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Table of Contents

United States

Securities and Exchange Commission

Washington, D.C. 20549

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, 2020

Or

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

For the transition period from ___________to ___________

Commission file number 001-36057

Ring Energy, Inc.

(Exact name of registrant as specified in its charter)

Nevada

90-0406406

(State or other jurisdiction of
incorporation or organization)

(I.R.S. Employer
Identification Number)

1725 Hughes Landing Blvd. Suite 900
The Woodlands, TX

77380

(Address of principal executive offices)

(Zip Code)

(281) 397-3699

 

(Registrant’s telephone number, including area code)

 

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

Title of Each Class

Trading Symbol

Name of Exchange

Common Stock, par value $0.001

REI

NYSE American

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 No

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

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. Yes No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes No

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

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 No

As of June 30, 2020, 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 American of $1.16 per share, was $74,553,881.

As of March 16, 2021, the issuer had outstanding 99,181,587 shares of common stock ($0.001 par value).

DOCUMENTS INCORPORATED BY REFERENCE

Table of Contents

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.

Table of Contents

TABLE OF CONTENTS

PART I

Item 1:

Business

5

Item 1A:

Risk Factors

16

Item 1B:

Unresolved Staff Comments

26

Item 2:

Properties

26

Item 3:

Legal Proceedings

36

Item 4:

Mine Safety Disclosures

36

PART II

Item 5:

Market for Registrant’s Common Equity, Related Stockholder Matters and Issued Purchases of Equity Securities

37

Item 6:

Selected Financial Data

38

Item 7:

Management’s Discussion and Analysis of Financial Condition and Results of Operations

39

Item 7A:

Quantitative and Qualitative Disclosures About Market Risk

48

Item 8:

Financial Statements and Supplementary Data

49

Item 9:

Changes in and Disagreement’s With Accountants on Accounting and Financial Disclosure

49

Item 9A:

Controls and Procedures

49

Item 9B:

Other Information

50

PART III

Item 10:

Directors, Executive Officers and Corporate Governance

50

Item 11:

Executive Compensation

50

Item 12:

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

51

Item 13:

Certain Relationships and Related Transactions, and Director Independence

51

Item 14:

Principal Accounting Fees and Services

51

PART IV

Item 15:

Exhibits, Financial Statement Schedules

51

3

Table of Contents

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 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 “could,” “would,” “should,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” or 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. 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 are 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 actual results to differ materially from those contemplated. Such factors include: declines or volatility in the prices we receive for our oil 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; 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” in this Annual Report, as well as in our consolidated financial statements, related notes, and the other financial information appearing elsewhere in this Annual Report 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, which speak only as of the date that such statements are made. We undertake no obligation to publicly update or 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,” “Ring Energy,” “the Company,” “we,” “us,” “our” or “ours” refer to Ring Energy, Inc.

4

Table of Contents

PART I

Item 1:  Business

General

Ring Energy, Inc., a Nevada corporation (“Ring,” “Ring Energy,” the “Company,” “we,” “us,” “our,” or similar terms), is a growth oriented independent exploration and production company based in The Woodlands, Texas and is engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in Texas and New Mexico. Our primary drilling operations target the oil and liquids rich producing formations in the Northwest Shelf, the Central Basin Platform, and the Delaware Basin all of which are part of the Permian Basin in Texas and New Mexico.

As of December 31, 2020, our leasehold acreage positions totaled 104,455 gross (76,745 net) acres and we held interests in 610 gross (441 net) producing wells.  Proved reserves as of December 31, 2020 were approximately 76.5 million BOE (barrel of oil equivalent), of which we are the operator of approximately 97.7%. All of our properties are located in the Permian Basin in Texas and New Mexico.  The Company’s proved reserves are oil-weighted with approximately 87% consisting of oil and 13% consisting of natural gas. Of those reserves, approximately 57.5% are classified as proved developed or “PD” and 42.5% 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

Ring’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 new strategic vision are to:

ensure health, safety, and environmental excellence and a strong commitment to Ring’s employees and the communities in which we work and operate;
continue our focus on generating free cash flow to improve and build a sustainable financial foundation;
pursue rigorous capital discipline focused on Ring’s highest returning opportunities;
improve margins and drive value by targeting additional operating cost reductions and capital efficiencies; and
strengthen the balance sheet by steadily paying down debt, divesting of non-core assets and becoming a peer leader in Debt/EBITDA metrics.

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

Attract and retain the best 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, 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.

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.  Ring incurred long-term indebtedness in

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connection with the acquisition of core assets from Wishbone Energy Partners, LLC and its related entities in 2019. 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, limited to maintain or minimally grow our production and reserve levels, and have returns sufficient to provide excess cash from operations to pay down debt.  Remaining focused and disciplined in this regard will lead to meaningful returns for our shareholders once our financial position improves and additional financial flexibility to manage swings in the business cycle.   Our commodity hedges are designed to ensure the necessary cash flow to adhere to these plans.

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 and Departure of Certain Officers and Directors

On September 30, 2020, the Company announced the appointment of Mr. Paul D. McKinney as Chief Executive Officer (“CEO”) and Chairman of the Board of Directors (the “Board”), effective October 1, 2020. In connection with the appointment of Mr. McKinney, Lloyd T. Rochford, Chairman of the Board, and Kelly Hoffman, CEO, resigned from their respective positions, effective as of October 1, 2020. Mr. Rochford and Mr. Hoffman also resigned from the Board on October 1, 2020. Mr. Rochford remains with the Company in a consulting capacity as an advisor to the CEO and Chairman of the Board.

On October 22, 2020, the Company appointed Mr. Thomas L. Mitchell to the Company’s Board and determined that Mr. Mitchell is an “independent director” as such term is defined under the NYSE American Company Guide.

On October 29, 2020, the Company appointed Mr. John A. Crum and Mr. Richard E. Harris to the Company’s Board and determined that Mr. Crum and Mr. Harris are “independent directors” as such term is defined under the NYSE American Company Guide.  In connection with the appointment of Mr. Crum and Mr. Harris, Mr. Stanley McCabe and Mr. David Fowler resigned from the Board on and effective October 29, 2020.

On November 30, 2020, the Company announced the promotion of Mr. Stephen D. Brooks to Executive Vice President of Land, Legal, Human Resources and Marketing, assuming roles previously held by Mr. Matt Garner who served as General counsel and Vice President of land for the company.

On December 16, 2020, Company issued a press release announcing several executive management changes, effective December 31, 2020. The Company announced the promotion of Mr. Alexander Dyes to Executive Vice President of Engineering and Corporate Strategy, the promotion of Mr. Marinos Baghdati to Executive Vice President of Operations, and the promotion of Ms. Hollie Lamb to Vice President of Compliance and General Manager of the Company’s Midland, Texas office. In connection with these changes, Mr. David A. Fowler resigned from his position as President but remains with the Company in a consulting capacity and manages Investor Relations and Mr. Danny Wilson resigned from his position as Executive Vice President and Chief Operating Officer.

Primary Business Operations

The Company seeks to exploit its acreage position through the drilling of highly economic vertical and horizontal wells using the most recent drilling and completion techniques. Our focus is drilling and developing our oil and gas properties through use of cash flow generated by our operations and reducing our long-term debt through the sale of non-core assets or through our excess cash flow

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while still working towards maintaining or providing annual production growth. We continue to evaluate potential transactions to acquire attractive acreage positions within our core areas of interest.

Ring’s original plan for 2020 included drilling 18 horizontal wells on the Northwest Shelf and performing workovers and extensive infrastructure projects on its Northwest Shelf, Central Basin Platform and Delaware Basin assets. Due to the drop in the price of oil, Ring re-evaluated its capital expenditure budget for 2020 and made changes that the Company believed were in the best interest of its stockholders, including ceasing any further drilling until oil prices stabilized. Of the 18 new wells originally planned, the Company drilled four new horizontal San Andres wells on its Northwest Shelf asset in the first quarter of 2020 and two more new horizontal San Andres wells in the same asset area in December 2020. All four new wells drilled in the first quarter were completed, tested and had Initial Potentials (“IP”) filed. In addition to the four new wells drilled in the first quarter which had IPs filed, the Company completed testing and filed IPs on two additional horizontal wells drilled in 2019. The Company performed nine conversions from electrical submersible pumps to rod pumps in the first quarter 2020, four conversions in the second quarter 2020, eight conversions in the third quarter 2020 and eight conversions in the fourth quarter 2020.  Starting the last week of April, the Company shut-in or curtailed essentially all production, other than that associated with Ring’s Delaware Basin property. The curtailments continued until early June, when, with commodity prices improving and price differentials decreasing, the Company began to bring wells back on-line, returning to near April levels by the end of the second quarter. In the third quarter 2020, we restored production to 9,549 net barrels of oil equivalent per day (“BOEPD”). In the fourth quarter 2020, the Company performed capital workovers and re-activations that stabilized production at 9,307 BOEPD. In view of the uncertainty of the extent of the contraction in oil demand and the volatility of oil futures contracts due to the COVID-19 pandemic, combined with the generally weaker commodity price environment, the Company turned its strategic focus in 2020 to reducing costs, generating free cash flow, and paying down debt.

