazardous substances or wastes disposed of 1974.

or released by prior owners or operators), to clean up contaminated off-site disposal facilities where our wastes have come to be located or to implement remedial measures to prevent or mitigate future contamination. Compliance with these regulationslaws may constitute a significant cost and effort for us. No specific accounting for environmental compliance has been maintained or projected by us at this time. We are not presently aware of any environmental demands, claims, or adverse actions, litigation or administrative proceedings in which either we or our acquired properties are involved in or subject to, or arising out of any predecessor operations.

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Air Emissions

Our operations are subject to the CAA and comparable state and local laws and regulations, which regulate emissions of air pollutants from various sources and mandate certain permitting, monitoring, recordkeeping and reporting requirements. The CAA and its implementing regulations may require that we obtain permits prior to the construction, modification or operation of certain projects or facilities expected to produce or increase air emissions above certain threshold levels and strictly comply with those permits, including emissions and operational limitations. These permits may require us to install emission control technologies to limit emissions, which can impose significant costs on our business. In 2012 and 2016, the EPA issued New Source Performance Standards to regulate emissions of sources of volatile organic compounds (“VOCs”), sulfur dioxide, air toxics and methane from various oil and natural gas exploration, production, processing and transportation facilities. On May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. However, in a March 28, 2017 executive order, the Trump Administration directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rule making to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. In September 2020, the EPA finalized amendments to the 2016 standards that removed the transmission and storage segment from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. However, President Biden signed an executive order on his first day in office calling for the suspension, revision, or rescission of the September 2020 rule and the reinstatement or issuance of methane emission standards for new, modified, and existing oil and gas facilities. Given the long-term trend toward increasing regulation, future federal Greenhouse Gas (“GHG”) regulations of the oil and gas industry remain a possibility, and several states have separately imposed their own regulations on methane emissions from oil and gas production activities. In November 2021, the EPA proposed new source performance standards and emissions guidelines to reduce methane and other pollution from new and existing sources in the oil and gas industry. The proposed rule would include, among other things, a comprehensive monitoring program for new and existing well sites, zero-emissions standards for new and existing pneumatic controls, and standards to eliminate venting of associated gas and requirements for the capture and sale of natural gas where a sales line is available. If adopted, these requirements could increase our costs to operate and control pollution. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions. Until these rules are formally adopted, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

In October 2015, the EPA announced that it was lowering the primary National Ambient Air Quality Standards (“NAAQS”) for ozone from 75 parts per billion to 70 parts per billion. Since that time, the EPA has issued area designations with respect to ground-level ozone. In December 2020, the EPA announced its intention to leave the ozone NAAQS unchanged at 70 parts per billion rather than lower them further. However, as discussed above, that action could be subject to reversal following the Biden Administration’s January 2021 executive order. In 2022, the New Mexico Environment Department is expected to issue final rules imposing more stringent limits on ozone pollution from the oil and gas industry operating in the state. Reclassification of areas of state implementation of the revised NAAQS could result in stricter permitting requirements, delay, or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.

Moreover, the NMOCD recently adopted new rules, which require oil and gas operators to capture 98 percent of their natural gas waste by the end of 2026. The new rules went into effect on May 25, 2021. While the State of Texas has not formally conducted a recent rulemaking related to air emissions, scrutiny of oil and natural gas operations and the rules affecting them have increased in recent years. For example, the EPA and environmental non-governmental organizations have conducted flyovers with optical gas imaging cameras to survey emissions from oil and natural gas production facilities and transmission infrastructure. In addition, the RRC has increased oversight related to flaring, with reporting reviews and site inspections. While none of these activities increases our compliance obligations, they signal the potential for increased enforcement and possible rulemaking in the future.

Oil Pollution Prevention

The OPA amended the CWA to impose liability for releases of crude oil from vessels or facilities into navigable waters. If a release of crude oil into navigable waters occurs during shipment or from an oil terminal, we could be subject to liability under the OPA. In 1973, the EPA adopted oil pollution prevention regulations under the CWA. These oil pollution prevention regulations require the preparation of a Spill Prevention Control and Countermeasure (“SPCC”) plan for facilities engaged in drilling, producing, gathering,

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storing, processing, refining, transferring, distributing, using, or consuming crude oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. SPCC requirements under the CWA require appropriate containment berms and similar structures to help prevent the discharge of pollutants into regulated waters in the event of a breachcrude oil or other constituent tank spill, rupture or leak. The SPCC regulations require affected facilities to prepare a written, site-specific SPCC plan, which details how a facility’s operations comply with the requirements of environmentalthe pollution prevention regulations. To be in compliance, the facility’s SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intra-facility piping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution. Where applicable, we maintain and implement SPCC plans for our facilities.

