Ring Energy (REI) 10-K 2019 FY Annual report

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, 2019

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)
901 West Wall St, 3rd Floor Midland, TX	79701
(Address of principal executive offices)	(Zip Code)
(432) 682-7464
(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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,”and “emerging growth 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 is shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ⌧

As of June 30, 2019, 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 $3.25 per share, was approximately $184,597,550.

As of March 16, 2020, the issuer had outstanding 67,993,797 shares of common stock ($0.001 par value).

TABLE OF CONTENTS

PART I
Item 1:	Business	3
Item 1A:	Risk Factors	9
Item 1B:	Unresolved Staff Comments	18
Item 2:	Properties	18
Item 3:	Legal Proceedings	28
Item 4:	Mine Safety Disclosures	28
PART II
Item 5:	Market for Registrant’s Common Equity, Related Stockholder Matters and Issued Purchases of Equity Securities	29
Item 6:	Selected Financial Data	30
Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 7A:	Quantitative and Qualitative Disclosures About Market Risk	39
Item 8:	Financial Statements and Supplementary Data	40
Item 9:	Changes in and Disagreement’s With Accountants on Accounting and Financial Disclosure	40
Item 9A:	Controls and Procedures	40
Item 9B:	Other Information	41
PART III
Item 10:	Directors, Executive Officers and Corporate Governance	42
Item 11:	Executive Compensation	46
Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	61
Item 13:	Certain Relationships and Related Transactions, and Director Independence	64
Item 14:	Principal Accounting Fees and Services	64
PART IV
Item 15:	Exhibits, Financial Statement Schedules	65

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Forward Looking Statements

All statements, other than statements of historical fact included in this Annual Report on Form 10-K (herein, “Annual Report”) regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. All forward-looking statements speak only as of the date of this Annual Report. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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

PART I

Item 1:     Business

General

We are a Midland-based exploration and production company that is engaged in oil and natural gas acquisition, exploration, development and production activities.  Our primary drilling operations target the Central Basin Platform, the Delaware Basin and the Northwest Shelf all of which are part of the Permian Basin in Texas and New Mexico.

We plan to continue to exploit our 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.   In 2019, we increased our acreage positions to 166,363 gross (122,396 net) acres with 97,956 gross (65,799 net) acres in the Central Basin Platform, 20,219 gross (19,998 net) acres in the Delaware Basin and 48,188 gross (36,599 net) on the Northwest Shelf.

As of December 31, 2019, Ring increased its proved reserves to approximately 81.1 million BOE (barrel of oil equivalent), all of which relate to its properties located in the Permian Basin in Texas and New Mexico.  For the calculation of BOE, oil is weighted on a 6 to 1 ratio against natural gas.  The Company’s proved reserves are oil-weighted with 88% of proved reserves consisting of oil and 12% consisting of natural gas. Of those reserves, 53% of the proved reserves are classified as proved developed producing, or “PDP,” 5% are classified as proved developed non-producing, or “PDNP,” and 42% are classified as proved undeveloped, or “PUD.”

A significant portion of the increase in 2019 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.

We plan to continue to focus on increasing our production through the development of existing properties, as well as the acquisitions of producing properties. Sales as a result of production for the year ended December 31, 2019, increased 77% to 3,948,871 BOE, as compared to sales of 2,232,658 BOE for the year ended December 31, 2018. The stated production amount reflects only the oil and natural gas that was produced and shipped prior to the end of the fourth quarter. Any oil and natural gas produced in the fourth quarter but still held on site after December 31, 2019, will be credited in the first quarter of 2020.

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Ring believes that there is significant value to be created by drilling the identified undeveloped opportunities on its Texas and New Mexico properties.

● Andrews and Gaines Counties, Texas – As of December 31, 2019, Ring owned interests in a total of 23,288 gross (18,372 net) developed acres and 74,669 gross (47,427 net) undeveloped acres in Andrews and Gaines Counties, Texas. In these counties, the Company has 40 identified proven vertical drilling locations and 29 identified proven horizontal locations based on the reserve reports as of December 31, 2019, and an additional 293 potential vertical drilling locations based on 10-acre downspacing and 667 potential horizontal drilling locations based on 6 wells per section or 106 acres per well.

● Culberson and Reeves Counties, Texas – As of December 31, 2019, Ring owned interests in a total of 19,323 gross (19,138 net) developed acres and 896 gross (860 net) undeveloped acres in Culberson and Reeves Counties, Texas. In these counties, the Company has 43 identified proven vertical drilling locations and 4 identified proven horizontal locations based on the reserve reports as of December 31, 2019 and an additional 154 potential horizontal drilling locations based on 6 wells per section or 106 acres per well.

● Gaines, Yoakum, Runnels and Coke Counties, Texas and Lea County, New Mexico –  As of December 31, 2019, Ring owned interests in a total of 11,723 gross (8,085 net) developed acres and 36,465 gross (28,514 net) undeveloped acres in Gaines, Yoakum, Runnels and Coke Counties, Texas and Lea County, New Mexico. In these counties, the Company has 69 identified proven horizontal drilling locations, 13 identified proven non-operated horizontal locations based on the reserve reports as of December 31, 2019 and an additional 76 potential vertical drilling locations based on 20-acre downspacing and 231 potential horizontal drilling locations based on 8 wells per section or 80 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 Business Strategy and Development

● Growing production and reserves by developing our oil-rich resource base through conventional and horizontal drilling. Ring intends to drill and develop its acreage base in an effort to maximize its value and resource potential, with a focus on the further drilling and development of its Northwest Shelf asset.  Ring plans to operate within its generated cash flow. Ring's preliminary 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 in 2020.  Due to the recent drop in the price of oil, Ring has re-evaluated its current capital expenditure budget for 2020 and is making changes that the Company believes are in the best interest of the Company and its stockholders, including ceasing any further drilling until oil prices stabilize. Of the 18 new wells, four were to be drilled in the first quarter of 2020. Those four new wells have been drilled, but as of now, the Company does not plan to drill further until it is comfortable that commodity pricing has stabilized.  Ring’s portfolio of proved oil and natural gas reserves consists of 88% oil and 12% natural gas. Of those reserves, 53% of the proved reserves are classified as proved developed producing, or “PDP,” 5% are classified as proved developed non-producing, or “PDNP,” and 42% are classified as proved undeveloped, or “PUD.” Ring plans to increase its production, reserves and cash flow while gaining favorable returns on invested capital through the conversion of undeveloped reserves to developed reserves.

Through December 31, 2019, we increased our proved reserves to approximately 81.1 million BOE (barrel of oil equivalent). As of December 31, 2019, our estimated proved reserves had a pre-tax “PV10” (present value of future net revenues before income taxes discounted at 10%) of approximately $1.1 billion and a Standardized Measure of Discounted Future Net Cash Flows of approximately $923.2 million. The difference between these two amounts is the effect of income taxes. 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.

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● Reduction of Long-Long Term Debt and De-Leveraging of Asset. ��Ring intends to reduce its long-term debt, either through the sale of non-core assets, the use of excess cash flow from operations, or a combination.  Ring incurred long-term indebtedness in connection with the acquisition of core assets from Wishbone Energy Partners, LLC and its related entities. The Company believes that with its market-leading completion margins, it is well positioned to maximize the value of its assets and plans to de-lever its balance sheet through strategic asset dispositions.  The Company is continuing to evaluate opportunities to strategically sell its non-core assets in transactions that maximize the Company’s return and provide the greatest upside to its stockholders.  In furtherance of this strategy, Ring is currently marketing its Delaware Basin assets.

● Employ industry leading drilling and completion techniques. Ring’s executive team intends to utilize new and innovative technological advancements and careful geological evaluation in reservoir engineering to generate value for its stockholders and to build development opportunities for years to come. Improved efficiency through employing technological advancements can provide a significant benefit in a continuous drilling program such as the one Ring contemplates for its current inventory of drilling locations.

● Pursue strategic acquisitions with exceptional upside potential. Ring has a history of acquiring leasehold positions that it believes to have substantial resource potential and to meet its targeted returns on invested capital. Ring has historically pursued acquisitions of properties that it believes to have exploitation and development potential comparable to its existing inventory of drilling locations. The Company has developed and refined an acquisition program designed to increase reserves and complement existing core properties. Ring’s experienced team of management and engineering professionals identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties. Management intends to continue to pursue strategic acquisitions that meet the Company’s operational and financial targets. The executive team, with its extensive experience in the Permian Basin, has many relationships with operators and service providers in the region. Ring believes that leveraging its relationships will be a competitive advantage in identifying acquisition targets. Management’s proven ability to evaluate resource potential will allow Ring to successfully acquire acreage and bring out more value in the assets.

Ring Energy’s Strengths

● High quality asset base in one of North America’s leading resource plays. Ring’s acreage is all located in the Permian Basin in Texas and New Mexico and includes acreage in the Northwest Shelf, Central Basin Platform and Delaware Basin. The Permian Basin is one of North America’s leading resource plays and has a significant production history.  As of December 31, 2019, Ring has drilled 309 wells on its Central Basin acreage (with 193 being vertical wells and 116 being horizontal wells), 15 wells on its Delaware Basin acreage (with 10 being vertical wells and 5 being horizontal wells) and 16 wells on the Northwest Shelf (all horizontal).  As of December 31, 2019, estimated net proved reserves were comprised of approximately 88% oil and 12% natural gas.

● De-risked Permian acreage position with multi-year drilling inventory. The Company considers a significant portion of its acreage to be de-risked, or having reduced risk and uncertainty associated therewith, as a result of the significant production history in the area and the well established activity surrounding the Company's acreage.  As of December 31, 2019, Ring has drilled 340 gross operated wells across its leasehold position with a 99.7% success rate. Ring has identified a multi-year inventory of potential drilling locations that the Company believes will drive reserves and production growth and provide attractive return opportunities. As of December 31, 2019, Ring has 40 identified proven vertical drilling locations and 29 identified proven horizontal locations on its Central Basin acreage, 43 identified proven vertical drilling locations and 4 identified proven horizontal locations on its Delaware Basin acreage and 57 identified proven horizontal drilling locations and 13 identified non-operated drilling locations.  Additionally, Ring believes there are an additional 426 potential vertical drilling locations based on 20-acre downspacing and an additional 154 potential horizontal drilling locations based on 6 wells per section or 106 acres per well in the Central Basin, an additional 43 potential vertical drilling locations based on 20-acre downspacing and 96 potential horizontal drilling locations based on 8 wells per section of 80 acres per well in the Delaware Basin and 33 potential vertical drilling locations based on 20-acre downspacing and an additional 135 potential horizontal drilling locations based on 8 wells per section or 80 acres per well  on the Northwest Shelf.