Ring believes that there is significant value to be created by drilling the identified undeveloped opportunities on its Texas and New Mexico properties and intends to focus its drilling efforts in 2021 primarily in the Northwest Shelf.

Northwest Shelf – Yoakum, Runnels and Coke Counties, Texas and Lea County, New Mexico – As of December 31, 2020, Ring owned interests in a total of 11,723 gross (8,085 net) developed acres and 35,249 gross (24,830 net) undeveloped acres. In these counties, the Company has 72 identified proved horizontal drilling locations and 11 proved vertical drilling locations based on the reserve reports as of December 31, 2020 and an additional 70 potential vertical drilling locations based on 20-acre downspacing and 135 potential horizontal drilling locations based on 4-8 wells per section or 80-160 acres per well.
Central Basin Platform – Andrews and Gaines Counties, Texas – As of December 31, 2020, Ring owned interests in a total of 23,668 gross (18,712 net) developed acres and 15,046 gross (6,650 net) undeveloped acres. In these counties, the Company has 2 identified proved vertical drilling locations and 32 identified proved horizontal locations based on the reserve reports as of December 31, 2020, and an additional 105 potential vertical drilling locations based on 10-acre downspacing and 179 potential horizontal drilling locations based on 6 wells per section or 106 acres per well.
Delaware Basin – Culberson and Reeves Counties, Texas – As of December 31, 2020, Ring owned interests in a total of 18,521 gross (18,256 net) developed acres and 248 gross (212 net) undeveloped acres. In these counties, the Company has 26 identified proved vertical drilling locations and 4 identified proved horizontal locations based on the reserve reports as of December 31, 2020 and an additional 17 potential vertical drilling locations based on 10-acre spacing and 59 potential horizontal drilling locations based on 4 wells per section or 160 acres per well.

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.

Ring Energy’s Strengths

high quality asset base in one of North America’s leading oil and gas producing regions characterized by low declines and attractive margins;
de-risked Permian Basin acreage position with multi-year drilling inventory of horizontal and vertical development potential;
concentrated acreage position with high degree of operational control;
experienced and proven management team focused on the Permian Basin;

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history of attracting technical personnel with experience in our core area of operations;
commitment to cost efficient operations, health, safety, protecting the environment, our employees, and the communities in which we work and operate.

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.

Marketing and 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. We believe there is little risk in our ability to sell our production at prevailing prices. We view potential declines in oil and gas prices to a level which could render our current production 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, which potentially gives such gathering companies certain short-term relative monopolistic powers to set gathering and transportation costs. 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-party gathering systems with respect to our oil production. Some of our oil production is sold through a third-party pipeline which has no regional competition and all other oil production is transported by the oil purchaser by trucks with competitive trucking costs in the area.

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.

For the fiscal year ended December 31, 2020, sales to three customers, Phillips 66 (“Phillips”), Occidental Energy Marketing (“Oxy”) and NGL Crude Partners (“NGL Crude”) represented 68%, 10% and 8%, respectively, of our oil and natural gas revenues. As of December 31, 2020, Phillips represented 80% of our accounts receivable, Oxy represented 0% of our accounts receivable and NGL Crude represented 5% 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 natural gas.

Delivery Commitments

As of December 31, 2020, 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, can affect our profitability.

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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. The 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, on January 20, 2021, the Biden Administration placed a 60-day moratorium on new oil and gas leasing and drilling permits on federal land, and on January 27, 2021, the Department of Interior acting pursuant to a Presidential Executive Order suspended the federal oil and gas leasing program indefinitely. 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 do not have a significant federal lands acreage position at 240 net acres, these actions could have a material adverse effect on the Company and our industry.

Currently, all of our properties and operations are in Texas and New Mexico, which have regulations governing conservation matters, such 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, both 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 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.

Regulation of Transportation of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated 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, 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, the Natural Gas Policy Act of 1978 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

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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. At 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; 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. 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 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 by state and local governments in the jurisdictions where we operate. As described below, there are various regulations issued by the EPA and other governmental agencies pursuant to these federal statutes that govern 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 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:

Hazardous Substances and Wastes

CERCLA, also known as the Superfund law, and analogous state laws impose liability on certain classes of persons, known as “potentially responsible parties,” for the 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 and state regulatory

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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 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 remediate environmental impacts on properties we currently own and lease or formerly owned or leased (including hazardous substances or wastes disposed of 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 laws 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.

Air Emissions

Our operations are subject to the federal 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. We note that in June 2016, the EPA finalized rules regarding criteria for aggregating multiple small sites into a single source for air permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities to be aggregated for permitting purposes, resulting in treatment as a major source, and thereby triggering more stringent air permitting requirements. Violation of CAA requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. Furthermore, future capital expenditures may be required for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

The trend under CAA regulations has been to increase the stringency of air quality standards, which may require us to incur capital expenditures for air pollution control equipment or other costs. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standards for ozone to 70 parts per billion, which was a significant decrease from the prior standards. On December 31, 2020, EPA published in the Federal Register its decision to retain the 2015 ozone standards; however, the current administration has announced that it intends to review this rule under the January 20, 2021 Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis. Further reductions in the ozone National Ambient Air Quality Standards could affect our operations and result in the need to install new emissions controls, longer permitting timelines and significant increases in our capital or operating expenditures. Compliance with these and any future air pollution control and permitting requirements has the potential to delay the development of our oil and natural gas projects and increase our costs of development and production, which costs could be significant.

Oil Pollution Prevention

The Oil Pollution Act of 1990 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 Oil Pollution Act. 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, 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 crude 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 the pollution prevention regulations. To be in compliance, the facility’s SPCC plan must satisfy all of the applicable

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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 impose 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. 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 Safe Drinking Water Act, 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 Safe Drinking Water Act 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, 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.

Hydraulic Fracturing

Hydraulic fracturing is a practice in the oil and natural gas industry used to stimulate production of natural gas and/or oil 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

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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 Texas Railroad Commission (“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. In January 2021, State Senator Antoinette Sedillo Lopez of New Mexico, introduced a bill which would 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 material 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

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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 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.

In addition, 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. 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. It is not possible at this time to predict how or when the United States might impose further restrictions on GHG emissions as a result of the Paris Agreement. The adoption and implementation of any laws or regulations 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 other 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,

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including greenhouse gas regulation, could continue, resulting in increased costs of conducting business and consequently affecting our profitability.

Operational Hazards and Insurance

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

Any of these 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 be subject to liability under environmental law or common law theories. In addition, these operational risks could result in the suspension or delay of 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

Key to our mission is our employees upon which the foundation of our company is built. We seek to employ the best 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.

As of December 31, 2020, we had forty-one (41) full-time employees. Our employees are extremely 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 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 22% are women and nearly 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 recognize that attracting, retaining and developing our employees 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.

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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 advance in their technical and managerial 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 to attend and/or 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 were 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.

In response to the COVID-19 pandemic, Ring began providing the following benefits to its employees:

covering the cost of COVID-19 testing through expanded insurance coverage;
promoting telehealth benefits;
promoting mental health and well-being plans;
providing additional paid sick leave for quarantined employees.

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 hot 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.

Available Information

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 pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 will be available through our Internet 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 an Internet website (http://www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

Item 1A:  Risk Factors

The following risks and uncertainties may affect our performance, results of operations and the trading price of our common stock.

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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 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 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:

drilling wells that are significantly longer and/or deeper than wells drilled by others;
landing our wellbore in the desired drilling zone;
staying in the desired drilling zone while drilling horizontally through the formation;
running our casing the entire length of the wellbore; and
being able to run tools and other equipment consistently through the horizontal wellbore.

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

the ability to fracture or stimulate the planned number of stages in a horizontal or lateral wellbore;
the ability to run tools the entire length of the wellbore during completion operations; and
the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

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:

the amount of recoverable reserves;
future oil and natural gas prices;
estimates of operating costs;
estimates of future development costs;
estimates of the costs and timing of plugging and abandonment; and
potential environmental and other liabilities.

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 (43%) 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.

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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 producing.

Because a substantial percentage of our proved properties are proved undeveloped (approximately 43%), 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.

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 may enter 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, 2020, the Company has in place derivative contracts covering 9,000 and 1,750 barrels of oil per day for the calendar years 2021 and 2022, respectively, and covering 6,000 and 5,000 MMBTU of natural gas per day for the calendar years 2021 and 2022, respectively. For 2021, contracts covering 4,500 of the 9,000 barrels of oil are in the form of costless collars of WTI Crude Oil prices. “Costless collars” are the combination of two options, a put option (floor) and a call option (ceiling) with the options structured so that the premium paid for the put option will be offset by the premium received from selling the call option. These collars have floors ranging from $40.00 to $45.00, with an averaged floor of $42.22 and have ceilings ranging between $52.71 and $55.35 per barrel, with an average ceiling of $54.57. The remaining 4,500 barrels of oil in 2021 and all of the 1,750 barrels of oil in 2022 are in the form of swaps of WTI Crude Oil prices. The oil swap prices for 2021 range from $45.00 to $45.96, with an average of $45.42. The oil swap prices for 2022 range from $44.22 to $45.98, with an average of $44.84. All of the contracts for natural gas for both 2021 and 2022 are in the form of swaps of Henry Hub. The swap prices for 2021 and 2022 are $2.991 and $2.7255, respectively.