Water Discharges

The CWA and analogous state laws and regulations these environmentalimpose restrictions and strict controls regarding the discharge of pollutants into navigable waters, defined as waters of the United States (“WOTUS”), as well as state waters. The CWA prohibits the placement of dredge or fill material in wetlands or other WOTUS unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”) or a delegated state agency pursuant to Section 404. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Also, in June 2016, the EPA issued a final rule implementing wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly owned treatment works. This restriction of disposal options for hydraulic fracturing waste and other changes to CWA requirements may result in increased costs. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

The scope of EPA’s and the Corps’ regulatory authority under Section 404 of the CWA has been the subject of extensive litigation and frequently changing regulations. The EPA issued a final rule in September 2015 that attempted to clarify the federal jurisdictional reach over WOTUS under Section 404 of the CWA. The EPA and the Corps issued a final rule in January 2018 staying implementation of the 2015 WOTUS rule for two years. On October 22, 2019, EPA and the Corps published a final rule repealing the 2015 WOTUS rule. The EPA and the Corps replaced the 2015 WOTUS rule by promulgating the Navigable Waters Protection Rule on April 21, 2020, which provides a revised definition of WOTUS and became effective on June 22, 2020.  These regulations have been challenged in federal court, however, and the scope of the CWA’s jurisdiction may remain fluid until all litigation is concluded. Further regulatory changes are likely, as the current administration has announced that it intends to review the Navigable Waters Protection Rule under the January 20, 2021 Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis. In November 2021, the EPA and the Corps issued a proposed rule to broaden the applicability of the definition of WOTUS. The agencies did not announce a date for official publication in the Federal Register of the new rule. However, future rulemakings regarding the definition of WOTUS will likely be subject to litigation. As a result of these developments, the scope of federal jurisdiction under the Clean Water Act is uncertain at this time. The pending litigation and future regulations concerning the definition of WOTUS may result in an expansion of the scope of the CWA’s jurisdiction, and we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in WOTUS in connection with our operations.

Underground Injection Control

The underground injection of crude oil and natural gas wastes is regulated by the Underground Injection Control (“UIC”) program, as authorized by the SDWA, as well as by state programs. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluid from the injection zone into underground sources of drinking water, as well as to prevent communication between injected fluids and zones capable of producing hydrocarbons. The SDWA establishes requirements for permitting, testing, monitoring, recordkeeping, and reporting of injection well activities, as well as a prohibition against the migration of fluid containing contaminants into underground sources of drinking water. Any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in the suspension of permits, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third parties for property damages and personal injuries.

Under the auspices of the federal UIC program as implemented by states with UIC primacy, regulators, particularly at the state level, are becoming increasingly sensitive to possible correlations between underground injection and seismic activity. Consequently,

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state regulators implementing both the federal UIC program and state corollaries are heavily scrutinizing the location of injection facilities relative to faulting and are limiting both the density and injection facilities as well as the rate of injection.

In New Mexico, the New Mexico Oil Conservation Division (“NMOCD”) administers the UIC program for all injection wells that are related to oil and natural gas production. In Texas, the Texas Railroad Commission (“RRC”) regulates the disposal of produced water by injection well. Permits must be obtained before drilling saltwater disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking salt water to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In response to recent seismic events near underground injection wells used for the disposal of oil and natural gas-related waste waters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or placed volumetric injection limits on existing wells or imposed moratoria on the use of such injection wells. In response to concerns related to induced seismicity, regulators in some states have already adopted or are considering additional requirements related to seismic safety. For example, the RRC has adopted rules for injection wells to address these seismic activity concerns in Texas. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. In 2021, the NMOCD announced a new plan for responding to increased seismic activity in the Permian Basin. Under the new plan, pending permits for wastewater injection in certain areas will be subject to additional reporting and monitoring requirements. More stringent regulation of injection wells could lead to reduced construction or the capacity of such wells, which could in turn impact the availability of injection wells for disposal of wastewater from our operations. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability. The costs associated with the disposal of proposed water are commonly incurred by all oil and natural gas producers, however, and we do not believe that these costs will have a broad rangematerial adverse effect on our operations. In addition, third-party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.