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● Experienced and proven management team focused on the Permian Basin. The executive team has an average of approximately 25 years of industry experience per person, most of which has been focused in the Permian Basin. The Company believes its management and technical team is one of the Company’s principal competitive strengths due to the team’s proven ability to identify and integrate acquisitions, focus on cost efficiencies while managing a large-scale development program and disciplined allocation of capital to high-returning projects. Ring’s Chief Executive Officer, Kelly Hoffman, has had a successful career in the Permian Basin since 1975 when he started with Amoco Production Company and found further success in West Texas when he co-founded AOCO. In addition, Chairman of the Board, Lloyd T. Rochford, and Director, Stanley M. McCabe, formed Arena Resources, Inc. (“Arena”) in 2001, which operated in the same proximate area as Ring’s Andrews and Gaines County acreage. Arena eventually sold to SandRidge Energy, Inc., in July 2010 for $1.6 billion. Ring’s management team aims to execute a similar growth strategy and development plan by leveraging its industry relationships and significant operational experience in these regions.

● Concentrated acreage position with high degree of operational control. Ring has a highly contiguous acreage position and operates the vast majority of its acreage. The operating control allows Ring to implement and benefit from its strategy of enhancing returns through operational and cost efficiencies. Additionally, as the operator of substantially all of its acreage, Ring retains the ability to adjust its capital expenditures based on well performance and commodity price forecasts.

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 all of our current production at current prices with a reasonable profit margin. The risk of domestic overproduction at current prices is not deemed significant. 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.

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For the fiscal year ended December 31, 2019, sales to three customers, Phillips 66 (“Phillips”), Occidental Energy Marketing (“Oxy”) and NGL Crude Partners (“NGL Crude”) represented 42%, 36% and 7%, respectively, of our oil and natural gas revenues. At December 31, 2019, Phillips represented 47% of our accounts receivable, Oxy represented 31% of our accounts receivable and NGL Crude represented 9% 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, 2019, 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.

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. Currently, all of our properties and operations are in Texas and New Mexico 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.

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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 contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

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

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors.

Environmental Compliance and Risks

Our oil and natural gas exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Historically, most of the environmental regulation of oil and gas production has been left to state regulatory boards or agencies in those jurisdictions where there is significant oil and gas production, with limited direct regulation by such federal agencies as the Environmental Protection Agency (“EPA”). However, while we believe this generally to be the case for our production activities, there are various regulations issued by the EPA and other governmental agencies that would govern significant spills, blow-outs, or uncontrolled emissions.

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.

At the federal level, among the more significant laws and regulations that may affect our business and the oil and natural gas industry are: The Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as “CERCLA” or “Superfund; the Oil Pollution Act of 1990; the Resource Conservation and Recovery Act, also known as “RCRA,”; the Clean Air Act; Federal Water Pollution Control Act of 1972, or the Clean Water Act; and the Safe Drinking Water Act of 1974.

Compliance with these regulations 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.

In the event of a violation of environmental regulations, these environmental regulatory agencies have a broad range of alternative or cumulative remedies which include: ordering a clean-up of any spills or waste material and restoration of the soil or water to conditions existing prior to the environmental violation; fines; or enjoining further drilling, completion or production activities. In certain egregious situations the agencies may also pursue criminal remedies against us or our principal officers.

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Operational Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations and could incur costs in connection therewith.

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.

Current Employees

As of December 31, 2019, we had fifty eight (58) full-time employees. Our employees are not represented by any labor union. We consider our relations with our employees to be satisfactory and have never experienced a work stoppage or strike.

We also retain certain engineers, geologists, landmen, pumpers and other personnel on a contract or fee basis as necessary for our operations.

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.

Principal Executive Office

Our principal executive offices are located at 901 West Wall St., 3^rd Floor, Midland, TX 79701, and our telephone number is (432) 682-7464.

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 or furnished 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 the Oil and Natural Gas Industry and Our Business

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

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

● 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 unit 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.

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

Because a substantial percentage of our proven properties are proved undeveloped (approximately 42%) or proved developed non-producing (approximately 5%), we will require significant additional capital to develop such properties before they may become productive. Further, because of the inherent uncertainties associated with drilling for oil and gas, some of these properties may never be developed to the extent that they result in positive cash flow. Even if we are successful in our development efforts, it could take several years for a significant portion of our undeveloped properties to be converted to positive cash flow.

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

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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. 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.

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 more conventional wells;

● 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 recently purchased properties are materially inaccurate, it could have a significant impact on future operations and earnings.

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

● 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.

11

Decreases in oil and natural gas prices may require us to take write-downs of the carrying values of our oil and natural gas properties, potentially requiring earlier than anticipated debt repayment and negatively impacting 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. Because our properties serve as collateral for advances under our credit facility, a write-down in the carrying values of our properties could require us to repay any outstanding debt earlier than we would otherwise be required. A write-down could 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. In 2018, the Company recorded a non-cash write-down of its proved oil and natural gas properties of approximately $14.2 million. The Company did not have any write-downs for the year-ended December 31, 2019.

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 expense. We did not record a write down during 2019. During the year ended December 31, 2018, we recorded a non-cash write down of $14.2 million.  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.

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, 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.

12

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 (42%) 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.

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.

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

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

13

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.

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

We have a credit facility in place with $425 million in commitments for borrowings and letters of credit. As of December 31, 2019, $366.5 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 quarterly 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.

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.

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.

14

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.

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. 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, when the cash benefit from hedges including a sold put is limited to the extent oil prices fall below the price of our sold puts, or when the counterparty to the derivative contract is financially constrained and defaults on its contractual obligations.  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, 2019, the Company has in place derivative contracts covering 5,500 barrels of oil per day for the period of January 2020 through December 2020.  All of the derivative contracts 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.  Our collars as of December 31, 2019 all had a floor of $50 per barrel and had ceilings ranging between $58.25 and $65.83 per barrel, with an average ceiling of $61.06.

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.

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.

15

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.

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. Clean Air Act.

The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business.

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 emanating from China 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 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.

16

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 plans to pay dividends on our common stock.

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to 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 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 causes shares of preferred stock to be issued, the rights of the holders of our common stock could be adversely affected. The board’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 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 stock holders 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.

17

The restatement of our interim unaudited consolidated financial statements could have a negative impact on our stock price.

As discussed elsewhere in this annual report, we are restating the interim unaudited consolidated financial statements included in our Quarterly Reports on Forms 10-Q for the periods ended March 31, 2019, June 30, 2019, and September 30, 2019 due to errors relating to our calculation of benefit/provision for income tax relating to outstanding unexercised equity awards. The review of our prior period calculations and the preparation of our restated financial statements has caused us to incur additional expenses for legal, accounting, tax and other professional services. The restatements could cause investors to lose confidence in our operating results and the price of our common stock could decline.

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, 2019, we owned interests in a total of 54,334 gross (45,594 net) developed acres and operate the vast majority of our acreage position. In addition, as of December 31, 2019, we owned interests in approximately 112,029 gross (76,801 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.

Summary of Oil and Natural Gas Properties and Projects

Significant Operations

Northwest Shelf – Gaines, 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, 2019, our acreage position in these counties is 48,188 gross (36,599 net) acres with 11,723 gross (8,085 net) developed and held by production and 36,465 gross (28,514 net) being undeveloped.  We believe the Northwest Shelf leases contain a considerable number of remaining potential drilling locations.  Our reserve estimates include 69 proved horizontal and 13 non-operated horizontal PUD wells.  Our reserve estimates include the capital costs required to develop these wells.

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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, 2019, we own 97,956 gross (65,799 net), acres with 23,288 gross  (18,372 net) acres developed and held by production and the remaining 74,669 gross (47,427 net) acres being undeveloped. We believe the Central Basin Platform leases contain a considerable number of remaining potential drilling locations.  Our reserve estimates include 40 proven vertical and 29 horizontal PUD wells.  Our reserve estimates include the capital costs required to develop these wells.

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, 2019, we own 20,219 gross (19,998 net) acres with 19,323 gross (19,138 net) acres developed and held by production and the remaining 896 gross (860 net) acres being undeveloped.  We believe the Delaware Basin leases contain a considerable number of remaining potential drilling locations.  Our reserve estimates include 43 proved vertical and 4 horizontal PUD wells.  Our reserve estimates include the capital costs required to develop these wells.

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, 2019, our estimated proved reserves had a pre-tax PV10 value of approximately $6 million and a Standardized Measure of Discounted Future Cash Flows of approximately $455.9 million, 100% of which relates to our properties in the Permian Basin in Texas and New Mexico. We spent approximately $624.4 million on acquisitions and capital projects during 2018 and 2019. We expect to further develop these properties through additional drilling.

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, 2019.  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
71,359,014	58,271,882	81,070,994	$	1,102,795,800	$	923,175,051

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.

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Reserve Quantity Information

Our estimates of proved reserves and related valuations are based on internally prepared reports and audited by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

Our oil and natural gas 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, 2017	28,943,742	18,037,489
Purchase of minerals in place	2,582,718	1,332,439
Improved recovery	1,142,222	4,197,487
Extensions and discoveries	7,425,387	32,867,798
Production	(2,047,295)	(1,112,177)
Upward revisions of estimates	193,531	93,562
Downward revision of estimates due to well performance	(1,145,110)	(477,732)
Downward revision of estimates due to commodity prices	(1,498,282)	(1,636,515)
Downward revision of estimates due to removal of undeveloped locations	(492,388)	(209,168)
Downward revision of estimates due to removal of waterflood reserves	(7,294,777)	(327,485)
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

Our proved oil and natural gas reserves are shown below.

	For the Years Ended December 31,
	2018	2019
Oil (Bbls)
Developed	19,206,048	41,242,064
Undeveloped	8,603,700	30,116,950
Total	27,809,748	71,359,014
Natural Gas (Mcf)
Developed	32,413,447	34,467,868
Undeveloped	20,352,251	23,804,014
Total	52,765,698	58,271,882
Total (Boe)
Developed	24,608,289	46,986,709
Undeveloped	11,995,742	34,084,285
Total	36,604,031	81,070,994

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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 or the present value of our oil and natural gas properties.

Our reserve estimates as of December 31, 2019 are based on an average price of $52.41 for oil and $1.47 for natural gas compared to $58.74 for oil and $3.26 for natural gas as of December 31, 2018.