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 phaseout of the London Interbank Offered Rate (LIBOR), or the replacement of LIBOR with a different reference rate, may adversely affect interest rates.

On July 27, 2017, the Financial Conduct Authority (the authority that regulates LIBOR) announced that it would phaseout LIBOR by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021, or if the alternative rates or benchmarks will be adopted. Changes in the method of calculating LIBOR, or the replacement of LIBOR with an alternative rate or benchmark, may adversely affect interest rates and result in higher borrowing costs. This could materially and adversely affect the Company’s results of operations, cash flow and liquidity. We cannot predict the effect of the potential changes to LIBOR or the establishment and use of alternative rates or benchmarks. If changes are made to the method of calculating LIBOR or LIBOR ceases to exist, we may need to amend certain contracts and cannot predict what alternative rate or benchmark would be negotiated. This may result in an increase to our interest expense.

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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 global economy, or could result in market disruption, any of which could have an adverse effect on our business, operating results, and financial condition.

The ongoing coronavirus outbreak at the beginning of 2020 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 in turn has led to a precipitous decline in oil prices in response to decreased demand, further exacerbated by the OPEC+ price war during the first quarter 2020 and global storage shortages. The confluence of these events has resulted in a significantly weaker outlook for oil and natural gas producers, including reduced operating and capital budgets as well as diminished market confidence in overall industry viability. While OPEC+ producers have agreed to cut oil production to a limited extent, downward pressure on commodity prices has remained and could continue for the foreseeable future. We currently are unable to predict the duration or severity of the spread of COVID-19 or the adverse effects thereof, including a global economic recession resulting from the pandemic, or the continuance or effectiveness of the OPEC+ voluntary production adjustments (or the terms thereof or compliance therewith). If economic and industry conditions do not improve, these factors will adversely impact our financial condition and results of operations.

The current environment may make it even more difficult to comply with our covenants and other restrictions in our credit facility, and a lack of confidence in our industry on the part of the financial markets may result in one or more of the following, any of which could lead to reduced liquidity: a lack of access to capital; an event of default under our credit facility; the possible acceleration of our repayment of outstanding debt under our credit facility; the exercise of certain remedies by our lenders; or a limited or total inability to refinance our debt.

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. In the last six months, the Company has 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. 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 deliver 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.

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Risks Relating to the Oil and Natural Gas Industry

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:

changes in global supply and demand for oil and natural gas, which has recently been negatively affected by concerns about the impact of COVID-19;
the actions of the Organization of Petroleum Exporting Countries, or OPEC;
the oil price war between Russia and Saudi Arabia;
the price and quantity of imports of foreign oil and natural gas;
political conditions, including embargoes, in or affecting other oil-producing activity;
the level of global oil and natural gas exploration and production activity;
the level of global oil and natural gas inventories;
weather conditions;
technological advances affecting energy consumption; and
the price and availability of alternative fuels.

Lower oil and natural gas prices may not only decrease our revenues on a per BOE basis but also may reduce the amount of oil and natural gas that we can produce economically. Lower prices also negatively impact the value of our proved reserves. The recent drop in the price of oil has forced the Company, as well as other operators, to re-evaluate our current capital expenditure budget and make changes accordingly that we believe are in the best interest of the Company and its stockholders. 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.

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, on January 20, 2021, the Biden Administration placed a 60-day moratorium on new oil and gas leasing and drilling permits on federal land, and on January 27, 2021, the Department of Interior acting pursuant to an Executive Order from President Biden suspended the federal oil and gas leasing program indefinitely. While we do not have a significant federal lands acreage position at 240 net acres, these actions could have a material adverse effect on the Company and our industry.

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 project uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following: delays imposed by or resulting from compliance with regulatory requirements; pressure or irregularities in geological formations; shortages of or delays in obtaining equipment and qualified personnel; equipment failures or accidents; adverse weather conditions; reductions in oil and natural gas prices; title problems; and limitations in the market for oil and natural gas.

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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 which could negatively impact the trading value of our securities.

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 down the carrying value of our oil and natural gas properties. A write-down could also constitute a non-cash charge to earnings. The cumulative effect of a write-down could also negatively impact the trading price of our securities.

We follow the full cost method of accounting for our oil and natural gas properties. Under the full cost method, the net book value of properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling is the estimated after tax future net revenues from proved oil and natural gas properties, discounted at 10% per year. Discounted future net revenues are estimated using oil and natural gas spot prices based on the average price during the preceding 12-month period determined as an un-weighted, arithmetic average of the first-day-of-the-month price for each month within such period, except for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an impairment expense. During the year ended December 31, 2020, we recorded a non-cash write down of $277.5 million. We did not record a write down during 2019. Under SEC full cost accounting rules, any write-off recorded may not be reversed even if higher oil and natural gas prices increase the ceiling applicable to future periods. Future price decreases could result in reductions in the carrying value of such assets and an equivalent charge to earnings.

It is difficult to predict with reasonable certainty the amount of expected future impairments given the many factors impacting the ceiling test calculation including, but not limited to, future pricing, operating costs, upward or downward reserve revisions, reserve adds, and tax attributes.

Decreases in oil and natural gas prices may affect our borrowing base, potentially requiring earlier than anticipated debt repayment, which could negatively impact the trading value of our securities.

Decreases in oil and natural gas prices could also result in reductions in the borrowing base of our Credit Facility, thus requiring earlier than anticipated repayment of debt.

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

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

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

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

You should not assume that the present value of future net revenues from our reported proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. If future values decline or costs increase it could negatively impact our ability to finance operations, and individual properties could cease being commercially viable, affecting our decision to continue operations on producing properties or to attempt to develop properties. All of these factors would have a negative impact on earnings and net income,

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and most likely the trading price of our securities. These factors could also result in the acceleration of debt repayment and a reduction in our borrowing base under our credit facility.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;
abnormally pressured formations;
mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
fires and explosions;
personal injuries and death; and
natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to our Company. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, then it could materially and adversely affect us.

Unless we replace our oil and natural gas reserves, our reserves and production will decline as reserves are produced.

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and, therefore, our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. If we are unable to develop, exploit, find or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing properties would be incapable of sustaining commercial production.

Competition is intense in the oil and natural gas industry.

We operate in a highly competitive environment for acquiring properties and marketing oil and natural gas. Our competitors include multinational oil and natural gas companies, major oil and natural gas companies, independent oil and natural gas companies, individual producers, financial buyers as well as participants in other industries that supply energy and fuel to consumers. Many of our competitors have greater and more diverse resources than we do. Additionally, competition for acquisitions may significantly increase the cost of available properties. We compete for the personnel and equipment required to explore, develop and operate properties. Our competitors also may have established long-term strategic positions and relationships in areas in which we may seek to enter. Consequently, our competitors may be able to address these competitive factors more effectively than we can. If we are not successful in our competition for oil and natural gas reserves or in our marketing of production, then our financial condition and operation results may be adversely affected.

If our access to markets is restricted, it could negatively impact our production, our income and our ability to retain our leases.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business.

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Currently, the majority of our production is sold to marketers and other purchasers that have access to nearby pipeline facilities. However, as we further develop our properties, we may find production in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking or requiring compression facilities. Such restrictions on our ability to sell our oil or natural gas could have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.

Risks Relating to Legal, Regulatory, Privacy and Tax Matters

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

Exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. It is not possible to predict how or when regulations affecting our operations might change. The Biden Administration’s January 20, 2021 issuance of a 60-day moratorium on new oil and gas leasing and drilling permits on federal land, and the related January 27, 2021 Executive Order suspending the federal oil and gas leasing program are examples of the uncertainties our Company and the industry faces with respect to regulation at the federal level. Similarly, at the state level, New Mexico’s consideration of legislation to prohibit certain uses of freshwater in fracking operations, implement new disclosure requirements, and increase penalties may affect the cost and feasibility of our business. We may be required to make large expenditures to comply with governmental regulations. Other matters subject to regulation include: discharge permits for drilling operations; drilling bonds; reports concerning operations; the spacing of wells; unitization and pooling of properties; and taxation.

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

Our operations may incur substantial liabilities to comply with the environmental laws and regulations.

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition as well as the industry in general. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed. The amount of additional future costs is not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions or compliance efforts that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.

Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.

The U.S. Congress and the EPA, in addition to some state and regional authorities, have in recent years considered legislation or regulations to reduce emissions of greenhouse gases, or GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. In the absence of federal GHG-limiting legislation, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the U.S. CAA. For example, the EPA has adopted and implemented regulations under existing provisions of the CAA that, among other things,

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establish permitting requirements for GHG, require that certain facilities meet “best available control technology” standards, and mandate annual reporting of GHG emissions.