Hydraulic Fracturing

Hydraulic fracturing is a practice in the oil and natural gas industry used to stimulate production of alternative natural gas and/or cumulative remediesoil from low permeability subsurface rock formations by injecting water, sand and chemicals under pressure. Oil and natural gas may be recovered from certain of our oil and natural gas properties through the use of hydraulic fracturing. Hydraulic fracturing is subject to regulation by state regulatory authorities, and several federal agencies have asserted federal regulatory authority over certain aspects of the hydraulic fracturing process. For example, the EPA published permitting guidance in February 2014 addressing the use of diesel fuel in fracturing operations, and in June 2016 EPA issued final effluent limitations guidelines under the CWA that waste-water from shale natural gas extraction operations must meet before discharging to a publicly owned treatment works. The EPA also issued an Advance Notice of Proposed Rulemaking under the Toxic Substances Control Act (“TSCA”) in 2014 regarding reporting of the chemical substances and mixtures used in hydraulic fracturing but, to date, has taken no further action. Separately, the BLM published a final rule in March 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands. However, a Wyoming federal court struck down this rule in June 2016. The June 2016 decision was appealed by the BLM to the U.S. Circuit Court of Appeals for the Tenth Circuit. However, following issuance of a presidential executive order to review rules related to the energy industry, in July 2017, the BLM published a notice of proposed rulemaking to rescind the 2015 final rule. In September 2017, the Tenth Circuit issued a ruling to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the 2015 rule in light of the BLM’s proposed rulemaking. The BLM issued a final rule repealing the 2015 hydraulic fracturing rule in December 2017. The current administration has announced that it intends to review the repeal of the 2015 hydraulic fracturing rule under the Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis.

Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process but, at this time, federal legislation related to hydraulic fracturing appears uncertain. In Texas and New Mexico, specific oil and natural gas regulations apply to oil and gas operations, including the drilling, completion and operations of wells, and the disposal of waste oil and salt water. There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency. As an example, the RRC adopted rules in 2014 requiring companies seeking permits for disposal wells to provide seismic activity data in permit applications. The rules also allow the RRC to modify, suspend, or terminate permits if a disposal well is determined to be causing seismic activity. Determinations by the RRC under these rules may adversely affect our operations. In New Mexico, the Produced Water Act, effective July 1, 2019, governs the discharge, handling, transport, storage, and recycling or treatment of produced water.

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Additionally, New Mexico has adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process. In January 2021, State Senator Antoinette Sedillo Lopez of New Mexico, introduced a bill which include: orderingwould prohibit certain uses of fresh water in fracking operations, require the disclosure of the chemical composition of produced water from spills, and increase penalties for produced water spills by the oil and gas industry. State Senator Sedillo introduced another bill for the 2021 legislative session seeking to prevent the New Mexico Energy, Minerals and Natural Resources Department from issuing new fracking permits until 2025. Similar legislation was unsuccessful in the 2019 and 2020 legislative sessions. However, if enacted, this legislation would have a clean-upmaterial adverse effect on our business and prospects.

Local governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. In Texas, however, local governments are expressly preempted from regulating oil and gas operations with limited exceptions, under Texas Natural Resources Code Section 81.0523. If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the local, state, or federal level, our fracturing activities could become subject to additional permit and financial assurance requirements, more stringent construction requirements, increased reporting or plugging and abandoning requirements or operational restrictions and associated permitting delays and potential increases in costs. These delays or additional costs could adversely affect the determination of whether a well is commercially viable and could cause us to incur substantial compliance costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities.

Climate Change

Continuing political and social attention to the issue of global climate change has resulted in both existing and pending international agreements and national, regional or local legislation and regulatory measures to limit or reduce emissions of so-called greenhouse gases (“GHGs”), such as cap and trade regimes, carbon taxes, restrictive permitting, increased fuel efficiency standards and incentives or mandates for renewable energy. In December 2009, the EPA published an endangerment finding concluding that emissions of CO₂, methane and certain other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on its findings, the EPA has adopted and implemented regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit requirements for GHG emissions from certain large stationary sources that already are major sources of criteria pollutants under the CAA. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically are GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities that exceed GHG emission thresholds. In addition, the EPA has adopted rules requiring the reporting of GHG emissions from oil and natural gas production and processing facilities on an annual basis, as well as reporting GHG emissions from gathering and boosting systems, oil well completions and workovers using hydraulic fracturing.