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 Cash Flows
December 31,	2019		2018
Future cash flows	$	3,825,773,515	$	1,805,419,612
Future production costs		(964,887,856)		(594,609,134)
Future development costs		(252,457,833)		(94,973,603)
Future income taxes		(424,715,966)		(176,430,782)
Future net cash flows		2,183,711,860		939,406,093
10% annual discount for estimated timing of cash flows		(1,260,536,809)		(483,461,452)
Standardized Measure of Discounted Cash Flows	$	923,175,051	$	455,944,641

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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.

	2019		2018
Beginning of the year	$	455,944,641	$	322,465,119
Purchase of minerals in place		598,489,190		50,094,951
Improved recovery, less related costs		86,989,301		145,717,969
Extensions and discoveries, less related costs		247,652,632		22,365,230
Development costs incurred during the year		152,125,320		198,870,366
Sales of oil and gas produced, net of production costs		(137,663,314)		(92,263,372)
Sales of minerals in place		(30,174,528)		—
Accretion of discount		47,463,292		38,426,781
Net changes in price and production costs		(219,608,128)		178,396,156
Net change in estimated future development costs		47,617,158		(56,282,127)
Upward revisions		44,034,636		4,975,263
Revision of previous quantity estimates as a result well performance		(64,553,979)		(39,785,033)
Revision of previous quantity estimates as a result of commodity prices		(71,545,320)		(29,332,880)
Revision of previous quantity estimates as a result removal of uneconomic proved undeveloped locations		(34,079,006)		(17,681,142)
Revision of previous quantity estimates as a result removal of proved undeveloped locations due to changes in previously adopted development plans		—		(178,024,754)
Revision of estimated timing of cash flows		(107,443,484)		(66,002,740)
Net change in income taxes		(92,073,360)		(25,995,146)
End of the Year	$	923,175,051	$	455,944,641

Our proved reserves by state as of December 31, 2019 are summarized in the table below.

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Proved Reserves

								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
PDP	35,806,130	29,690,630	40,754,568	50	%	$	622,346	$	520,980	$	—
PDNP	2,983,310	2,542,890	3,407,125	4	%		56,021		46,896		7,460
PUD	29,009,704	22,868,372	32,821,099	41	%		372,095		311,489		234,348
Total Proved:	67,799,144	55,101,892	76,982,792	95	%	$	1,050,462	$	879,365	$	241,808
New Mexico
PDP	2,035,180	1,812,960	2,337,340	3	%	$	28,605	$	23,946	$	—
PDNP	417,430	421,390	487,662	1	%		6,739		5,641		80
PUD	1,107,260	935,640	1,263,200	2	%		16,990		14,223		10,570
Total Proved:	3,559,870	3,169,990	4,088,202	5	%	$	52,334	$	43,810	$	10,650
Total
PDP	37,841,310	31,503,590	43,091,908	53	%	$	650,951	$	544,926	$	—
PDNP	3,400,740	2,964,280	3,894,787	5	%		62,760		52,537		7,540
PUD	30,116,964	23,804,012	34,084,299	42	%		389,085		325,712		244,918
Total Proved:	71,359,014	58,271,882	81,070,994	100	%	$	1,102,796	$	923,175	$	252,458

We have approximately 81.1 million BOE of proved reserves, consisting of approximately 88% oil and 12% natural gas, as  summarized in the table above as of December 31, 2019, 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, 2019, approximately 53% of the proved reserves have been classified as proved developed producing, or “PDP”. Proved developed non-producing, or “PDNP” reserves constitute approximately 5% and proved undeveloped, or “PUD”, reserves constitute approximately 42%, of the proved reserves.

As of December 31, 2019, our total proved reserves had a net pre-tax PV10 value of approximately $1.1 billion and a Standardized Measure of Discounted Future Net Cash Flows of approximately $923.2 million.  Approximately $651.0 million and $544.9 million, respectively, of total proved reserves are associated with the PDP reserves, which is approximately 59% of the total proved reserves’ pre-tax PV10 value.  An additional $62.8 million and $52.5 million, respectively, are associated with the PDNP reserves, which is approximately 6% of total proved reserves’ pre-tax PV10 value. The remaining $389.1 million and $325.7 million, respectively, are associated with PUD reserves.

Proved Undeveloped Reserves

Our reserve estimates as of December 31, 2019 include approximately 35.1 million BOE as proved undeveloped reserves. As of December 31, 2018, our reserve estimates included approximately 12.0 million BOE as proved undeveloped reserves. Below is a description of the changes in our PUD reserves from December 31, 2018 to December 31, 2019.

During the year ended December 31, 2019, we incurred costs of approximately $33.9 million to convert 6,046,028 BOE of reserves from PUD to PDP through development.

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Other changes to our PUD reserves included:

● Purchase of minerals in place of 28,427,806 BOE, primarily from the Wishbone Acquisition;

● Sale of minerals in place of 709,208 BOE by selling a non-operated interest in wells and acreage acquired in the Wishbone Acquisition;

● Extensions and discoveries of 5,394,118 BOE;

● Upward revisions of 1,769,661 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 2,794,713 BOE as the result of well performance due to reduction of offsetting production;

● Downward revisions of 1,506,746 BOE as the result of changes in commodity prices; and

● Downward revision of 2,446,347 BOE for the removal of locations due to lack of development within the prescribed time frame as the result of changes in our development plan following the Wishbone Acquisition and the removal of locations added as part of the Wishbone Acquisition that were removed because the offsetting justification was inactive and had been reduced to a PDNP category.

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

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

	Estimated Oil	Estimated Gas
	Reserves	Reserves			Estimated
Year	Developed (Bbls)	Developed (Mcf)		Total Boe	Development Costs
2020	14,086,447	13,336,496		16,309,196	$	92,826,207
2021	14,732,192	9,776,618		16,361,628		123,732,172
2022	3,434,194	2,499,976		3,850,857		20,458,807
2023	675,102	589,944		773,426		7,110,664
2024	352,808	254,261		395,185		4,830,000
2025	236,961	310,997		288,794		3,500,000
			��
	33,517,704	26,768,292		37,979,086	$	252,457,850

Internal Controls Over Reserves Estimates

All of our proved reserves estimates shown in this Annual Report on Form 10-K at December 31, 2019, have been independently prepared by 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 forth in the CGA letter dated January 30, 2020, 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.

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The Company provides its third party independent consultants, including CGA, with full access to complete and accurate information pertaining to the property, and to all applicable personnel of the Company. Our reserves estimates and process for developing such estimates are reviewed and approved by our Vice President of Operations, Daniel D. Wilson, a petroleum engineer, and our Chief Executive Officer, Kelly Hoffman, to ensure compliance with SEC disclosure and internal control requirements and to verify the independence of the third party consultants. Mr. Wilson, a petroleum engineer and businessman, has over 30 years of experience in operating, evaluating and exploiting oil and natural gas properties. Mr. Hoffman has over 40 years of well-rounded experience in the oil and natural gas industry. Our management is ultimately responsible for reserve estimates and reserve disclosures and ensuring that they are in accordance with the applicable regulatory requirements and industry standards and practices.

Estimates of oil and natural gas reserves are projections based on a process involving an independent third party engineering firm’s collection of all required geologic, geophysical, engineering and economic data, and such firm’s complete external preparation of all required estimates and are forward-looking in nature. These reports rely upon various assumptions, including assumptions required by the SEC, such as constant oil and natural gas prices, operating expenses and future capital costs. The process also requires assumptions relating to availability of funds and timing of capital expenditures for development of our proved undeveloped reserves. These reports should not be construed as the current market value of our reserves. The process of estimating oil and natural gas reserves is also dependent on geological, engineering and economic data for each reservoir. Because of the uncertainties inherent in the interpretation of this data, we cannot be certain that the reserves will ultimately be realized and our actual results could differ materially.

Summary of Oil and Natural Gas Properties and Projects

Production Summary

Our estimated average daily production for the month of December 2019 is summarized below. The following table indicates the percentage of our estimated December 2019 average daily production of 11,498 BOE/d attributable to oil versus natural gas production.

			Natural
	Oil		Gas
Texas	85.43	%	10.88	%
New Mexico	3.26	%	0.42	%
Total	88.70	%	11.30	%

Acreage

The following table summarizes gross and net developed and undeveloped acreage at December 31, 2019 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	23,288	18,372	74,669	47,427	97,956	65,799
Delaware Basin	19,323	19,138	896	860	20,219	19,998
Northwest Shelf	11,723	8,085	36,465	28,514	48,188	36,599
Total	54,334	45,594	112,029	76,801	166,363	122,396

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.

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The following table sets forth the gross and net undeveloped acreage, as of December 31, 2019, 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:

	2020		2021		2022
	Gross	Net	Gross	Net	Gross	Net
Undeveloped acreage	67,308	47,785	19,350	13,252	6,409	2,259

Production History

The following table presents the historical information about our produced natural gas and oil volumes for the years ended December 31, 2017, 2018 and 2019:

	Years Ended December 31,
	2017	2018	2019
Oil (Bbls)
Central Basin Platform	1,037,868	1,812,616	1,579,296
Delaware Basin	272,653	234,679	275,080
Northwest Shelf	—	—	1,681,750
Total	1,310,521	2,047,295	3,536,126
Gas (Mcf)
Central Basin Platform	128,160	346,115	315,117
Delaware Basin	626,928	766,062	939,437
Northwest Shelf	—	—	1,221,918
Total	755,088	1,112,177	2,476,472
Total production (BOE)
Central Basin Platform	1,059,228	1,870,302	1,631,816
Delaware Basin	377,141	362,356	431,653
Northwest Shelf	—	—	1,885,403
Total	1,436,369	2,232,658	3,948,871
Daily production (Boe/d)
Central Basin Platform	2,902	5,124	4,471
Delaware Basin	1,033	993	1,183
Northwest Shelf	—	—	5,165
Total	3,935	6,117	10,819

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Production Prices and Production Costs

The following tables provides historical pricing and costs statistics for the years ended December 31, 2017, 2018 and 2019.

	Years Ended December 31,
	2017		2018		2019
Average sales price:
Oil (per Bbl)	$	48.97	$	56.99	$	54.27
Natural gas (per Mcf)		3.23		3.23		1.54
Total (per Boe)		46.36		53.78		49.56
Average production cost (per Boe)	$	11.11	$	12.45	$	12.28
Average production taxes (per Boe)		2.19		2.52		2.31

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.

Productive Wells

The following table presents our ownership at December 31, 2019, 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
627	526	—	—	627	526

Drilling Activity

During 2019, we drilled 30 gross (29.33 net) wells in the Central Basin Platform, Delaware Basin and Northwest Shelf in the Permian Basin.  We completed and placed on production all 30 of these wells.  All of these wells were successful and there were no dry wells.