The EPA also sought to address climate change through its GHG NSPS regulations, which the current administration intends to review, pursuant to the Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis. Many state governments have established rules aimed at reducing greenhouse gas emissions, including greenhouse gas cap and trade programs. Most of these cap-and-trade programs work by requiring major sources of emissions to acquire and surrender emission allowances. It is difficult to predict the timing and certainty of such government actions and their ultimate effect, which could depend on, among other things, the type and extent of greenhouse gas reductions required, the availability and price of emissions allowances or credits, the availability and price of alternative fuel sources, the energy sectors covered, and the ability to recover the costs incurred through our operating agreements or the pricing of oil, natural gas, and other products.

On an international level, the United States is one of almost 200 nations that agreed in December 2015 to 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. 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. It is not possible at this time to predict how or when the United States might impose restrictions on GHGs as a result of the Paris Agreement.

Risks Relating to Our Capital Structure

If our indebtedness increases, it could reduce our financial flexibility.

We have a credit facility in place with $350 million in commitments for borrowings and letters of credit. As of December 31, 2020, $313 million was outstanding on our credit facility. If we further utilize this facility, the level of our indebtedness could affect our operations in several ways, including the following:

a significant portion of our cash flow could be used to service the indebtedness;
a high level of debt would increase our vulnerability to general adverse economic and industry conditions;
the covenants contained in our credit facility limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments, and;
a high level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

In addition, our bank borrowing base is subject to semi-annual redeterminations. We could be required to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are required to do so, we may not have sufficient funds to make such repayments, and we may need to negotiate renewals of our borrowings or arrange new financing or sell significant assets. Any such actions could have a material adverse effect on our business and financial results.

We may be unable to access the equity or debt capital markets to meet our obligations.

Our plans for growth may include accessing the capital markets. Recent reluctance to invest in the exploration and production sector based on market volatility, perceived underperformance and Environmental, Social and Governance (ESG) trends, among other things, has raised concerns regarding capital availability for the sector. If those markets are unavailable, or if we are unable to access alternative means of financing on acceptable terms, we may be unable to implement all of our development plans, make acquisitions or otherwise carry out our business strategy, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

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Risks Relating to Technology and Cybersecurity

We rely on computer and telecommunications systems, and failures in our systems or cyber security attacks or breaches could result in information theft, data corruption, disruption in operations and/or financial loss.

The oil and natural gas industry has become increasingly dependent upon digital technologies to conduct day-to-day operations including certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil and natural gas reserves, process and record financial and operating data, analyze seismic and drilling information, process and store personally identifiable information on our employees and royalty owners and communicate with our employees and other third parties. Our business partners, including vendors, service providers, purchasers of our production and financial institutions, are also dependent on digital technology. It is possible that we could incur interruptions from cyber security attacks or breaches, computer viruses or malware that could result in disruption of our business operations and/or financial loss. Although we utilize various procedures and controls to monitor and protect against these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing and causing us to suffer losses in the future. Even so, any cyber incidents or interruptions to our computing and communications infrastructure or our information systems could lead to data corruption, communication interruption, unauthorized release, gathering, monitoring, misuse or destruction of proprietary or other information, or otherwise significantly disrupt our business operations. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

Risks Relating to Our Common Stock

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

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

our operating and financial performance and prospects;
variations in our quarterly operating results and changes in our liquidity position;
investor perceptions of us and the industry and markets in which we operate;
future sales, or the availability for sale, of equity or equity-related securities;
changes in securities analysts' estimates of our financial performance;
changes in market valuations of similar companies;
changes in the price of oil and natural gas; and
general financial, domestic, economic and other market conditions.

We have no current plans to pay dividends on our common stock.

We do not currently anticipate paying any cash dividends on our common stock. We currently intend to retain future earnings, if any, to pay down debt and finance the expansion of our business. Our future dividend policy is within the discretion of our Board of Directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities. In addition, our current credit facility prohibits us from paying dividends.

Our Board of Directors can, without stockholder approval, cause preferred stock to be issued on terms that could adversely affect common stockholders.

Under our Articles of Incorporation, our Board of Directors is authorized to issue up to 50,000,000 shares of preferred stock, of which none are issued and outstanding as of the date of this Annual Report. Also, our Board of Directors, without stockholder approval, may determine the price, rights, preferences, privileges and restrictions, including voting rights, of those shares. If the Board of Directors causes shares of preferred stock to be issued, the rights of the holders of our common stock could be adversely affected. The Board of Director’s ability to determine the terms of preferred stock and to cause its issuance, while providing desirable flexibility in connection with possible acquisitions and other corporate purposes, could have the effect of making it more difficult for a third party

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to acquire a majority of our outstanding voting stock. Preferred shares issued by the Board of Directors could include voting rights, or even super voting rights, which could shift the ability to control the Company to the holders of the preferred stock. Preferred shares could also have conversion rights into shares of common stock at a discount to the market price of the common stock which could negatively affect the market for our common stock. In addition, preferred shares would have preference in the event of liquidation of the Company, which means that the holders of preferred shares would be entitled to receive the net assets of the Company distributed in liquidation before the common stockholders receive any distribution of the liquidated assets. We have no current plans to issue any shares of preferred stock.

Provisions under Nevada law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock.

In addition to the ability of the Board of Directors to issue preferred stock, the existence of some provisions under Nevada law could delay or prevent a change in control of the Company, which could adversely affect the price of our common stock. Nevada law imposes some restrictions on mergers and other business combinations between us and any holder of 10% or more of our outstanding common stock.

Item 1B:  Unresolved Staff Comments

None.

Item 2:  Properties

General Background

Ring is currently engaged in oil and natural gas acquisition, exploration, development and production, with activities and operations currently in Texas and New Mexico. While our business model includes pursuing acquisition opportunities, our near-term focus will be on the development of our existing properties.

Management’s Business Strategy Related to Properties

Our goal is to increase stockholder value by investing in oil and natural gas projects with attractive rates of return on capital employed. We plan to achieve this goal by exploiting and developing our existing oil and natural gas properties and pursuing strategic acquisitions of additional properties.

Developing and Exploiting Existing Properties

We believe that there is significant value to be created by drilling the identified undeveloped opportunities on our properties. As of December 31, 2020, we owned interests in a total of 53,912 gross (45,053 net) developed acres and operate the vast majority of our acreage position. In addition, as of December 31, 2020, we owned interests in approximately 50,543 gross (31,692 net) undeveloped acres. While our near-term plans are focused towards drilling wells on our existing acreage to develop the potential contained therein, our long term plans also include continuing to evaluate acquisition and leasing opportunities.

Pursuing Profitable Acquisitions

We have historically pursued acquisitions of properties that we believe to have exploitation and development potential comparable to our existing inventory of drilling locations. We have developed and refined an acquisition program designed to increase reserves and complement our existing core properties. We have an experienced team of management and engineering professionals who identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties.

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Summary of Oil and Natural Gas Properties and Projects

Significant Operations

Northwest Shelf –Yoakum, Runnels and Coke County, Texas and Lea County, New Mexico – In 2019, we acquired properties consisting of 49,754 gross (38,230 net) acres with an average working interest of 77% and an average net revenue interest of 58%. As of December 31, 2020, our acreage position in these counties is 46,972 gross (32,915 net) acres with 11,723 gross (8,085 net) developed and held by production and 35,249 gross (24,830 net) being undeveloped. Our reserve estimates include 72 identified proved horizontal drilling locations and 11 proved vertical drilling locations. Our reserve estimates include the capital costs required to develop these wells. We believe the Northwest Shelf leases contain a considerable number of remaining potential drilling locations.

Central Basin Platform - Andrews and Gaines County, Texas leases In 2011, we acquired a 100% working interest and a 75% net revenue interest in the Company’s initial leases in Andrews and Gaines counties. Since that time, we have acquired working and net revenue interests in additional producing leases and acquired additional undeveloped acreage in and around our Andrews County and Gaines county leases. The working interests range from 1-100% and the net revenue interests range from 1-80%. In total as of December 31, 2020, we own 38,714 gross (25,362 net), acres with 23,668 gross (18,712 net) acres developed and held by production and the remaining 15,046 gross (6,650 net) acres being undeveloped. Our reserve estimates include 2 proved vertical and 32 horizontal PUD wells. Our reserve estimates include the capital costs required to develop these wells. We believe the Central Basin Platform leases contain a considerable number of remaining potential drilling locations.

Delaware Basin - Culberson and Reeves County, Texas leases In 2015, we acquired properties consisting of 19,983 gross (19,679 net) acres with an average working interest of 98% and an average net revenue interest of 79%. Since that time, we have acquired additional undeveloped acreage in and around our Culberson and Reeves County leases. In total as of December 31, 2020, we own 18,769 gross (18,468 net) acres with 18,521 gross (18,256 net) acres developed and held by production and the remaining 248 gross (212 net) acres being undeveloped. Our reserve estimates include 26 proved vertical and 4 horizontal PUD wells. Our reserve estimates include the capital costs required to develop these wells. We believe the Delaware Basin leases contain a considerable number of remaining potential drilling locations.