In June 2016, the EPA finalized rules to reduce methane emissions from new, modified or reconstructed sources in the oil and natural gas sector, including implementation of a leak detection and repair (“LDAR”) program to minimize methane emissions, under the CAA’s New Source Performance Standards in 40 C.F.R. Part 60, Subpart OOOOa (“GHG NSPS”). On April 18, 2017, the EPA announced its intention to reconsider certain aspects of those regulations, and in June 2017, the EPA proposed a two-year stay of certain requirements of the GHG NSPS regulations. In October 2018 the EPA proposed revisions to the GHG NSPS, such as changes to the frequency for monitoring fugitive emissions at well sites and changes to requirements that a professional engineer certify when meeting certain GHG NSPS requirements is technically infeasible. EPA proposed further revisions to the GHG NSPS on September 24, 2019, including rescinding the methane requirements in the GHG NSPS that apply to sources in the production and processing segments of the industry. In September 2020, the EPA finalized amendments to the GHG NSPS that rescind requirements for the transmission and storage segment of the oil and natural gas industry and rescind methane-specific limits that apply to the industry’s production and processing segments, among other things. The current administration has announced that it intends to review the September 2020 rules under the Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis, which review may result in the reinstatement of the now-rescinded standards or promulgation of more stringent standards. Our Company has taken measures to control methane leaks, but it is possible that these rules and future revisions thereto will require us to take further methane emission reduction measures, which may require us to expend material sums.

In addition, in November 2016, the U.S. Department of the Interior Bureau of Land Management (“BLM”) issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and natural gas operations on federal lands that are substantially similar to the GHG NSPS requirements. However, in December 2017, the BLM published a final rule to temporarily suspend or delay

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certain requirements contained in the November 2016 final rule until January 17, 2019, including those requirements relating to venting, flaring and leakage from oil and gas production activities. Further, in September 2018, the BLM published a final rule revising or rescinding certain provisions of the 2016 rule, which became effective on November 27, 2018. Both the 2016 and the 2018 rule were challenged in federal court. On July 21, 2020, a Wyoming federal court vacated almost all of the 2016 rule, including all provisions relating to the loss of gas through venting, flaring, and leaks, and on July 15, 2020, a California federal court vacated the 2018 rule. As a result of these decisions, the 1979 regulations concerning venting, flaring and lost production on federal land have been reinstated. The current administration is likely to impose new regulations on GHG emissions from oil and natural gas production operations on federal land, given the long-term trend towards increasing regulation in this area. Moreover, several states have already adopted rules requiring operators of both new and existing sources to develop and implement an LDAR program and to install devices on certain equipment to capture methane emissions. Compliance with these rules could require us to purchase pollution control and leak detection equipment, and to hire additional personnel to assist with inspection and reporting requirements.

Additionally, a number of state and regional efforts are aimed at tracking and/or reducing GHG emissions by means of cap-and-trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. On an international level, the United States is one of almost 200 nations that agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measure each country will use to achieve its GHG emissions targets, (the “Paris Agreement”). However, the Paris Agreement does not impose any binding obligations on the United States. In June 2017, President Trump announced that the United States would withdraw from the Paris Agreement, which became effective November 4, 2020. President Biden announced on January 20, 2021 that the United States will rejoin the Paris Agreement. In November 2021, the United States participated in the United Nations Climate Change Conference in Glasgow, Scotland, United Kingdom (“COP26”). COP26 resulted in a pact among approximately 200 countries, including the United States, called the Glasgow Climate Pact. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. In conjunction with COP26, the United States committed to an economy-wide target of reducing net greenhouse gas emissions by 50-52 percent below 2005 levels by 2030. Also in November 2021, President Biden signed a $1 trillion dollar infrastructure bill into law. The new infrastructure law includes several climate-focused investments, including upgrades to power grids to accommodate increased use of renewable energy and expansion of electric vehicle infrastructure. Further, several states, including New Mexico, and local governments remain committed to the principles of the Paris Agreement in their effectuation of policy and regulations. Although it is not possible at this time to predict what additional domestic legislation may be adopted in light of the Paris Agreement or the Glasgow Climate Pact, or how legislation or new regulations that may be adopted based on the Paris Agreement or the Glasgow Climate Pact to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations and could decrease demand for oil and natural gas.

The adoption and implementation of any spillslaws or wasteregulations imposing reporting obligations on, or limiting emissions of GHG from, our equipment and operations could require additional expenditures to reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas we produce, and thus possibly have a material adverse effect on our revenues, as well as having the potential effect of lowering the value of our reserves. Recently, stakeholders concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and restorationother sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Finally, to the extent increasing concentrations of GHGs 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, such events could have a material adverse effect on the Company and potentially subject the Company to further regulation. The trend of more expansive and stringent environmental legislation and regulations, including greenhouse gas regulation, could continue, resulting in increased costs of conducting business and consequently affecting our profitability. We also are aware that the SEC intends to propose new and additional rules regarding company disclosure of climate change risk. We will monitor and comply with any such promulgated rules.