The table below contains information regarding the number of wells completed during the periods indicated.  Each of these wells was drilled in the Permian Basin, on the Northwest Shelf, Central Basin Platform or Delaware Basin.

	For the year ended December 31,
	2019		2018		2017
	Gross	Net	Gross	Net	Gross	Net
Exploratory
Productive	—	—	—	—	—	—
Dry	—	—	—	—	3.00	3.00
Development
Productive	30.00	29.33	57.00	56.25	47.00	45.59
Dry					—	—
Total
Productive	30.00	29.33	57.00	56.25	47.00	45.59
Dry	—	—	—	—	3.00	3.00

(1) All of the wells drilled by the Company to date, with the exception of those wells included in the row for exploratory dry wells in the table above, have been development wells. The Company considers the exploratory dry wells to be “science wells”. “Science well” is a term used in the industry to describe a well that is drilled for purposes of determining the stratigraphic composition of a particular area, and is not intended to be completed to produce any oil or natural gas. Since these exploratory wells have not been completed for production, we have designated them as dry wells.

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Present Activities

There were no wells in the process of being drilled or awaiting completion as of December 31, 2019.

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 $11.11, $12.45 and $12.28 during the years ended December 31, 2017, 2018 and 2019, respectively, and our average production taxes, per BOE, were $2.19, $2.52 and $2.31 for the years ended December 31, 2017, 2018 and 2019, respectively. These amounts are calculated by dividing our total production costs or total production taxes by our total volume sold, in BOE.

Costs incurred for property acquisition, exploration and development activities during the years ended December 31, 2018 and 2019 are shown below:

	2018		2019
Wishbone Acquisition (1)	$	—	$	304,392,921
Acquisition of proved properties (2)		15,860,742		3,400,411
Divestiture of proved properties		—		(8,547,074)
Acquisition of unproved properties		—		—
Exploration costs		—		—
Development costs		198,870,366		152,125,320
Total Costs Incurred	$	214,731,108	$	451,371,578

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

(2) Acquisition of proved properties in 2018 includes $11.2 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 Midland, Texas. The leased office space consists of approximately 15,000 square feet. Additionally, we lease office space in Tulsa, Oklahoma which serves as our primary accounting office and consists of approximately 3,700 square feet. We also lease office space in Andrews, Texas for a field office consisting of approximately 2,000 square feet. 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.” We have only one class of common stock. We also have 50,000,000 authorized but unissued shares of preferred stock.

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, 2014, and reinvestment of dividends on the date of payment without commission. This table is not intended to forecast future performance of our common stock.

* The peer group consists of: Callon Petroleum Company, Lilis Energy, Inc., Earthstone Energy, Inc., Laredo Petroleum, Inc. and Northern Oil and Gas, Inc., 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 Securities Exchange Act of 1934 and will not be incorporated by reference into any registration filed under the Securities Act of 1933 unless specifically identified therein as being incorporated by reference. The performance graph is not solicitation material subject to Regulation 14A.

Record Holders

As of February 25, 2020, there are approximately 9,102 holders of record of our common stock.

Dividend Policy

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to 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 results of operations, financial condition, capital requirements and investment opportunities. In addition, our 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, 2019.

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, 2019, 2018, 2017, 2016 and 2015. 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,
	2019		2018		2017		2016		2015
Statement of Operations Data:
Revenues	$	195,702,831	$	120,065,361	$	66,699,700	$	30,850,248	$	31,013,892
Cost of revenues		57,626,604		33,433,082		19,130,924		11,372,420		11,426,453
Depreciation, depletion and amortization		56,204,269		39,024,886		20,517,780		11,483,314		15,175,791
Ceiling test impairment		—		14,172,309		—		56,513,016		9,312,203
Accretion		943,707		606,459		567,968		487,182		418,384
Operating lease expense		925,217		—		—		—		—
General and administrative		19,866,706		12,867,686		10,515,887		8,027,077		7,995,395
Net income (loss)		29,496,551		8,999,760		1,753,869		(37,637,687)		(9,052,771)
Basic income (loss) per common share	$	0.44	$	0.15	$	0.03	$	(0.97)	$	(0.32)
Diluted income (loss) per common share	$	0.44	$	0.15	$	0.03	$	(0.97)	$	(0.32)

	As of December 31,
	2019		2018		2017		2016		2015
Balance Sheet Data:
Current assets	$	38,708,541	$	16,844,257	$	29,123,924	$	75,220,915	$	8,714,491
Oil and gas properties subject to amortization		1,083,966,135		641,121,398		433,591,134		250,133,965		269,590,374
Total assets		973,006,148		567,065,659		414,102,486		307,597,399		250,866,245
Total current liabilities		59,092,554		51,910,432		48,443,449		9,099,391		11,333,167
Total long-term liabilities		390,403,661		52,555,797		9,055,697		7,957,035		53,301,950
Total Stockholders Equity		523,509,933		462,599,430		356,603,340		290,540,973		186,231,128

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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 a Midland-based exploration and production company 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

Ring is currently engaged in oil and natural gas acquisition, exploration, development and production in Texas and New Mexico. We focus on developing our existing properties, while continuing to pursue acquisitions of oil and gas properties with upside potential.

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. Specifically, our business strategy is to increase our stockholders’ value through the following:

● Growing production and reserves by developing our oil-rich resource base through conventional and horizontal drilling. Ring intends to drill and develop its acreage base in an effort to maximize its value and resource potential, with a focus on the further drilling and development of its Northwest Shelf asset.  Ring plans to operate within its generated cash flow. Ring's preliminary plan 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 in 2020. Due to the recent drop in the price of oil, Ring has re-evaluated its current capital expenditure budget for 2020 and is making changes that the Company believes are in the best interest of the Company and its stockholders, including ceasing any further drilling until oil prices stabilize. Of the 18 new wells, four were to be drilled in the first quarter of 2020. Those four new wells have been drilled, but as of now, the Company does not plan to drill further until it is comfortable that commodity pricing has stabilized.  Ring’s portfolio of proved oil and natural gas reserves consists of 88% oil and 12% natural gas. Of those reserves, 53% of the proved reserves are classified as proved developed producing, or “PDP,” 5% are classified as proved developed non-producing, or “PDNP,” and 42% are classified as proved undeveloped, or “PUD.” Ring plans to increase its production, reserves and cash flow while gaining favorable returns on invested capital through the conversion of undeveloped reserves to developed reserves.

Through December 31, 2019, we increased our proved reserves to approximately 81.1 million BOE (barrel of oil equivalent). As of December 31, 2019, our estimated proved reserves had a pre-tax “PV10” (present value of future net revenues before income taxes discounted at 10%) of approximately $1.1 billion and a Standardized Measure of Discounted Future Net Cash Flows of approximately $923.2 million. The difference between these two amounts is the effect of income taxes. 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.

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● Reduction of Long-Long Term Debt and De-Leveraging of Asset. Ring intends to reduce its long-term debt, either through the sale of non-core assets, the use of excess cash flow from operations, or a combination.  Ring incurred long-term indebtedness in connection with the acquisition of core assets from Wishbone Energy Partners, LLC and its related entities. The Company believes that with its market-leading completion margins, it is well positioned to maximize the value of its assets and plans to de-lever its balance sheet through strategic asset dispositions.  The Company is continuing to evaluate opportunities to strategically sell its non-core assets in transactions that maximize the Company’s return and provide the greatest upside to its stockholders.  In furtherance of this strategy, Ring is currently marketing its Delaware Basin assets.

● Employ industry leading drilling and completion techniques. Ring’s executive team intends to utilize new and innovative technological advancements and careful geological evaluation in reservoir engineering to generate value for its stockholders and to build development opportunities for years to come. Improved efficiency through employing technological advancements can provide a significant benefit in a continuous drilling program such as the one Ring contemplates for its current inventory of drilling locations.

● Pursue strategic acquisitions with exceptional upside potential. Ring has a history of acquiring leasehold positions that it believes to have substantial resource potential and to meet its targeted returns on invested capital. Ring has historically pursued acquisitions of properties that it believes to have exploitation and development potential comparable to its existing inventory of drilling locations. The Company has developed and refined an acquisition program designed to increase reserves and complement existing core properties. Ring’s experienced team of management and engineering professionals identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties. Management intends to continue to pursue strategic acquisitions that meet the Company’s operational and financial targets. The executive team, with its extensive experience in the Permian Basin, has many relationships with operators and service providers in the region. Ring believes that leveraging its relationships will be a competitive advantage in identifying acquisition targets. Management’s proven ability to evaluate resource potential will allow Ring to successfully acquire acreage and bring out more value in the assets.

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 recent drop in the price of oil has forced us, as well as other operators, to re-evaluate our current capital expenditure budget for 2020 and make changes that we believe are in the best interest of the Company and our stockholders. Our preliminary capital expenditure budget for 2020 included the drilling of 18 new horizontal wells on our Northwest Shelf asset. Of the 18 new wells, four were to be drilled in the first quarter of 2020. Those four new wells have been drilled, but as of now, the Company has ceased new drilling until the Company is comfortable that oil commodity pricing has stabilized. We expect oil and natural gas to remain 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,	2017		2018		2019
Net production:
Oil (Bbls)		1,311,727		2,047,295		3,536,126
Natural gas (Mcf)		761,517		1,112,177		2,476,472
Net sales:
Oil	$	64,236,490	$	116,678,375	$	191,891,314
Natural gas		2,463,210		3,386,986		3,811,517
Average sales price:
Oil (per Bbl)	$	48.97	$	56.99	$	54.27
Natural gas (per Mcf)		3.23		3.05		1.54
Production costs and expenses
Oil and gas production costs	$	15,978,362	$	27,801,989	$	48,496,225
Production taxes		3,152,562		5,631,093		9,130,379
Depreciation, depletion and amortization expense		20,517,780		39,024,886		56,204,269
Ceiling test impairment		—		14,172,309		—
Realized loss on derivatives		119,897		11,153,702		—
Accretion expense		567,968		606,459		943,707
Operating lease expense		—		—		925,217
General and administrative expenses		10,515,887		12,867,686		19,866,706

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

Oil and natural gas sales. Oil and natural gas sales revenue increased approximately $75.6 million to $195.7 million in 2019. Oil sales increased approximately $75.2 million while natural gas sales increased approximately $0.4 million. The oil sales increase was primarily the result of an increase in sales volume from 2,047,295 barrels of oil in 2018 to 3,536,126 barrels of oil in 2019, partially offset by a decrease in the average realized per barrel oil price from $56.99 in 2018 to $54.27 in 2019. These per barrel amounts are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels.