Title to Properties

We generally conduct a preliminary title examination prior to the acquisition of properties or leasehold interests. Prior to commencement of operations on such acreage, a thorough title examination is usually conducted and any significant defects are remedied before proceeding with operations. We believe the title to our leasehold properties is good, defensible and customary with practices in the oil and natural gas industry, subject to such exceptions that we believe do not materially detract from the use of such properties. With respect to our properties of which we are not the record owner, we rely on contracts with the owner or operator of the property or assignment of leases, pursuant to which, among other things, we generally have the right to have our interest placed on record.

Our properties are generally subject to royalty, overriding royalty and other interests customary in the industry, liens incident to agreements, current taxes and other customary burdens, minor encumbrances, easements and restrictions. We do not believe any of these burdens will materially interfere with our use of these properties.

Summary of Oil and Natural Gas Reserves

As of December 31, 2020, our estimated proved reserves had a pre-tax PV10 value of approximately $638.1 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $555.9 million, 100% of which relates to our properties in the Permian Basin in Texas and New Mexico. We spent approximately $466.9 million on acquisitions and capital projects during 2019 and 2020. We expect to further develop these properties through additional drilling.

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The following table summarizes our total net proved reserves, pre-tax PV10 value and Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2020. All of our reserves are in the Permian Basin in the States of Texas and New Mexico.

    

    

    

    

Standardized

Measure of

Oil

Natural

Total

Pre-Tax PV10

Discounted Future

(Bbl)

Gas (Mcf)

(Boe)

Value

Net Cash Flows

66,264,286

 

61,305,027

 

76,481,791

$

638,107,637

$

555,871,253

The Company presents the pre-tax PV10 value, which is a non-GAAP financial measure, because it is a widely used industry standard which we believe is useful to those who may review this Annual Report when comparing our asset base and performance to other comparable oil and natural gas exploration and production companies.

Reserve Quantity Information

Our estimates of proved reserves and related valuations are based on reports independently determined and prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. These reserves are attributable solely to properties within the United States. A summary of the changes in quantities of proved (developed and undeveloped) oil and natural gas reserves is shown below.

    

Oil (Bbl)

    

Gas (Mcf)

Balance, December 31, 2018

 

27,809,748

52,765,698

Purchase of minerals in place

 

36,501,824

 

41,921,368

Improved recovery

 

4,732,449

 

2,530,636

Extensions and discoveries

 

13,295,301

 

5,501,627

Production

 

(3,536,126)

 

(2,476,472)

Sales of minerals in place

(758,169)

(811,279)

Upward revisions of estimates

 

2,731,228

 

1,618,234

Downward revision of estimates due to well performance

 

(3,699,908)

 

(11,680,453)

Downward revision of estimates due to commodity prices

 

(3,655,679)

 

(28,789,545)

Downward revision of estimates due to removal of undeveloped locations

 

(2,061,654)

 

(2,307,932)

Balance, December 31, 2019

 

71,359,014

 

58,271,882

Improved recovery

 

3,495,210

 

1,824,310

Production

 

(2,801,528)

 

(2,494,501)

Upward revisions of estimates

 

2,591,965

 

6,158,076

Downward revision of estimates due to well performance

 

(4,484,425)

 

44,370

Downward revision of estimates due to commodity prices

 

(2,313,890)

 

(2,303,700)

Downward revision of estimates due to removal of undeveloped locations

 

(1,582,060)

 

(195,410)

Balance, December 31, 2020

 

66,264,286

 

61,305,027

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Our proved oil and natural gas reserves are shown below.

For the Years Ended December 31,

    

2020

    

2019

Oil (Bbls)

 

  

 

  

Developed

 

38,260,638

 

41,242,064

Undeveloped

 

28,003,648

 

30,116,950

Total

 

66,264,286

 

71,359,014

Natural Gas (Mcf)

 

  

 

  

Developed

 

34,335,520

 

34,467,868

Undeveloped

 

26,969,507

 

23,804,014

Total

 

61,305,027

 

58,271,882

Total (Boe)

 

  

 

  

Developed

 

43,983,225

 

46,986,709

Undeveloped

 

32,498,566

 

34,084,285

Total

 

76,481,791

 

81,070,994

Standardized Measure of Discounted Future Net Cash Flows

Our standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and changes in the standardized measure as described below were prepared in accordance with generally accepted accounting principles.

Future income tax expenses are calculated by applying appropriate year-end tax rates to future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of our oil and natural gas properties.

Our estimates of reserves and future cash flow as of December 31, 2020 and 2019 were prepared using an average price equal to the unweighted arithmetic average of the first day of the month price for each month within the 12-month periods ended December 31, 2020 and 2019, respectively, in accordance with SEC guidelines.  As of December 31, 2020, our reserves are based on an SEC average price of $36.04 per Bbl of WTI oil posted and $1.99 per MMBtu Henry Hub natural gas. As of December 31, 2019, our reserves are based on an SEC average price of $52.19 per Bbl of WTI oil posted and $2.58 per MMBtu Henry Hub natural gas. Prices are adjusted by local field and lease level differentials and are held constant for life of reserves in accordance with SEC guidelines.

The standardized measure of discounted future net cash flows relating to the proved oil and natural gas reserves are shown below.

Standardized Measure of Discounted Future Net Cash Flows

December 31, 

    

2020

    

2019

Future cash flows

$

2,682,488,655

$

3,825,773,515

Future production costs

 

(821,515,126)

 

(964,887,856)

Future development costs

 

(244,323,270)

 

(252,457,833)

Future income taxes

 

(208,645,934)

 

(424,715,966)

Future net cash flows

 

1,408,004,325

 

2,183,711,860

10% annual discount for estimated timing of cash flows

 

(852,133,072)

 

(1,260,536,809)

Standardized Measure of Discounted Future Net Cash Flows

$

555,871,253

$

923,175,051

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The changes in the standardized measure of discounted future net cash flows relating to the proved oil and natural gas reserves are shown below.

    

2020

    

2019

Beginning of the year

$

923,175,051

$

455,944,641

Purchase of minerals in place

 

 

598,489,190

Improved recovery, less related costs

 

61,303,074

 

86,989,301

Extensions and discoveries, less related costs

 

 

247,652,632

Development costs incurred during the year

 

29,916,746

 

152,125,320

Sales of oil and gas produced, net of production costs

 

(70,634,853)

 

(137,663,314)

Sales of minerals in place

 

 

(30,174,528)

Accretion of discount

 

92,838,323

 

47,463,292

Net changes in price and production costs

 

(368,974,767)

 

(219,608,128)

Net change in estimated future development costs

 

(3,883,985)

 

47,617,158

Upward revisions

 

32,920,723

 

44,034,636

Revision of previous quantity estimates as a result well performance

(52,731,122)

(64,553,979)

Revision of previous quantity estimates as a result of commodity prices

 

(26,590,142)

 

(71,545,320)

Revision of previous quantity estimates as a result removal of uneconomic proved undeveloped locations

 

(19,812,745)

 

(34,079,006)

Revision of estimated timing of cash flows

 

(139,039,115)

 

(107,443,484)

Net change in income taxes

 

97,384,365

 

(92,073,360)

End of the Year

$

555,871,553

$

923,175,051

Our proved reserves by state as of December 31, 2020 are summarized in the table below.

    

    

    

    

    

    

Standardized

    

Measure of

Discounted Future

Future Capital

% of Total

Pre-tax PV10

Net Cash Flows

Expenditures

Oil (Bbl)

Gas (Mcf)

Total (Boe)

Proved

(In thousands)

(In thousands)

(In thousands)

Texas

PD

 

36,075,577

 

32,364,426

 

41,469,648

 

54

%  

$

418,844

$

364,435

$

23,655

PUD

 

27,055,299

 

26,207,571

 

31,423,228

 

41

%  

 

193,527

 

168,387

 

208,590

Total Proved:

 

63,130,876

 

58,571,997

 

72,892,876

 

95

%  

$

612,371

$

532,822

$

232,245

New Mexico

PD

2,185,061

1,971,094

2,513,577

3

%  

$

19,364

$

17,342

$

1,505

PUD

948,349

761,936

1,075,338

1

%  

6,373

 

5,707

10,573

Total Proved:

3,133,410

2,733,030

3,588,915

5

%  

$

25,737

$

23,049

$

12,078

Total

PD

38,260,638

34,335,520

43,983,225

57.5

%  

$

438,208

$

381,777

$

25,160

PUD

28,003,648

26,969,507

32,498,566

42.5

%  

199,900

 

174,094

219,163

Total Proved:

66,264,286

61,305,027

76,481,791

100

%  

$

638,108

$

555,871

$

244,323

66,264,286

61,305,027

76,481,791

638,108

244,323

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Proved Reserves

We have approximately 76.5 million BOE of proved reserves, consisting of approximately 87% oil and 13% natural gas, as summarized in the table above as of December 31, 2020, on a net pre-tax PV10 value and Standardized Measure of Discounted Future Net Cash Flows basis. Our reserve estimates have not been filed with any Federal authority or agency (other than the SEC).