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Threatened and endangered species, migratory birds and natural resources

Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act (“ESA”), the Migratory Bird Treaty Act (“MBTA”) and the Clean Water Act. The U.S. Fish and Wildlife Service (“FWS”) may designate critical habitat areas that it believes are necessary for survival of threatened or endangered species. As a result of a 2011 settlement agreement, the FWS was required to determine whether to identify more than 250 species as endangered or threatened under the ESA by no later than completion of the soil or wateragency’s 2017 fiscal year. The FWS missed the deadline but reportedly continues to conditions existing priorreview new species for protected status under the ESA pursuant to the environmental violation; fines;settlement agreement. A critical habitat designation could result in further material restrictions on federal land use or enjoining furtheron private land use and could delay or prohibit land access or development. Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties may act to prevent or restrict oil and natural gas exploration activities or seek damages for any injury, whether resulting from drilling completion or productionconstruction or releases of oil, wastes, hazardous substances or other regulated materials, and in some cases, criminal penalties may result. Similar protections are offered to migratory birds under the MBTA. Recently, there have been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species or that may attract migratory birds, we believe that we are in substantial compliance with the ESA and the MBTA, and we are not aware of any proposed ESA listings that will materially affect our operations. Nevertheless, we are monitoring proposed listings by the FWS, such as the January 2022 proposal to list the Sacramento Mountains checkerspot butterfly in New Mexico, to ensure continued compliance. The federal government in the past has issued indictments under the MBTA to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. In certain egregious situationsJanuary 2020, a new DOI rule went into effect clarifying that only the agencies may also pursue criminal remedies againstintentional taking of protected migratory birds is subject to prosecution under the MTBA. In December 2021, however, that rule was revoked, and a new rule took effect reinstating the prohibition on incidental takes under the MTBA. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our principal officers.development activities that could have an adverse impact on our ability to develop and produce our oil and natural gas reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

Operational Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow outs,well blow-outs, pipe failures, industrial accidents, and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills,releases, chemical releases, natural gas leaks and the discharge of toxic gases. If any

Any of these should occur,risks could adversely affect our ability to conduct operations or result in substantial losses to us, for example, as a result of damage to our property or equipment or injury to our personnel. These operational risks could also result in the spill or release of hazardous materials such as drilling fluids or other chemicals, which may result in pollution, natural resource damages, or other environmental damage and necessitate investigation and remediation costs. As a result, we could incur legal defense costs andbe subject to liability under environmental law or common law theories. In addition, these operational risks could be required to pay amounts due to injury, lossresult in the suspension or delay of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.

our operations, which could have significant adverse consequences on our business.

In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. Under certain circumstances, we may be liable for environmental damage caused by previous owners or operators of properties that we own, lease or operate. As a result, we may incur substantial liabilities to third parties or governmental entities for environmental matters for which we do not have insurance coverage, which could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses.

Human Capital Management

Current EmployeesKey to our mission is our employees upon which the foundation of our company is built.  We seek to employ highly trained people who exemplify our core values of honesty and integrity, and are diligent, hard-working individuals who deliver results, and who are good neighbors and contribute to the communities in which they live.

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As of December 31, 2017,2021, we had thirty seven53 full-time employees.  Our employees are notextremely valuable to the success of the Company, and we encourage their collaboration and respect their diverse points of view and opinions.  In addition to our full-time employees, the Company also employs a diverse group of independent contractors who assist our full-time staff in a range of areas including geology, engineering, land, accounting, and field operations, as needed.  None are represented by labor unions or covered by any labor union. collective bargaining agreements.

Diversity and inclusion: The unique backgrounds and experiences of our employees help to develop a wide range of perspectives that lead to better solutions. Our staff’s diversity is reflected in our full-time employees where 26% are women and approximately one third represent minorities. The majority of our employees are citizens of the United States, with a few retaining dual citizenships in other countries. The employees who are not US citizens, are legally registered to live and work here and the Company is committed to helping those employees retain their ability to remain in the US and continue their employment. The Company is also committed to continuously providing an inclusive work environment where all of our employees can be respected, valued, and successful in achieving their goals, all while contributing to the Company’s success.

We considerrecognize that attracting, retaining and developing our relationsemployees is critical for our future success. Our Executive Vice President of Land, Legal, Human Resources and Marketing, together with our Chief Executive Officer are responsible for developing and executing our human capital strategy, with oversight by the Board of Directors and the Board committees. Some of our key human capital areas of focus include:

Building a Safe Workforce Starts with Our Culture: Ring is committed to building a safety culture that empowers employees and contractors to act as needed to work safely and to stop the job, without retribution, if conditions are deemed unsafe. We strive to be incident-free every day across our operations. We are focused on building and maintaining a safe workplace for all employees and contractors. The oil and gas industry has a number of inherent risks and our workers are often outdoors, in all seasons and all types of weather. In addition, our field personnel spend significant time driving on a daily basis, putting them at risk for driving incidents. A strong safety culture is essential to the Company’s success, and we emphasize the important role that all personnel play in creating and maintaining a safe work environment.