Natural gas sales volume increased from 1,112,177 Mcf in 2018 to 2,476,472 Mcf in 2019 and the average realized per Mcf gas price decreased from $3.05 in 2018 to $1.54 in 2019. These per Mcf amounts are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf. The volume increases are the result of our ongoing development of existing properties.

Oil and natural gas sales volumes increased primarily as a result of the acquisition of the Northwest Shelf assets. Of our 3,536,126 barrels of oil produced in 2019, 1,893,888 barrels came from the Northwest Shelf properties and of our 2,476,472 Mcf of natural gas produced in 2019, 1,892,438 Mcf came from the Northwest Shelf properties.

Oil and natural gas production costs. Our aggregate oil and natural gas production costs increased from $27,801,989 in 2018 to $48,496,225 in 2019 and decreased on a BOE basis from $12.45 in 2018 to $12.28 in 2019. These per BOE amounts are calculated by dividing our total production costs by our total volume sold, in BOE. The increase in total production costs is primarily a result of the acquisition of the Northwest Shelf assets. The decrease in production costs per BOE is primarily the result increased production volumes from the Northwest Shelf assets.

Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.69% during 2018 and decreased to 4.67% in 2019.  Production taxes vary from state to state. Therefore, these taxes are likely to vary in the future depending on the mix of production we generate from various states, and on the possibility that any state may raise its production tax.

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Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased by $17,179,383 to $56,204,269 in 2019. The increase was primarily the result of increased production volumes but was partially offset by a decrease in our average depreciation, depletion and amortization rate from $17.54 per BOE during 2018 to $14.23 per BOE during 2019.  These per BOE amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total volume sold, in BOE. The reduction in our depletion rate per BOE is primarily the result of added reserves from the acquisition of the Northwest Shelf assets.

Ceiling Test Write-Down.     The Company did not have any write-downs for the period ended December 31, 2019.  The Company recorded a non-cash write-down of the carrying value of its proved oil and natural gas properties of $14,172,309 for the year ended December 31, 2018 as a result of ceiling test limitations, which is reflected as ceiling test impairments in the accompanying Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2018, adjusted for market differentials, per SEC guidelines. The write-down reduced earnings in the period and is expected to result in a lower depreciation, depletion and amortization rate in future periods.

General and administrative expenses. General and administrative expenses increased from $12,867,686 in 2018 to $19,866,706 in 2019.  The increase was primarily related to acquisition related expenses, amortization of deferred financing costs and compensation related expenses.

Interest income. Interest income was $13,511 in 2019 as compared to $97,855 in 2018. The decrease was the result of lower average cash on hand during 2019.

Interest expense. Interest expense was $13,865,556 in 2019 as compared to $427,898 in 2018. The increase was the result of having larger amounts outstanding on our credit facility during 2019.

Provision for income taxes. The provision for income taxes increased from $3,445,721 for 2018 to $13,787,654 for 2019.  The increase was the result of higher income before income taxes and also as a result of a $3,965,000 excess tax expense related to share based compensation.

Net income. The Company had net income of $29,496,551 in 2019 as compared to $8,999,760 in 2018. The increase in net income primarily resulted from increased revenues, which was largely the result of the Northwest Shelf acquisition, and not having a ceiling test write down in 2019 partially offset by higher interest and income tax expense.

Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

Oil and natural gas sales. Oil and natural gas sales revenue increased approximately $53.4 million to $120.1 million in 2018. Oil sales increased approximately $52.4 million while natural gas sales increased approximately $0.9 million. The oil sales increase was the result of an increase in sales volume from 1,311,727 barrels of oil in 2017 to 2,047,295 barrels of oil in 2018 and an increase in the average realized per barrel oil price from $48.97 in 2017 to $56.99 in 2018. These per barrel amounts are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels. Natural gas sales volume increased from 761,517 Mcf in 2017 to 1,112,177 Mcf in 2018 and the average realized per Mcf gas price decreased from $3.23 in 2017 to $3.05 in 2018. These per Mcf amounts are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf. The volume increases are the result of our ongoing development of existing properties.

Oil and natural gas production costs. Our aggregate oil and natural gas production costs increased from $15,978,362 in 2017 to $27,801,989 in 2018 and increased on a BOE basis from $11.11 in 2017 to $12.45 in 2018. These per BOE amounts are calculated by dividing our total production costs by our total volume sold, in BOE. The increase in production costs and the cost per BOE is primarily the result of higher electrical costs and to a lesser degree chemical costs, partially offset by increased production volumes.

Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.73% during 2017 and decreased to 4.69% in 2018. Production taxes vary from state to state. Therefore, these taxes are likely to vary in the future depending on the mix of production we generate from various states, and on the possibility that any state may raise its production tax.

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Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased by $18,507,106 to $39,024,886 in 2018. The increase was primarily the result of increased production volumes but was also affected by an increase in our average depreciation, depletion and amortization rate from $11.15 per BOE during 2017 to $17.54 per BOE during 2018. These per BOE amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total volume sold, in BOE.

Ceiling Test Write-Down.    The Company recorded a non-cash write-down of the carrying value of its proved oil and natural gas properties of $14,172,309 for the year ended December 31, 2018 as a result of ceiling test limitations, which is reflected as ceiling test impairments in the accompanying Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2018, adjusted for market differentials, per SEC guidelines. The write-down reduced earnings in the period and will result in a lower depreciation, depletion and amortization rate in future periods. The Company did not have any write-downs for the period ended December 31, 2017.

General and administrative expenses. General and administrative expenses increased from $10,515,887 in 2017 to $12,867,686 in 2018. The increase was primarily related to increases in costs associated with compensation and employee benefits.

Interest income. Interest income was $97,855 in 2018 as compared to $291,083 in 2017. The decrease was the result of lower average cash on hand during 2018.

Interest expense. Interest expense was $427,898 in 2018 as compared to no interest expense in 2017. The increase was the result of having outstanding amounts on our credit facility during 2018.

Provision for income taxes. The provision for income taxes decreased from $10,416,171 in 2017 to $3,445,721 in 2018. The change was due to an adjustment in 2017 to the value of our deferred tax asset as a result of a change in our future effective tax rate.

Net income. The Company had net income of $8,999,760 in 2018 as compared to $1,753,869 in 2017. The increase in net income primarily resulted from increased revenues and from not having an additional provision for income taxes recorded for the change in tax rate as in 2017, partially offset by the ceiling test write down in 2018.

Liquidity and Capital Resources

Financing of Operations. We have historically funded our operations through cash available from operations and from equity offerings of our stock. Our primary sources of cash in 2019 were from funds generated from the sale of oil and natural gas production and borrowing on our Credit Facility. These cash flows were primarily used to fund our capital expenditures.

Credit Facility.  On July 1, 2014, the Company entered into a Credit Agreement with SunTrust Bank, as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (the “Administrative Agent”), which was amended on June 14, 2018, May 18, 2016, July 24, 2015, and June 26, 2015. In April 2019, the Company amended and restated its Credit Agreement with the Administrative Agent (as amended and restated, the “Credit Facility”). The amendment and restatement of the Credit Facility, among other things, increases the maximum borrowing amount to $1 billion, increases the borrowing base (the “Borrowing Base”) to $425 million, extends the maturity date through April 2024 and makes other modifications to the terms of the Credit Facility. The Credit Facility is secured by a first lien on substantially all of the Company’s assets.

The Borrowing Base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time.  The Borrowing Base will be redetermined semi-annually on each May 1 and November 1.  The Borrowing Base will also be reduced in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and cancellation of certain hedging positions.

The Credit Facility allows for Eurodollar Loans and Base Rate Loans.  The interest rate on each Eurodollar Loan will be the adjusted LIBOR for the applicable interest period plus a margin between 1.75% and 2.75% (depending on the then-current level of Borrowing Base usage).  The annual interest rate on each Base Rate Loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the Federal Funds Rate (as defined in the Credit Facility) plus 0.5% per annum, the (iii) adjusted LIBOR determined on a daily basis for an interest period of one-month, plus 1.00% per annum and (iv) 0.00% per annum, plus (b) a margin between 0.75% and 1.75% (depending on the then-current level of Borrowing Base usage).

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The Credit Facility contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio (as defined in the Credit Facility) of not more than 4.0 to 1.0 and (ii) a minimum current ratio of Current Assets to Current Liabilities (as such terms are defined in the Credit Facility) of 1.0 to 1.0. The Credit Facility also contains other customary affirmative and negative covenants and events of default.  As of December 31, 2019, $366,500,000 was outstanding on the Credit Facility.  We are in compliance with all covenants contained in the Credit Facility.

Cash Flows. Historically, our primary sources of cash have been from operations, equity offerings and borrowings on our Credit Facility. During 2019, 2018 and 2017, we had cash inflow from operations of $106,616,221, $70,357,321 and $42,806,224, respectively. During the three years ended December 31, 2019, we financed $140,848,094 through proceeds from the sale of stock.  During 2019, 2018 and 2017, we had proceeds from drawdowns on our Credit Facility of $327,000,000, $39,500,000, and $0, respectively.  We primarily used this cash to fund our capital expenditures and development aggregating $784,374,525 over the three years ended December 31, 2019. At December 31, 2019, we had cash on hand of $10,004,622 and negative working capital of $20,384,013, as compared to cash on hand of $3,363,726 and negative working capital of $35,066,175 at December 31, 2018 and cash on hand of $15,006,581 and working capital of $19,319,525 at December 31, 2017.

Schedule of Contractual Obligations. The following table summarizes our contractual obligations for periods subsequent to December 31, 2019.

	Payment due by period
			Less than 1						More than
Contractual Obligations	Total		year		1‑3 years		3‑5 years		5 years
Credit Facility (1)	$	366,500,000	$	—	$	—	$	366,500,000	$	—
Financing Lease Obligations (2)		754,911		311,206		311,206		132,499		—
Operating Lease Obligations - Office (3)		528,387		528,387		—		—		—
Operating Lease Obligations - Field (4)		1,416,784		708,392		708,392		—		—
Total	$	369,200,082	$	1,547,985	$	1,019,598	$	366,632,499	$	—

(1) This table does not include future commitment fees, interest expense or other fees on this facility because they are floating rate instruments, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.

(2) Financing Lease Obligations includes payments for vehicles under lease terms.  Per the term of the lease agreements, the Company will own the vehicles at the end of their term.

(3) Operating Lease Obligations – Office includes leases for our office spaces in Midland, Texas and Tulsa, Oklahomaand lease terms for certain office equipment.  The Midland office serves as our headquarters and is approximately 15,000 square feet. The Tulsa office is our accounting office and is approximately 3,700 square feet.  The office equipment leased is for equipment that is used in our Midland and Andrews offices.  All of these leases are currently month to month but are presumed to continue for all of 2020.  The Company incurred lease expense related to the office space of $555,425, $527,600 and $537,582, respectively, for the years ended December 2019, 2018 and 2017.