As of December 31, 2020, approximately 57.5% of the proved reserves have been classified as proved developed, or “PD” and the remaining 42.5% are proved undeveloped, or “PUD”.

As of December 31, 2020, our total proved reserves had a net pre-tax PV10 value of approximately $638.1 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $555.9 million. Approximately $438.2 million and $381.8 million, respectively, of total proved reserves are associated with the PD reserves, which is approximately 69% of the total proved reserves’ pre-tax PV10 value. The remaining $199.9 million and $174.1 million, respectively, are associated with PUD reserves.

Proved Undeveloped Reserves

Our reserve estimates as of December 31, 2020 include approximately 32.5 million BOE as proved undeveloped reserves. As of December 31, 2019, our reserve estimates included approximately 35.1 million BOE as proved undeveloped reserves. Below is a description of the changes in our PUD reserves from December 31, 2019 to December 31, 2020.

During the year ended December 31, 2020, we incurred costs of approximately $10.0 million to convert 1,698,122 BOE of reserves from PUD to PD through development.

Other changes to our PUD reserves included:

Upward revisions of 3,521,992 BOE as the result of a reduction in lease operating expenses in certain areas and improved offsetting production due to pump optimization and improved completion practices;
Downward revisions of 1,794,900 BOE as the result of changes in commodity prices; and
Downward revision of 1,614,628 BOE for the removal of locations due to lack of development within the prescribed time frame due to changes in anticipated development programs as a result of market conditions

The following table indicates projected reserves that we currently estimate will be converted from proved undeveloped to proved developed, as well as the estimated costs per year involved in such development.

Estimated Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed Reserves

    

Estimated Oil

    

Estimated Gas

    

    

Reserves

Reserves

Estimated

Year

Developed (Bbls)

Developed (Mcf)

Total Boe

Development Costs

2021

5,880,319

6,006,939

6,881,476

42,156,847

2022

 

9,345,510

 

9,186,059

 

10,876,520

72,617,289

2023

 

9,706,829

 

10,062,460

 

11,383,906

 

78,041,149

2024

 

3,070,990

 

1,714,049

 

3,356,665

 

26,348,548

 

28,003,648

 

26,969,507

 

32,498,566

$

219,163,833

Preparation and Internal Controls Over Reserves Estimates

All the proved oil and natural gas reserves disclosed in this report are based on reserve estimates determined and prepared by independent reserve engineers Cawley, Gillespie & Associates (“CGA”), a leader of petroleum property analysis for industry and financial institutions. CGA was founded in 1960 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CGA, the technical person primarily responsible for preparing the estimates set

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forth in the CGA letter dated February 10, 2021, filed as an exhibit to this Annual Report on Form 10-K, was Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CGA since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 30 years of practical experience in petroleum engineering, with over 30 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

The proved oil and natural gas reserves disclosed in this report are based on reserve estimates determined and prepared by independent reserve engineers primarily using decline curve analysis to determine the reserves of individual producing wells. To establish reasonable certainty with respect to our estimated proved reserves, the independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using volumetric estimates or performance from analogous wells in the surrounding area. These wells were considered to be analogous based on production performance from the same formation and completions using similar techniques. The technologies and economic data used to estimate our proved reserves include, but are not limited to, well logs, geological maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. This data was reviewed by various levels of management for accuracy before consultation with independent reserve engineers. This consultation included review of properties, assumptions and available data. Internal reserve estimates were compared to those prepared by independent reserve engineers to test the estimates and conclusions before the reserves were included in this report. The accuracy of the reserve estimates is dependent on many factors, including the following:

the quality and quantity of available data and the engineering and geological interpretation of that data;
estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;
the accuracy of economic assumptions; and
the judgment of the personnel preparing the estimates.

Ring’s Executive Vice President of Engineering and Corporate Strategy, Mr. Alex Dyes, is the technical professional primarily responsible for overseeing the preparation of our reserves estimates. He has a Bachelor of Science degree in Petroleum Engineering with over 14 years of practical industry experience, including over 10 years of estimating and evaluating reserve information. He is a member of the Society of Petroleum Engineers since 2013 and his qualifications meet or exceed the Society of Petroleum Engineers’ standard requirements to be a professionally qualified Reserve Estimator and Auditor.

We encourage ongoing professional education for our engineers and analysts on new technologies and industry advancements as well as refresher training on basic skill sets. In order to ensure the reliability of reserves estimates, the Corporate Reserves department follows comprehensive SEC-compliant internal controls and policies to determine, estimate and report proved reserves including:

confirming that we include reserves estimates for all properties owned and that they are based upon proper working and net revenue interests;
ensuring the information provided by other departments within the Company such as Accounting is accurate;
communicating, collaborating, and analyzing with technical personnel in our business units;
comparing and reconciling the internally generated reserves estimates to those prepared by third parties;
utilizing experienced reservoir engineers or those under their direct supervision to prepare reserve estimates; and
ensuring compensation for the reserve engineers is not tied to the amount of reserves recorded.

Each quarter, the Executive Vice President of Engineering and Corporate Strategy presents the status of the Company’s reserves to senior executives, and subsequently obtains approval of significant changes from key executives. Additionally, the five-year PUD development plan is reviewed and approved annually by the Company’s Chief Executive Officer, Chief Financial Officer, Executive Vice President of Operations, the Executive Vice President of Land, Legal, Human Resources, and Marketing, and the Executive Vice President of Engineering and Corporate Strategy.

The Corporate Reserves department works closely with independent petroleum consultants at each fiscal year end to ensure the integrity, accuracy and timeliness of annual independent reserves estimates. These independently developed reserves estimates are

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presented to the Audit Committee. In addition to reviewing the independently developed reserve reports, the Audit Committee also periodically meets with the independent petroleum consultants that prepare estimates of proved reserves.

Summary of Oil and Natural Gas Properties and Projects

Production Summary

Our estimated average daily total Company net production for the month of December 2020 is 9,201 BOE/d. The following table provides the calculation of this daily production rate for the month of December 2020.

Oil (Bbls)

    

244,857

Gas (Mcf)

 

242,180

Total production (BOE)

 

285,221

 

  

Daily production (Boe/d)

 

9,201

Acreage

The following table summarizes gross and net developed and undeveloped acreage as of December 31, 2020 by region (net acreage is our percentage ownership of gross acreage). Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.

    

Developed Acreage

    

Undeveloped Acreage

    

Total Acreage

Gross

Net

Gross

Net

Gross

Net

Central Basin Platform

 

23,668

    

18,712

 

15,046

    

6,650

 

38,714

    

25,362

Delaware Basin

 

18,521

 

18,256

 

248

 

212

 

18,769

 

18,468

Northwest Shelf

11,723

8,085

35,249

24,830

46,972

32,915

Total

 

53,912

 

45,053

 

50,543

 

31,692

 

104,455

 

76,745

Leases of undeveloped acreage will generally expire at the end of their respective primary terms unless production from such leasehold acreage has been established prior to expiration of such primary term. If production is established on such acreage, the lease will generally remain in effect until the cessation of production from such acreage and is referred to in the industry as “Held-By-Production” or “HBP.” Leases of undeveloped acreage may terminate or expire as a result of not meeting certain drilling commitments, if any, or otherwise by not complying with the terms of a lease depending on the specific terms that are negotiated between lessor and lessee.

The following table sets forth the gross and net undeveloped acreage, as of December 31, 2020, under lease which would expire over the next three years unless (i) production is established on the lease or within a spacing unit of which the lease is participating, or (ii) the lease is renewed or extended prior to the relevant expiration dates:

    

2021

    

2022

    

2023

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

    

    

    

Undeveloped acreage

 

19,350

 

13,252

 

6,409

 

2,259

 

1,978

 

1,908

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Production History

The following table presents the historical information about our produced natural gas and oil volumes for the years ended December 31, 2020, 2019 and 2018:

Years Ended December 31,

    

2020

    

2019

    

2018

Oil (Bbls)

  

  

  

Central Basin Platform

 

958,691

 

1,590,473

 

1,812,616

Delaware Basin

 

159,635

 

275,080

 

234,679

Northwest Shelf

1,683,202

1,670,573

Total

 

2,801,528

 

3,536,126

 

2,047,295

 

 

 

Gas (Mcf)

 

 

 

Central Basin Platform

 

268,495

 

315,228

 

346,115

Delaware Basin

 

468,177

 

939,437

 

766,062

Northwest Shelf

1,757,830

1,221,807

Total

 

2,494,502

 

2,476,472

 

1,112,177

 

 

 

Total production (BOE)

 

 

 

Central Basin Platform

 

1,003,440

 

1,643,011

 

1,870,302

Delaware Basin

 

237,665

 

431,653

 

362,356

Northwest Shelf

1,976,173

1,874,207

Total

 

3,217,278

 

3,948,871

 

2,232,658

 

 

 

Daily production (Boe/d)

 

 

 

Central Basin Platform

 

2,742

 

4,501

 

5,124

Delaware Basin

 

649

 

1,183

 

993

Northwest Shelf

5,399

5,135

Total

 

8,790

 

10,819

 

6,117

Production Prices and Production Costs

The following tables provides historical pricing and costs statistics for the years ended December 31, 2018, 2019 and 2020.