Health and Safety Training and Education: We offer a wide range of training opportunities for employees and contractors to help them develop their skills and understanding of our health and safety policy and programs. In addition to teaching specific skills, these training opportunities encourage personal responsibility for safe operating conditions and help to build a culture of individual accountability for conducting job tasks in a safe and responsible manner.

Ring Energy supports both company identified and employee identified educational opportunities for employees to be satisfactoryadvance in their technical and have never experienced amanagerial skills and to help provide opportunities to advance throughout our company. Ring’s support comes in the form of full or partial funding of educational programs and opportunities, including time off work stoppage to attend and/or strike.prepare for such programs.

COVID-19 Response: Our COVID-19 management plan was built around the need to support all employees in managing their personal and professional challenges. Frequent and transparent communications are the focus at every level of the organization from those on the front lines to those in our corporate offices. During the early stages of the pandemic, Ring’s management team directed the Company’s overall COVID-19 pandemic response by implementing all relevant county, state and local government guidelines, directives and regulations, and developed and adopted work-from-home provisions and procedures, implemented safe working protocols for production teams, assessed and implemented appropriate return-to-office protocols, and provided timely and transparent communications to employees and key stakeholders.

We also retain certain engineers, geologists, landmen, pumpersIn response to the COVID-19 pandemic, Ring began providing the following benefits to its employees:

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Seasonal Nature of Business

Generally, the demand for oil and natural gas fluctuates depending on the time of year. Seasonal anomalies such as mild winters or hotand summers may sometimes lessen this fluctuation. Further, pipelines, utilities, local distribution companies, and industrial end users utilize oil and natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand.

FinancialAvailable Information

FinancialOur website can be found at www.ringenergy.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 will be available through our website free of charge as soon as reasonably practical after we electronically file such material with, or furnish it to, the SEC. The information on, or that can be accessed through, our website is not incorporated by reference into this Annual Report and should not be considered part of this Annual Report. The SEC also maintains a website (http://www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the geographic area in which we operate is incorporated herein by reference to Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8, “Financial Statements and Supplementary Data.” We conduct our oil and natural gas activities entirely in the United States.SEC.

The followingOur business is subject to various risks and uncertainties in the ordinary course of business. The following summarizes significant risks and uncertainties that may adversely affect our performance,business, financial condition, or results of operations. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. Readers should carefully consider the risk factors included below as well as those matters referenced in this report under “Forward-Looking Statements” and other information included and incorporated by reference into this report.

Risks Relating to Our Business, Operations and Strategy

Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve additional risks and uncertainties in their application as compared to conventional drilling.

Our operations utilize some of the latest horizontal drilling and completion techniques as developed by us, other oil and natural gas exploration and production companies and our service providers. The additional risks that we face while drilling horizontally include, but are not limited to, the following:

Risks that we face while completing our wells include, but are not limited to, the following:

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If our assessments of purchased properties are materially inaccurate, it could have a significant impact on future operations and earnings.

The successful acquisition of producing properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including the following:

Our assessment will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. We plan to undertake further development of our properties through the use of cash flow from existing production. Therefore, a material deviation in our assessments of these factors could result in less cash flow being available for such purposes than we presently anticipate, which could either delay future development operations (and delay the anticipated conversion of reserves into cash) or cause us to seek alternative sources to finance development activities.

Prospects that we decide to drill may not yield oil or natural gas 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. 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. This risk may be enhanced in our situation, due to the fact that a significant percentage (44)% of our proved reserves is currently proved undeveloped reserves. The use of 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 obtained by analyzing other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

A substantial percentage of our proved properties are undeveloped; therefore, the risk associated with our success is greater than would be the case if the majority of our properties were categorized as proved developed.

Because a substantial percentage of our proved properties are proved undeveloped (44)%, we will require significant additional capital to develop such properties before they may become productive. Further, because of the inherent uncertainties associated with drilling for oil and gas, some of these properties may never be developed to the extent that they result in positive cash flow. Even if we are successful in our development efforts, it could take several years for a significant portion of our undeveloped properties to be converted to positive cash flow.

While our current business plan is to fund the development costs with cash flow from our other producing properties, if such cash flow is not sufficient, we may be forced to seek alternative sources for cash, through the issuance of additional equity or debt securities, increased borrowings or other means.

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Hedging transactions may limit our potential gains.