(4) Operating Lease Obligations – Field includes equipment leased for the operation of our wells.  These leases are on a month to month basis but we anticipate continuing to lease this equipment until the end of its useful life.

Long-term asset retirement obligation is not included in the above table as the timing of these payments cannot be reasonably predicted.

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Subsequent Events

Subsequent to December 31, 2019, the Company entered into new derivative contracts covering 4,500 barrels of oil per day for the period of January 2021 through December 2021. All of the derivative contracts 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. Please see the below table for information related to the put prices and call prices for the derivative contracts in place for 2021.

Date entered into	Barrels per day	Put price		Call price
2021 contracts
02/25/20	1,000	$	45.00	$	54.72
02/25/20	1,000		45.00		52.71
02/27/20	1,000		40.00		55.08
03/02/20	1,500		40.00		55.35

Subsequent to December 31, 2019, there has been a significant decline in oil prices due to global circumstances that are out of our control. As a result, the value of our derivative contracts has changed significantly. As of December 31, 2019, our balance sheet reflected a $3,000,078 derivative liability. As of March 16, 2020, there has been an unrealized gain on derivativs and that liability has become an asset.

Effects of Inflation and Pricing

The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Material changes in prices impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans and the value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. We anticipate business costs will vary in accordance with commodity prices for oil and natural gas, and the associated increase or decrease in demand for services related to production and exploration.

Off-Balance Sheet Financing Arrangements

As of December 31, 2019 we had no off-balance sheet financing arrangements.

Critical Accounting Policies and Estimates

Our discussion of financial condition and results of operations is based upon the information reported in our financial statements. The preparation of these statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. Our significant accounting policies are detailed in Note 1 to our financial statements included in this Annual Report. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.

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Revenue Recognition. In January 2018, the Company adopted Accounting Standards Update (“ASU”) 2014-09 Revenues from Contracts with Customers (Topic 606) (“ASU 2014-09”). The timing of recognizing revenue from the sale of produced crude oil and natural gas was not changed as a result of adopting ASU 2014-09. The Company predominantly derives its revenue from the sale of produced crude oil and natural gas. The contractual performance obligation is satisfied when the product is delivered to the customer. Revenue is recorded in the month the product is delivered to the purchaser and the Company receives payment from one to three months after delivery. The transaction price includes variable consideration as product pricing is based on published market prices and reduced for contract specified differentials. The new guidance regarding ASU 2014-09 does not require that the transaction price be fixed or stated in the contract. Estimating the variable consideration does not require significant judgment and Ring engages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products. See Note 3 of our financial statements for additional information.

Full Cost Method of Accounting. We account for our oil and natural gas operations using the full cost method of accounting. Under this method, all costs (internal or external) associated with property acquisition, exploration and development of oil and gas reserves are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and cost of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. All of our properties are located within the continental United States.

Write-down of Oil and Natural Gas Properties.   Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly utilizing the average of prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.

During 2018, the Company recorded  a non-cash write-down of the carrying value of the Company’s proved oil and natural gas properties as a result of ceiling test limitations of approximately $14.2 million which is reflected with ceiling test and other impairments in the accompanying Statements of Operations.  The Company did not have any write-downs related to the full cost ceiling limitation in 2017 and 2019.

Our reserve estimates, as of December 31, 2019, are based on an average price of $52.41 for oil and $1.47 for gas.

Oil and Natural Gas Reserve Quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Reserve quantities and future cash flows included in this Annual Report are prepared in accordance with guidelines established by the SEC and FASB. The accuracy of our reserve estimates is a function of:

● the quality and quantity of available data;

● the interpretation of that data;

● the accuracy of various mandated economic assumptions; and

● the judgments of the persons preparing the estimates.

Our proved reserve information included in this Annual Report was based on internal reports and audited by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. We continually make revisions to reserve estimates throughout the year as additional properties are acquired. We make changes to depletion rates and impairment calculations in the same period that changes to the reserve estimates are made.

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All capitalized costs of oil and natural gas properties, including estimated future costs to develop proved reserves and estimated future costs of site restoration, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent engineers. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined.

Income Taxes. Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to the actual values in the period we file our tax returns. Our balance sheet for the year ended December 31, 2019, includes a deferred tax liability of approximately $6.0 million.

In January 2017, the Company adopted ASU 2016-09, Compensation - Stock Compensation (Topic 718.) The Company used the modified retrospective method to account for unrecognized excess tax benefits from prior periods, resulting in an adjustment to our beginning balances of Deferred Income Taxes and Retained Loss of $1,596,463 and uses the prospective method to account for current period and future excess tax benefit. For the years ended December 31, 2019, 2018 and 2017, we recorded an increase of $3,855,389, an increase of $907,884 and a decrease of $49,896, respectively, to our income tax provision.

Item 7A:   Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Market risk refers to the risk of loss from adverse changes in oil and natural gas prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and spot prices applicable to the region in which we produce natural gas. Historically, prices received for oil and natural gas production have been volatile and unpredictable. We expect pricing volatility to continue.

The prices we receive depend on many factors outside of our control. Oil prices we received during 2019 ranged from a low of $40.40 per barrel to a high of $62.08 per barrel. Natural gas prices we received during 2019 ranged from a low of $0.34 per Mcf to a high of $3.78 per Mcf. A significant decline in the prices of oil or natural gas could have a material adverse effect on our financial condition and results of operations. In order to reduce 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.  As of December 31, 2019, the Company has in place derivative contracts covering 5,500 barrels of oil per day for the period of January 2020 through December 2020.  All of the derivative contracts 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.  Our collars as of December 31, 2019 all had a floor of $50 per barrel and had ceilings ranging between $58.25 and $65.83 per barrel, with an average ceiling of $61.06.  See Note 8 to our Financial Statements for further information.

Customer Credit Risk

Our principal exposure to credit risk is through receivables from the sale of our oil and natural gas production (approximately $22.9 million at December 31, 2019). We are subject to credit risk due to the concentration of our oil and natural gas receivables with our most significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the fiscal year 2019, sales to three customers, Phillips 66, Oxy and NGL Crude represented 42%, 36% and 7%, respectively, of oil and natural gas revenues. At December 31, 2019, Phillips 66 represented 47% of our accounts receivable, Oxy represented 31% of our accounts receivable and NGL Crude represented 9% of our accounts receivable.  Due to availability of other purchasers, we do not believe the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility, which bears variable interest based upon a prime rate and is therefore susceptible to interest rate fluctuations. Changes in interest rates affect the interest earned on the Company’s cash and cash equivalents and the interest rate paid on borrowings under the Credit Facility.

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As of December 31, 2019, we had $366.5 million outstanding on our Credit Facility with a weighted average interest rate of 4.49%.  A 1% change in the interest rate on our Credit Facility would result in an estimated $3,665,000 change in our annual interest expense.  See note 10 in the Footnotes to the Financial Statements for more information on the Company’s interest rates on our Credit Facility.

Currently, the Company does not use interest rate derivative instruments to manage exposure to interest rate changes.

Please also see Item 1A “Risk Factors” above for a discussion of other risks and uncertainties we face in our business.

Item 8:     Financial Statements and Supplementary Data

The financial statements and supplementary data required by this item are included beginning at page F-1 of this Annual Report.

Item 9:     Changes in and Disagreements with Accountants and Accounting and Financial Disclosure

None.

Item 9A:   Controls and Procedures

Evaluation of disclosure controls and procedures.

Our management, with the participation of our chief executive officer and chief financial officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Exchange Act. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.

Our management identified a material weakness in the Company's internal control over interim financial reporting for the quarters ended March 31, 2019, June 30, 2019 and September 30, 2019, as discussed below, which resulted in the restatement of the Company's previously issued interim financial statements (See Note 2 to Notes to Financial Statements - "Restatement of Previously Filed Financial Information"). However, this error was revealed and corrected through the application of the Company's annual financial reporting process. The Company will remediate this material weakness by incorporating procedures from its annual review process into its process for preparing future interim financial reports, including adding a level of third-party review. Management believes that these measures will remediate the material weakness. Based on management’s evaluation, our chief executive officer and chief financial officer concluded that, as of December 31, 2019, our disclosure controls and procedures are designed at a reasonable assurance level and are effective to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure.

We will continue to monitor and evaluate the effectiveness of our disclosure controls and procedures and our internal controls over financial reporting on an ongoing basis and are committed to taking further action and implementing additional enhancements or improvements, as necessary and as funds allow.

Changes in internal control over financial reporting.

We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes.

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In preparing our annual report for the year ended December 31, 2019, we identified errors in the Company's computation of the income tax provision related to equity compensation, which resulted in the restatement of previously issued financial statements as of and for the periods ended March 31, 2019, June 30, 2019 and September 30, 2019 (See Note 2 to Notes to Financial Statements - "Restatement of Previously Filed Financial Information"). Design and operating effectiveness deficiencies in our internal controls over interim financial reporting caused us to fail to identify the computational errors. Management has concluded that these deficiencies in internal control over interim financial reporting constituted a material weakness for the quarters ended March 31, 2019, June 30, 2019 and September 30, 2019. In order to remediate the material weakness, we are incorporating procedures from our annual review process into our process for preparing interim financial reports, including adding a level of third-party review. Management believes that these measures will remediate the material weakness in its interim procedures.

Except as described above, there were no changes in our internal control over financial reporting that occurred during the fiscal year ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Annual Report on Internal Control Over Financial Reporting and Report of Independent Accounting Firm

Our management is responsible for establishing and maintaining adequate internal controls over financial reporting. Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Furthermore, the effectiveness of a system of internal control over financial reporting in future periods can change as conditions change.

In making our assessment of internal control over financial reporting, our management used the criteria issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013). Based on our assessment, we believe that, as of December 31, 2019, our internal control over financial reporting is effective based on those criteria.