Years Ended December 31,

    

2020

    

2019

    

2018

Average sales price:

 

  

Oil (per Bbl)

$

38.95

$

54.27

$

56.99

Natural gas (per Mcf)

 

1.57

 

1.54

 

3.05

Total (per Boe)

 

35.13

 

49.56

 

53.78

Average production cost (including ad valorem taxes) (per Boe)

$

11.49

$

12.28

$

12.45

Average production taxes (per Boe)

 

1.63

 

2.31

 

2.52

The average oil sales price amounts above are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels “Bbl”. The average natural gas sales price amounts above are calculated by dividing revenue from natural gas sales by the volume of natural gas sold, in thousand cubic feet “Mcf”. The total average sales price amounts are calculated by dividing total revenues by total volume sold, in BOE. The average production costs above are calculated by dividing production costs by total production in BOE.

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Productive Wells

The following table presents our ownership as of December 31, 2020 in productive oil and natural gas wells (a net well is our percentage ownership of a gross well). All of such wells are in the Permian Basin in Texas and New Mexico.

Oil Wells

Gas wells

Total Wells

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

610

 

441

 

 

 

610

 

441

Drilling Activity

During 2020, we drilled 6 gross (5.61 net) wells in the Northwest Shelf in the Permian Basin. We completed and placed on production 4 of these wells during the first quarter 2020. Two wells were drilled in December 2020 and subsequently completed and placed on production during 2021. All of these wells were successful and there were no dry wells.

The table below contains information regarding the number of wells drilled during the periods indicated.

For the year ended December 31,

2020

2019

2018

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

Exploratory

Productive

 

 

 

 

 

 

Dry

 

 

 

 

 

 

Development

 

  

 

  

 

  

 

  

 

  

 

  

Productive

 

6.00

 

5.61

 

30.00

 

29.33

 

57.00

 

56.25

Dry

 

  

 

  

 

  

 

  

 

  

 

  

Total

 

  

 

  

 

  

 

  

 

  

 

  

Productive

 

6.00

 

5.61

 

30.00

 

29.33

 

57.00

 

56.25

Dry

 

 

 

 

 

 

Present Activities

There were no wells in the process of being drilled, however, there were two wells waiting to be being completed as of December 31, 2020.

Cost Information

We conduct our oil and natural gas activities entirely in the United States. As noted in the table under “Production Prices and Production Costs”, our average production costs, per BOE, were $12.45, $12.28 and $11.49 during the years ended December 31, 2018, 2019 and 2020, respectively, and our average production taxes, per BOE, were $2.52, $2.31 and $1.63 for the years ended December 31, 2018, 2019 and 2020, respectively. These amounts are calculated by dividing our total production costs or total production taxes by our total volume sold, in BOE.

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Costs incurred for property acquisition, exploration and development activities during the years ended December 31, 2019 and 2020 are shown below:

    

2020

    

2019

Wishbone Acquisition (1)

$

$

304,392,921

Acquisition of proved properties

1,317,313

3,400,411

Divestiture of proved properties

(8,547,074)

Acquisition of unproved properties

 

 

Exploration costs

 

 

Development costs

 

42,457,745

 

152,125,320

Total Costs Incurred

$

43,775,058

$

451,371,578

(1)Wishbone Acquisition in 2019 includes $28.3 million in fair value of stock issued as consideration in acquisitions.

Other Properties and Commitments

Our principal executive offices are in leased office space in The Woodlands, Texas.  The lease for this office space was entered into subsequent to December 31, 2020.  Prior to this and throughout 2020, our principal offices were in Midland, Texas.  Those offices now serve as an operations office. We also lease office space in Tulsa, Oklahoma, which serves as our current accounting office, but which will be closed following the transition of those functions to The Woodlands offices.  We expect our current office space to be adequate as we move forward.

Item 3:  Legal Proceedings

In the ordinary course of business, we may be, from time to time, a claimant or a defendant in various legal proceedings. We do not presently have any material litigation pending or threatened requiring disclosure under this item.

Item 4:  Mine safety disclosures

Not applicable.

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PART II

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

Market for our Common Stock

Our common stock is listed on the NYSE American under the trading symbol “REI.”

Performance Graph

The following graph compares the cumulative 5-year total return attained by stockholders on Ring’s common stock relative to the cumulative total returns of the S&P 500 index and that of a selected peer group, named below. The graph assumes a $100 investment at the closing price on December 31, 2015, and reinvestment of dividends on the date of payment without commission. This table is not intended to forecast future performance of our common stock.

Graphic

*

The peer group consists of: Callon Petroleum Company, Earthstone Energy, Inc., Laredo Petroleum, Inc., Abraxas Petroleum Corporation and Contango Oil & Gas Company, all of which are in the oil and natural gas exploration and production industry.

The performance graph above is furnished and not filed for purposes of Section 18 of the Exchange Acts and will not be incorporated by reference into any registration filed under the Securities Act unless specifically identified therein as being incorporated by reference. The performance graph is not solicitation material subject to Regulation 14A.

Record Holders

As of March 1, 2021, there are approximately 21,632 holders of record of our common stock.

Dividend Policy

We do not currently anticipate paying any cash dividends on our common stock. We currently intend to retain future earnings, if any, to pay down debt and finance the expansion of our business. Our future dividend policy is within the discretion of our Board of Directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities. In addition, our current credit facility prohibits us from paying dividends.

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Recent Sales of Unregistered Securities and Use of Proceeds from Registered Securities

None

Issuer Repurchases

We did not make any repurchases of our equity securities during the year ending December 31, 2020.

Item 6:  Selected Financial Data

The selected financial information set forth below is derived from our balance sheets and statements of operations as of and for the years ended December 31, 2020, 2019, 2018, 2017 and 2016. The data set forth below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes thereto included in this Annual Report.

For the years ended December 31, 

    

2020

    

2019

    

2018

    

2017

    

2016

Statement of Operations Data:

Revenues

$

113,025,138

$

195,702,831

$

120,065,361

$

66,699,700

$

30,850,248

Cost of revenues

 

42,196,963

 

57,626,604

 

33,433,082

 

19,130,924

 

11,372,420

Depreciation, depletion and amortization

 

43,010,660

 

56,204,269

 

39,024,886

 

20,517,780

 

11,483,314

Ceiling test impairment

 

277,501,943

 

 

14,172,309

 

 

56,513,016

Accretion

 

906,616

 

943,707

 

606,459

 

567,968

 

487,182

Operating lease expense

1,196,372

925,217

General and administrative

 

16,874,050

 

19,866,706

 

12,867,686

 

10,515,887

 

8,027,077

Net income (loss)

 

(253,411,828)

 

29,496,551

 

8,999,760

 

1,753,869

 

(37,637,687)

 

  

 

  

 

  

 

  

 

  

Basic income (loss) per common share

$

3.48

$

0.44

$

0.15

$

0.03

$

(0.97)

Diluted income (loss) per common share

$

3.48

$

0.44

$

0.15

$

0.03

$

(0.97)

As of December 31, 

    

2020

    

2019

    

2018

    

2017

    

2016

Balance Sheet Data:

Current assets

$

20,799,890

$

38,708,541

$

16,844,257

$

29,123,924

$

75,220,915

Oil and gas properties subject to amortization

 

836,514,815

 

1,083,966,135

 

641,121,398

 

433,591,134

 

250,133,965

Total assets

 

663,456,197

 

973,006,148

 

567,065,659

 

414,102,486

 

307,597,399

Total current liabilities

 

36,941,737

 

59,092,554

 

51,910,432

 

48,443,449

 

9,099,391

Total long-term liabilities

 

331,748,647

 

390,403,661

 

52,555,797

 

9,055,697

 

7,957,035

Total Stockholders Equity

 

294,765,813

 

523,509,933

 

462,599,430

 

356,603,340

 

290,540,973

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Item 7:  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our accompanying financial statements and the notes to those financial statements included elsewhere in this Annual Report. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs and our actual results could differ materially from those discussed in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors” and elsewhere in this Annual Report.

Overview

Ring is an exploration and production company based in The Woodlands that is engaged in oil and natural gas acquisition, exploration, development and production activities. Our exploration and production interests are currently focused in Texas and New Mexico. The Company seeks to exploit its acreage position through the drilling of highly economic, vertical and horizontal wells using the most recent drilling and completion techniques.  Our focus is drilling and developing our oil and gas properties through use of cash flow generated by our operations and reducing our long-term debt through the sale of non-core assets or through our excess cash flow while still working towards providing annual production growth. We continue to evaluate potential transactions to acquire attractive acreage positions within our core areas of interest.

Business Description and Plan of Operation

The Company seeks to exploit its acreage position through the drilling of highly economic, vertical and horizontal wells using the most recent drilling and completion techniques. Our focus is drilling and developing our oil and gas properties through use of cash flow generated by our operations and reducing our long-term debt through the sale of non-core assets or through our excess cash flow while still working towards maintaining or providing annual production growth. We continue to evaluate potential transactions to acquire attractive acreage positions within our core areas of interest.