To reduce our exposure to commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we have entered into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production in order to economically hedge a portion of our forecasted oil and natural gas production. Additionally, our credit facility requires us to hedge a portion of our production. In addition, these derivative contracts may limit the benefit we would otherwise receive from increases in the prices for oil and natural gas.  As of December 31, 2021, the Company has in place derivative contracts covering 3,129 barrels of oil per day for the calendar year 2022.  All of the 3,129 barrels of oil in 2022 are in the form of swaps of WTI Crude Oil prices.  The oil swap prices for 2022 range from $44.22 to $50.05, with a weighted average swap price of $46.60.

Hedging transactions may expose us to risk of financial loss.

While intended to reduce the effects of volatile crude oil and natural gas prices, such derivative contracts expose us to risk of financial loss in some circumstances, including when there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received, or when the counterparty to the derivative contract is financially constrained and defaults on its contractual obligations. It is also possible that sales volumes fall below the hedged volumes leaving a portion of our position uncovered.

The transition from LIBOR to alternative reference “benchmark” interest rates is uncertain and could adversely affect the value of or the interest rates on our investments and obligations indexed to LIBOR, as well as the revenue and expenses associated with those assets and obligations.

LIBOR is an interest rate benchmark that has been widely used in financial contracts around the world for decades. In July 2017, the United Kingdom’s Financial Conduct Authority (“FCA”), which regulates the London Interbank Offered Rate (“LIBOR”) announced that it intended to phase out LIBOR by the end of 2021. Following discussions with the FCA and other official sector bodies, the Intercontinental Exchange Benchmark Administration announced in March 2021 the publication of certain USD LIBOR settings will continue through June 30, 2023. The Alternative Reference Rates Committee of the Federal Reserve Board (ARRC), a group of market participants convened to help ensure a successful transition away from LIBOR, has recommended the Secured Overnight Financing Rate (SOFR) as its preferred alternative reference rate and has proposed a transition plan and timeline designed to encourage the adoption of SOFR from LIBOR.

We are in the process of analyzing and identifying our population of securities, financial instruments and contracts that utilize LIBOR (collectively “LIBOR Instruments”) to determine if we have any material exposure to the transition from LIBOR. To the extent we hold LIBOR Instruments, the terms of these instruments may have fallback provisions that provide for an alternative reference rate when LIBOR ceases to exist. For securities without adequate fallback provisions already in place, legislation governing securities under New York law has been enacted to provide a safe harbor for transition to the recommended alternative reference rate. In addition, federal legislation has been introduced to provide the same protection for securities not governed by New York law.

Notwithstanding, in preparation for the phase out of LIBOR, we may need to renegotiate our LIBOR Instruments that utilize

LIBOR. However, these efforts may not be successful in mitigating the legal and financial risk from changing the reference rate in our LIBOR Instruments. Furthermore, the discontinuation of LIBOR may adversely impact our ability to manage and hedge exposures to fluctuations in interest rates using derivative instruments.

As a result, the transition of our LIBOR Instruments to alternative reference rates may result in adverse changes to the net investment income, fair market value and return on those investments. We intend to continue to evaluate and monitor the risks associated with the LIBOR transition which include identifying and monitoring our exposure to LIBOR, monitoring the market adoption of alternative reference rates and ensuring operational processes are updated to accommodate alternative rates. Due to uncertainty surrounding alternative rates, we are unable to predict the overall impact of this change at this time.

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We may be adversely affected by natural disasters, pandemics (including the recent coronavirus outbreak) and other catastrophic events, and by man-made problems such as terrorism, that could disrupt our business operations.

Natural disasters, adverse weather conditions, floods, pandemics (including the recent coronavirus outbreak), acts of terrorism and other catastrophic or geo-political events may cause damage or disruption to our operations and the trading priceglobal economy, or could result in market disruption, any of which could have an adverse effect on our common stock.business, operating results, and financial condition.

The ongoing coronavirus outbreak has impacted various businesses throughout the world, including an impact on the global demand for oil and natural gas, travel restrictions and the extended shutdown of certain businesses in impacted geographic regions. If the coronavirus outbreak situation should worsen, it could have a material adverse impact on our business operations, operating results and financial condition.

The ongoing COVID-19 pandemic, and the relations of and agreements between OPEC+ producers, could disrupt our operations and adversely impact our business and financial results.

The COVID-19 pandemic has led to worldwide shutdowns, reductions in commercial and interpersonal activity, and changes in consumer behavior. In attempting to control the spread of COVID-19, governments around the world-imposed regulations such as shelter-in-place orders, quarantines, executive orders and similar restrictions. As a result, the global economy has been marked by significant slowdown and uncertainty, which has in the past led to a precipitous decline in oil prices in response to decreased demand. We currently are unable to predict the duration or severity of the spread of COVID-19 or the adverse effects thereof.