While management identified a deficiency in the Company's internal control over interim financial reporting that constituted a material weakness for the quarters ended March 31, 2019, June 30, 2019 and September 30, 2019, this error was revealed and corrected through the application of the Company’s annual financial reporting process.  The Company will remediate this material weakness by incorporating procedures from its annual review process into its process for preparing future interim financial reports, including adding a level of third-party review.  A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the Company's annual or interim financial statements will not be prevented or detected on a timely basis. We identified errors in the Company's computation of the income tax provision related to equity compensation, which resulted in the restatement of previously issued financial statements for the three months ended March 31, 2019, the three and six months ended June 30, 2019 and the three and nine months ended September 30, 2019 (See Note 2 to Notes to Financial Statements - "Restatement of Previously Filed Financial Information"). Design and operating effectiveness deficiencies in our internal control over interim financial reporting caused us to fail to identify the computational errors that related to the computation of the income tax provision related to equity compensation. Management has concluded that these deficiencies in internal control over interim financial reporting constituted a material weakness for the quarters ended March 31, 2019, June 30, 2019 and September 30, 2019.  Controls in place for annual financial reporting identified the above referenced error. As such, as of December 31, 2019, management believes that our internal control over financial reporting is effective.

The registered public accounting firm, Eide Bailly LLP, has audited the financial statements included in this annual report and has issued an attestation report on our internal control over financial reporting. The report is set forth under the caption “Report of Independent Registered Public Accounting Firm” in Item 8 of this annual report.

Item 9B:   Other Information

None.

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PART III

Item 10:     Directors, Executive Officers and Corporate Governance

Executive Officers and Directors

The following table sets forth information regarding our executive officers, certain other officers and directors as of March 2, 2020. Our Board of Directors (“Board”) believes that all the directors named below are highly qualified and have the skills and experience required for effective service on the Board. The directors’ and officers’ individual biographies below contain information about their experience, qualifications and skills.

Name	Age	Position
Kelly Hoffman	61	Chief Executive Officer, Director
David A. Fowler	61	President, Director
Daniel D. Wilson	58	Vice President of Operations
William R. Broaddrick	42	Chief Financial Officer
Lloyd T. Rochford	73	Chairman of the Board of Directors
Stanley M. McCabe	87	Director
Anthony B. Petrelli	67	Director
Clayton E. Woodrum	79	Director
Regina Roesener	59	Director

Each of the directors identified above were appointed for a term of one year (or until their successors are elected and qualified).

Messrs. Rochford and McCabe joined the Board in June 2012 as a part of the merger between Ring and Stanford. Messrs. Hoffman, Fowler, Woodrum and Petrelli joined the Board in January 2013. Regina Roesener joined the Board in September 2019. All of the Board members were re-elected at the Company’s 2019 annual stockholders’ meeting. There are no family relationships between any director or executive officer or person nominated or chosen to become a director or officer of the Company.

The following biographies describe the business experience of our executive officers and directors:

Kelly Hoffman – Chief Executive Officer and Director

Mr. Hoffman, 61, has organized the funding, acquisition and development of many oil and gas properties. He began his career in the Permian Basin in 1975 with Amoco Production Company. His responsibilities included oilfield construction, crew management, and drilling and completion operations. In the early 1990s, Mr. Hoffman co-founded AOCO and began acquiring properties in West Texas. In 1996, he arranged financing and purchased 10,000 acres in the Fuhrman Mascho field in Andrews, Texas. In the first six months, he organized a 60 well drilling and completion program resulting in a 600% increase in revenue and approximately 18 months later sold the properties to Lomak (Range Resources). In 1999, Mr. Hoffman arranged financing and acquired 12,000 acres in Lubbock and Crosby counties. After drilling and completing 19 successful wells, unitizing the acreage, and instituting a secondary recovery project, he sold his interest in the property to Arrow Operating Company. From April 2009 until December 2011, Mr. Hoffman served as President of Victory Park Resources, a privately held exploration and production company focused on the acquisition of oil and gas producing properties in Oklahoma, Texas and New Mexico. Mr. Hoffman has served as Chief Executive Officer of the Company since January 2013. Mr. Hoffman currently serves as a director of Joes Jeans Inc. (NASDAQ: JOEZ), a reporting company.

The particular experience, qualifications, attributes and skills that led our Board to conclude that Mr. Hoffman should serve as director include over 40 years of experience in the oil and gas industry; his substantial experience in the operation and management of drilling operations in the Permian Basin; his extensive experience acquiring oil and gas properties and the financing of such acquisitions; and his service in executive leadership and strategic planning roles in the oil and gas industry.

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David A. Fowler – President and Director

Mr. Fowler, 61, has served in several management positions for various companies in the insurance and financial services industries. In 1994, he joined Petroleum Listing Service as Vice President of Operations, overseeing oil and gas property listings, information packages, and marketing oil and gas properties to industry players. In late 1998, Mr. Fowler became the Corporate Development Coordinator for the Independent Producer Finance (“IPF”) group of Range Resources Corporation. Leaving IPF in April 2001, Mr. Fowler co-founded and became President of Simplex Energy Solutions, LLC (“Simplex”). Representing Permian Basin oil and gas independent operators, Simplex became known as the Permian Basin’s premier oil and gas divestiture firm, closing over 150 projects valued at approximately $675 million. Mr. Fowler has served as President of the Company since January 2013.

The particular experience, qualifications, attributes and skills that led our Board to conclude that Mr. Fowler should serve as director include his significant experience and relationships in the oil and gas industry; his knowledge regarding oil and gas properties and marketing in the Permian Basin; and his strategic planning roles in the oil and gas industry.

Daniel D. Wilson – Executive Vice President

Mr. Wilson, 58, has over 30 years of experience in operating, evaluating and exploiting oil and gas properties. He has experience in production, drilling and reservoir engineering. From September 1983 to December 2012, Mr. Wilson served as the Vice President and Manager of Operations for Breck Operating Corporation (“Breck”). He had the responsibility of overseeing the building, operating and divestiture of two companies during this time. At Breck’s peak, Mr. Wilson was responsible for over 750 wells in seven states and had an operating staff of 27 members, including engineers, foremen, pumpers and clerks. Mr. Wilson personally performed or oversaw all of the economic evaluations for both acquisition and banking purposes. Mr. Wilson has served as Executive Vice President of the Company since January 2013.

William R. Broaddrick – Chief Financial Officer.

Mr. Broaddrick, 42, was employed from 1997 to 2000 with Amoco Production Company, performing lease revenue accounting and state production tax regulatory reporting functions. In 1999, Mr. Broaddrick received a Bachelor’s Degree in Accounting from Langston University through Oklahoma State University – Tulsa. Mr. Broaddrick is a Certified Public Accountant. During 2000, Mr. Broaddrick was employed by Duke Energy Field Services, LLC, performing state production tax functions. From 2001 until 2010, Mr. Broaddrick was employed by Arena, as Vice President and Chief Financial Officer. During 2011, Mr. Broaddrick joined Stanford Energy, Inc. (“Stanford”) as Chief Financial Officer. As a result of the merger transaction between Stanford and Ring, Mr. Broaddrick became Chief Financial Officer of the Company as of July 2012.

Lloyd T. (“Tim”) Rochford – Chairman of the Board of Directors

Mr. Rochford, 73, has been an active individual consultant and entrepreneur in the oil and gas industry since 1973. He has been an operator of wells in the mid-continent of the United States, evaluated leasehold drilling and production projects, and arranged and raised in excess of $500 million in private and public financing for oil and gas projects and development.

Mr. Rochford has successfully formed, developed and sold/merged four natural resource companies, two of which were listed on the New York Stock Exchange. The most recent, Arena Resources, Inc. (“Arena”), was founded by Mr. Rochford and his associate Stanley McCabe in August 2000. From inception until May 2008, Mr. Rochford served as President, Chief Executive Officer and as a director of Arena. During that time, Arena received numerous accolades from publications such as Business Week (2007 Hot Growth Companies), Entrepreneur (2007 Hot 500), Fortune (2007, 2008, 2009 Fastest Growing Companies), Fortune Small Business (2007, 2008 Fastest Growing Companies) and Forbes (Best Small Companies of 2009). In May 2008, Mr. Rochford resigned from the position of Chief Executive Officer at Arena and accepted the position of Chairman of the Board. In his role as Chairman, Mr. Rochford continued to pursue opportunities that would enhance the then-current, as well as long-term, value of Arena. Through his efforts, Arena entered into a merger agreement and was acquired by another New York Stock Exchange company for $1.6 billion in July 2010.

The particular experience, qualifications, attributes and skills that led our Board to conclude that Mr. Rochford should serve as director include his 45 years of experience in the oil and gas industry; his service as an executive officer of four natural resources companies; his extensive experience in evaluating and pursuing strategic transactions; his corporate governance, compliance, and risk management experience; and his board experience.

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Stanley M. McCabe – Director

Mr. McCabe, 87, has been active in the oil and gas industry for over 30 years, primarily seeking individual oil and gas acquisition and development opportunities. In 1979, he founded and served as Chairman and Chief Executive Officer of Stanton Energy, Inc., a Tulsa, Oklahoma natural resource company specializing in contract drilling and operation of oil and gas wells. In 1990, Mr. McCabe co-founded Magnum Petroleum, Inc. with Mr. Rochford, serving as an officer and director. In 2000, Mr. McCabe co-founded Arena with Mr. Rochford, and Mr. McCabe served as Chairman of the Board of Arena until 2008 and then as a director of Arena until 2010.

The particular experience, qualifications, attributes and skills that led our Board to conclude that Mr. McCabe should serve as director include his vast years of experience founding and serving in executive roles for oil and gas exploration and production companies, as well as his experience evaluating oil and gas acquisition and development opportunities.

Anthony B. Petrelli – Director

Mr. Petrelli, 67, is President, Chairman, and Director of Investment Banking Services of NTB Financial Corporation, a Denver, Colorado based financial services firm founded in 1977. Beginning his career in 1972, Mr. Petrelli has extensive experience in the areas of operations, sales, trading, management of sales, underwriting and corporate finance. He has served on numerous regulatory and industry committees including service on the FINRA Corporate Finance Committee, the NASD Small Firm Advisory Board and as Chairman of the FINRA District Business Conduct Committee, District 3. Additionally, Mr. Petrelli has served on the Board of Directors of Sensus Healthcare, Inc. since July 2016. Mr. Petrelli received his Bachelors of Science in Business (Finance) and his Masters of Business Administration (MBA) from the University of Colorado and a Masters of Arts in Counseling from Denver Seminary.

The particular experience, qualifications, attributes and skills that led our Board to conclude that Mr. Petrelli should serve as director include his experience and expertise in financial and business matters with significant involvement in corporate governance and financial matters; his service on the FINRA Corporate Finance Committee, the NASD Small Firm Advisory Board and as Chairman of the FINRA District Business Conduct Committee; and his board experience.