2020 Developments and Highlights

In March 2020, the World Health Organization declared the COVID-19 outbreak a pandemic. Governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, which have caused a significant contraction in global economic activity, including a decline in the demand for oil and to a lesser extent natural gas.

Our business and operations have been adversely affected by, and may continue to be adversely affected by, the COVID-19 pandemic and the public health response thereto. As a result of the COVID-19 outbreak and the adverse public health developments, including voluntary and mandatory quarantines, travel restrictions and other restrictions, our operations, and those of our subcontractors, customers and suppliers, have experienced, and may to continue to experience, delays or disruptions. Starting the last week of April, essentially all of our production, other than that associated with our Delaware Basin property, was shut-in or curtailed. The curtailments continued until early June, when, with commodity prices improving and price differentials decreasing, the Company began to bring wells back on-line, returning to near April levels by the end of the second quarter.  In the third quarter 2020, we had restored production to 9,549 net BOEPD and in the fourth quarter 2020 we produced 9,307 net BOEPD.

In addition, our financial condition and results of operations have been, and may continue to be, adversely affected by the ongoing coronavirus outbreak. The timeline and potential magnitude of the COVID-19 outbreak and its consequences are currently unknown. The prolongation or exacerbation of this pandemic could more extensively affect the United States and global economy, including the demand for oil and natural gas.

The Company has experienced the effects of a negatively impacted domestic and international demand for crude oil and natural gas, which has contributed to price volatility and impacted the price we received for our production, and moreover materially and adversely affected the demand for and marketability of our production. For the Company, this means that production was shut in for some of our wells, and that we held some of our production as inventory to be sold at a later date because we refused to accept the unprecedented and exceptionally low price for our production. Our 2020 first quarter results were negatively impacted by the pandemic response, and we continued to experience the pandemic’s negative impact through the fourth quarter of 2020. At this time, we expect that our financial results for the first quarter of 2021 may be adversely impacted by our response to, the existence of and the global response to the COVID-19 pandemic.

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Also, in March 2020, Saudi Arabia and Russia, along with OPEC producers, failed to agree to cut oil production, and Saudi Arabia significantly cut the sell price of its oil and announced plans to increase production, which events together contributed to a sharp drop in global oil prices. While OPEC, Russia and other allied producers reached an agreement in April 2020, and most recently in March 2021, to reduce production, oil prices remained low until the first quarter of 2021. While OPEC+ producers ultimately agreed to cut global petroleum output, such cut was not enough to offset the impact of COVID-19 on 2020 demand. As a result of this decrease in demand and increase in supply, oil and natural gas prices decreased, which affected our liquidity. Additionally, with depressed oil and natural gas prices, we incurred a write-down to our oil and gas properties and additional write-downs may be required in future periods if prices decrease from current levels.  

The imbalance between the supply of and demand for oil, as well as the uncertainty around the extent and timing of an economic recovery, caused significant market volatility and a substantial adverse effect on commodity prices during the last three quarters of 2020. The Company expects ongoing oil and gas price volatility over the short-term. The full impact of the coronavirus on oil and natural gas prices continues to evolve as of the date of this report. As such, the full magnitude of such events on the Company remains uncertain. Management is actively monitoring the global situation and its impact on the Company’s future operations, financial position and liquidity in fiscal year 2020.

As a producer of oil and natural gas, we are recognized as an essential business under various federal, state and local regulations related to the COVID-19 pandemic. We have continued to operate as permitted under these regulations while taking steps to protect the health and safety of our workers. We have implemented protocols to reduce the risk of an outbreak within our field operations, and these protocols have not reduced production or efficiency in a significant manner. A substantial portion of our non-field level employees have transitioned temporarily to remote work-from-home arrangements. With these arrangements in place, we have been able to maintain a consistent level of effectiveness, including maintaining our day-to-day operations, our financial reporting systems and our internal control over financial reporting.

Our oil and natural gas producing properties are located in the Permian Basin. Oil sales represented approximately 96.5% and 98.1% of our total revenue for the twelve months ended December 30, 2020 and 2019, respectively. While natural gas prices also declined as a result of changes in demand, the decline in natural gas prices was far less significant than the decline in oil prices. As of December 31, 2020, we have in place derivative contracts covering 9,000 and 1,750 barrels of oil per day for the calendar years 2021 and 2022, respectively, and covering 6,000 and 5,000 MMBTU of natural gas per day for the calendar years 2021 and 2022, respectively. For 2021, contracts covering 4,500 of the 9,000 barrels of oil are in the form of costless collars of WTI Crude Oil prices. “Costless collars” are the combination of two options, a put option (floor) and a call option (ceiling) with the options structured so that the premium paid for the put option will be offset by the premium received from selling the call option. These collars have floors ranging from $40.00 to $45.00, with an averaged floor of $42.22 and have ceilings ranging between $52.71 and $55.35 per barrel, with an average ceiling of $54.57. The remaining 4,500 barrels of oil in 2021 and all of the 1,750 barrels of oil in 2022 are in the form of swaps of WTI Crude Oil prices. The oil swap prices for 2021 range from $45.00 to $45.96, with an average of $45.42. The oil swap prices for 2022 range from $44.22 to $45.98, with an average of $44.84. All of the contracts for natural gas for both 2021 and 2022 are in the form of swaps of Henry Hub. The swap prices for 2021 and 2022 are $2.991 and $2.7255, respectively. Our 2020 and 2021 derivative hedges resulted in total unrealized fair value loss of approximately $1.2 million during the twelve months ended December 31, 2020 and realized gain on derivates of approximately $22.5 million twelve months ended December 31, 2020. All of our hedges are financial hedges and do not have physical delivery requirements. As such, any decreases in anticipated production, whether as a result of decreased development activity or shut-ins, will not impact our ability to realize the benefits of the hedges.

Our supply chain has experienced some interruptions. In the second quarter of 2020, one of our purchasers cancelled its existing contracts to purchase produced oil from the Company. However, we have since entered into new contracts with an existing purchaser to purchase the oil previously covered by the cancelled contracts. In the second quarter of 2020, the industry overall experienced severe storage capacity constraints with respect to oil and certain natural gas products. Although such restraints have relaxed significantly, we may become subject to such constraints if we are not able to sell our production, or certain components of our production. The lack of a market or available storage for natural gas product or oil could result in us having to shut in production.

In addition, as previously announced, we reduced our drilling and completion capital budget for 2020 by approximately 70% since the beginning of the year. Reductions in the 2020 capital budget may impact production levels in 2021 and forward to the extent fewer wells are brought online.

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In May 2020, the Borrowing Base supporting our Credit Facility was subject to its semi-annual redetermination, which led to us entering into a second amendment to our Credit Facility on June 17, 2020. The amendment, among other things, reduces the Company’s Borrowing Base under the Credit Facility from $425 million to $375 million. The Company subsequently entered into a third amendment to our Credit Facility on December 23, 2020, subject to its semi-annual redetermination requirement. The amendment, among other things, reduced the Company’s Borrowing Base from $375 million to $350 million. During the fourth quarter, the Company paid down approximately $47 million in debt leaving approximately $313 million outstanding on our credit facility as of December 31, 2020.

The COVID-19 pandemic, commodity market volatility and resulting financial market instability are variables beyond our control that can adversely impact our ability to generate sufficient funds from operating activities, our available borrowings under our Credit Facility and our ability to access the capital markets. We believe we are taking appropriate steps in response to the evolving circumstances. However, past performance is not a promise of future events and the Company cannot estimate all aspects of the ongoing impact of the pandemic-related events and the OPEC+ production adjustments on the Company’s financial statements.

Market Conditions and Commodity Prices

Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future commodity prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our drilling program, production volumes or revenues.

The pandemic induced reduction in oil prices experienced in 2020 caused Ring, as well as other operators, to re-evaluate our original capital budget plans for 2020 that led to changes we believed were in the best interest of the Company and our stockholders. Although oil prices have recovered to pre-pandemic levels, we believe oil and natural gas prices may continue to be volatile. The ability to find and develop sufficient amounts of natural gas and crude oil reserves at economical costs are critical to our long-term success.

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Results of Operations

The following table sets forth selected operating data for the periods indicated:

For the Years Ended December 31, 

    

2020

    

2019

    

2018

Net production:

 

  

 

  

 

  

Oil (Bbls)

 

2,801,528

 

3,536,126

 

2,047,295

Natural gas (Mcf)

 

2,494,502

 

2,476,472

 

1,112,177

 

  

 

  

 

  

Net sales:

 

  

 

  

 

  

Oil

$

109,113,557

$

191,891,314

$

116,678,375

Natural gas

 

3,911,581

 

3,811,517

 

3,386,986

 

  

 

  

 

  

Average sales price:

 

  

 

  

 

  

Oil (per Bbl)

$

38.95

$

54.27

$

56.99

Natural gas (per Mcf)

 

1.57