The loss of key members of management or failure to attract and retain other highly qualified personnel could, in the future, affect the Company’s business results.

The Company’s success depends on its ability to attract, retain and motivate a highly-skilled and diverse management team and workforce. During the latter half of 2020, the Company experienced significant leadership changes, including appointing a new Chief Executive Officer, Executive Vice President of Operations, a new Executive Vice President of Engineering and Corporate Strategy, a new Vice President of Compliance, a new Executive Vice President of Land, Legal, Human Resources and Marketing along with the appointment of new directors to the Board of Directors. In the first quarter of 2021, the Company appointed a new Chief Financial Officer. Executive leadership transitions can be difficult to manage and could cause disruption to our business. Failure to ensure that the Company has the depth and breadth of management and personnel with the necessary skill set and experience could impede its ability to achieve growth objectives and execute its operational strategy. As the Company continues to expand, it will need to promote or hire additional staff, and, as a result of increased compensation and benefit mandates, it may be difficult to attract or retain such individuals without incurring significant additional costs.

Risks Relating to the Oil and Natural Gas Industry and Our Business

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets 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, but are not limited to, the following:

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Lower oil and natural gas prices may not only decrease our revenues on a per unitBOE basis but also may reduce the amount of oil and natural gas that we can produce economically. Lower prices will also negatively impact the value of our proved reserves. A substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

A substantial percentage of our proven properties are undeveloped; therefore, the risk associated with our success is greater than would be the case if the majority of our properties were categorized as proved developed producing.

Because a substantial percentage of our proven properties are proved undeveloped (approximately 45%) or proved developed non-producing (approximately 10%), we will require significant additional capital to develop such properties before they may become productive. Further, because of the inherent uncertainties associated with drilling for oil and gas, some of these properties may never be developed to the extent that they result in positive cash flow. Even if we are successful in our development efforts, it could take several years for a significant portion of our undeveloped properties to be converted to positive cash flow.

While our current business plan is to fund the development costs with cash flow from our other producing properties, if such cash flow is not sufficient we may be forced to seek alternative sources for cash, through the issuance of additional equity or debt securities, increased borrowings or other means.

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 success will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. For example, in January 2021, President Biden signed an Executive Order directing the Department of Interior (the “DOI”) to temporarily pause new oil and gas leases on federal lands and waters pending completion of a comprehensive review of the federal government’s existing oil and gas leasing and permitting program. In June 2021, a federal district court enjoined the DOI from implementing the pause and leasing resumed, although litigation over the leasing pause remains ongoing. In February 2022, another judge ruled that the Biden Administration’s efforts to raise the cost of climate change in its environmental assessments, would increase energy costs and damage state revenues from energy production. This ruling has cause federal agencies to delay issuing new oil and gas leases and permits on federal lands and waters. While we do not have a significant federal lands acreage position (240 net acres as of December 31, 2021), these actions could have a material adverse effect on our industry and the Company.

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. Please read “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. . .” (below) for a discussion of the uncertainty involved in these processes. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular well or project uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following:

Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve additional risks and uncertainties in their application if compared to conventional drilling.

Our operations utilize some of the latest horizontal drilling and completion techniques as developed by us, other oil and natural gas explorationprices; title problems; and production companieslimitations in the market for oil and our service providers. The additional risks that we face while drilling horizontally include, but are not limited to, the following:natural gas.

Risks that we face while completing our wells include, but are not limited to, the following:

If our assessments of recently purchased properties are materially inaccurate, it could have a significant impact on future operations and earnings.

We have aggressively expanded our base of producing properties. The successful acquisition of producing properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including the following:

Our assessment will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. As noted previously, we plan to undertake further development of our properties through the use of cash flow from existing production. Therefore, a material deviation in our assessments of these factors could result in less cash flow being available for such purposes than we presently anticipate, which could either delay future development operations (and delay the anticipated conversion of reserves into cash), or cause us to seek alternative sources to finance development activities.

Decreases in oil and natural gas prices may require us to take write-downs of the carrying values of our oil and natural gas properties potentially requiring earlier than anticipated debt repayment andwhich could negatively impactingimpact the trading value of our securities.

common stock.

Accounting rules require that we review periodically the carrying value of our oil and natural gas 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 downwrite-down the carrying value of our oil and natural gas properties. Because our properties serve as collateral for advances under our existing credit facility, a write-down in the carrying values of our properties could require us to repay any outstanding debt earlier than we would otherwise be required. A write-down could alsowould likely constitute a non-cash charge to earnings. It is likely theThe cumulative effect of a write-down could also negatively impact the trading price of our securities.common stock.