Clayton E. Woodrum – Director

Mr. Woodrum, CPA, 79, is a founding partner of Woodrum, Tate & Associates, PLLC. His financial background encompasses over 40 years of experience from serving as a Partner In Charge of the Tax Department of a big eight accounting firm to Chief Financial Officer of BancOklahoma Corp. and Bank of Oklahoma. His areas of expertise include business valuation, litigation support (including financial analysis, damage reports, depositions and testimony), estate planning, financing techniques for businesses, asset protection vehicles, sales and liquidations of businesses, debt restructuring, debt discharge and CFO functions for private and public companies.

The particular experience, qualifications, attributes and skills that led our Board to conclude that Mr. Woodrum should serve as a director include his significant financial background; his public accounting and tax experience; and his prior performance of CFO functions for both public and private companies.

Regina Roesener – Director

Mrs. Roesener, 59, currently serves as the Chief Operating Officer, Director of Corporate Finance and a member of the board of directors of NTB Financial Corporation (“NTB”), a member firm of FINRA and also a Registered Investment Advisor with the U.S. Securities and Exchange Commission (“SEC”).  She has served as a Board Member of the National Investment Bankers Association and as a member of Women in Syndicate Association and has served as a Board Member for the Denver chapter of the March of Dimes. Mrs. Roesener received her Bachelor of Science degree in Education from the University of Colorado in 1982.

The particular experience, qualifications, attributes and skills that led our Board to conclude that Mrs. Roesener should serve as a director include her significant financial background; and her prior Board experience.

Our executive officers are elected by, and serve at the pleasure of, our Board of Directors. Our directors serve terms of one year each, with the current directors serving until the next annual meeting of stockholders, and in each case until their respective successors are duly elected and qualified.

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Involvement in Certain Legal Proceedings

During the past ten years, there have been no events under any bankruptcy act, no criminal proceedings and no judgments, injunctions, orders or decrees material to the evaluation of the ability and integrity of any of our directors or executive officers, and none of our executive officers or directors has been involved in any judicial or administrative proceedings resulting from involvement in mail or wire fraud or fraud in connection with any business entity, any judicial or administrative proceedings based on violations of federal or state securities, commodities, banking or insurance laws or regulations, and any disciplinary sanctions or orders imposed by a stock, commodities or derivatives exchange or other self-regulatory organization.

Board Committees

Our Board of Directors has established an Audit Committee, a Compensation Committee, a Nominating and Corporate Governance Committee, and an Executive Committee, the composition and responsibilities of which are briefly described below. The charters for each of these committees will be provided to any person without charge, upon request. The charters are also available on the Company’s website at www.ringenergy.com. Requests may be directed to Ring Energy, Inc., 6555 S. Lewis Ave., Suite 200, Tulsa, Oklahoma 74136, Attention William R. Broaddrick, or by calling (918) 499-3880. Our Board may establish other committees from time to time to facilitate our management.

Audit Committee

The Audit Committee’s principal functions are to assist the Board in monitoring the integrity of our financial statements, the independent auditor’s qualifications and independence, the performance of our independent auditors and our compliance with legal and regulatory requirements. The Audit Committee has the sole authority to retain and terminate our independent auditors and to approve the compensation paid to our independent auditors. The Audit Committee is also responsible for overseeing our internal audit function. The Audit Committee is comprised of Mr. Woodrum, Mr. Petrelli and Mrs. Roesener, with Mr. Woodrum acting as the chairman. Our Board of Directors determined that Mr. Woodrum qualified as “audit committee financial expert” as defined in Item 407 of Regulation S-K promulgated by the Securities and Exchange Commission (see the biographical information for Mr. Woodrum, infra, in this discussion of “Directors and Executive Officers”). Each of the members further qualified as “independent” in accordance with the applicable regulations of the NYSE American definition of independent director set forth in the Company Guide, Part 8, Section 803(A).

Compensation Committee

The Compensation Committee’s principal function is to make recommendations regarding the compensation of the Company’s officers. In accordance with the rules of the NYSE American, the compensation of our chief executive officer is recommended to the Board (in a proceeding in which the chief executive officer does not participate) by the Compensation Committee. Compensation for all other officers is also recommended to the Board for determination by the Compensation Committee. The Compensation Committee is comprised of Messrs. McCabe and Woodrum, with Mr. McCabe acting as the chairman.

Nominating and Corporate Governance Committee

The Nominating and Corporate Governance Committee’s principal functions are to identify and recommend qualified candidates to the Board of Directors for nomination as members of the Board and its committees, and develop and recommend to the Board corporate governance principles applicable to the Company. The Nominating and Corporate Governance Committee is comprised of Messrs. Petrelli and McCabe, with Mr. Petrelli acting as the chairman.

There have been no material changes to the procedures by which security holders may recommend nominees to our Board of Directors.

Executive Committee

The Executive Committee’s principal function is to exercise the powers and duties of the Board between Board meetings and while the Board is not in session, and implement the policy decisions of the Board. The Executive Committee is comprised of Messrs. Rochford and McCabe.

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Code of Ethics

We have adopted a Code of Ethics that applies to our Chief Executive Officer, President, Chief Financial Officer, and Corporate Controller, as well as the principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions to ensure the highest standard of ethical conduct and fair dealing.

We have also adopted a Code of Business Conduct covering a wide range of business practices that applies to all of our officers, directors, and employees to help promote honest and ethical conduct. The Code of Business Conduct covers standards for professional conduct, including, among others, conflicts of interest, insider trading, confidential information, protection and proper use of Company assets, and compliance with all laws and regulations applicable to the Company’s business.

These documents are available on the Company’s website at www.ringenergy.com. We will also provide any person without charge, upon request, a copy of the Code of Ethics or Code of Business Conduct. Requests may be directed to Ring Energy, Inc., 6555 S. Lewis Ave., Suite 200, Tulsa, Oklahoma 74136, Attention William R. Broaddrick, or by calling (918) 499-3880.

Delinquent Section 16(a) Reports

Section 16(a) of the Exchange Act requires our officers and directors, and persons who own more than ten percent of a registered class of our equity securities, to file initial reports of ownership and reports of changes in ownership with the SEC. Such persons are required by SEC regulations to furnish us with copies of all Section 16(a) forms they file.

To our knowledge, based solely upon review of the copies of such Section 16 reports furnished to us during the year ended December 31, 2019 and on written representations from our directors and executive officers, all Section 16 reports applicable to our directors, executive officers and holders known to us to beneficially own more than 10% of any class of our equity securities were filed on a timely basis, except one Form 4 for Mrs. Roesener that did not report a transaction on December 21, 2019 in a timely manner, two Form 4s for Mr. Fowler that did not report certain transactions on December 19, 2019, December 21, 2019 and December 26, 2019 in a timely manner, two Form 4s for Mr. Broaddrick that did not report certain transactions on December 19, 2019, December 21, 2019 and December 26, 2019 in a timely manner, two Form 4s for Mr. Hoffman that did not report certain transactions on December 19, 2019, December 21, 2019 and December 26, 2019 in a timely manner, two Form 4s for Mr. McCabe that did not report certain transactions on December 19, 2019, December 21, 2019 and December 26, 2019 in a timely manner, two Form 4s for the Rochford Living Trust that did not report certain transactions on December 19, 2019, December 21, 2019 and December 26, 2019 in a timely manner, two Form 4s for Mr. Wilson that did not report certain transactions on December 19, 2019, December 21, 2019 and December 26, 2019 in a timely manner, two Form 4s for Mr. Woodrum that did not report certain transactions on December 19, 2019, December 21, 2019 and December 26, 2019 in a timely manner and two Form 4s for Mr. Petrelli that did not report certain transactions on December 19, 2019, December 21, 2019 and December 26, 2019 in a timely manner.

Item 11:     Executive Compensation

COMPENSATION DISCUSSION & ANALYSIS

Our Compensation Committee, appointed by our Board, assists the Board in performing its responsibilities relating to the compensation of our Chief Executive Officer and other Named Executive Officers. The Compensation Committee is responsible for our incentive compensation programs, which include programs for our executive management team, including the Named Executive Officers listed below. (See “Setting Executive Compensation and Evaluating Named Executive Officer Performance” below).

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This Compensation Discussion and Analysis (1) provides an overview of our compensation policies and programs; (2) explains our compensation objectives, policies and practices with respect to our Named Executive Officers and our Compensation Committee’s rationale in structuring our executive compensation program, which is designed to align the interests of Named Executive Officers with our stockholders, as well as to provide our Named Executive Officers with incentives to achieve the Company’s goals and objectives that will ultimately enhance value to our stockholders; and (3) identifies the elements of compensation for each of the individuals identified in the following table, whom we refer to in this annual report as our “Named Executive Officers” for the fiscal year ending December 31, 2019.

Name	Principal Position
Kelly Hoffman	Chief Executive Officer, effective January 1, 2013
David A. Fowler	President, effective January 1, 2013
Daniel D. Wilson	Executive Vice President, effective January 1, 2013
William R. Broaddrick	Chief Financial Officer, effective July 1, 2012
Lloyd T. Rochford	Chairman of the Board, effective January 1, 2012

This section contains a discussion of the material elements of compensation awarded to, earned by or paid to (i) all individuals serving as the Company’s principal executive officer or acting in a similar capacity during the last completed fiscal year (“PEO”), regardless of compensation level, and (ii) all individuals serving as the Company’s principal financial officer or acting in a similar capacity during the last completed fiscal year (“PFO”), regardless of compensation level. As of the end of the last completed fiscal year, the Company had two executive officers other than the PEO and PFO, and this discussion includes the material elements of compensation awarded to, earned by, or paid to such executive officers. This section omits tables and columns if there has been no compensation awarded to, earned by, or paid to any of the Named Executive Officers or directors required to be reported in such table or column in any fiscal year covered by such table.

OBJECTIVES AND PHILOSOPHY OF OUR EXECUTIVE COMPENSATION PROGRAM

The Company strives to attract, motivate and retain high-quality executives who are willing to accept lower base compensation in cash and be rewarded with equity awards based on performance and the achievement of the goals and objectives of the Company, thereby allowing the Company to better align the interests of its executives with its stockholders. The Company competes for executive talent from a broad range of public companies and private companies primarily using its equity grants, as its cash compensation is relatively low compared to its peers.

General

Our executive compensation programs are intended to achieve two objectives. The primary objective is to enhance stockholder value. The second objective is to attract, motivate, reward and retain employees, including executive personnel, who contribute to the long-term success of the Company and the enhancement of stockholder value. As described in more detail below, our current executive compensation program for Named Executive Officers includes three major elements: (1) a base salary, (2) discretionary annual bonuses, and (3) discretionary equity awards.

The Company believes that each element of its executive compensation program helps to achieve one or both of the Company’s compensation objectives outlined above. Our executives’ compensation is based on individual and Company performance and designed to attract, retain and motivate highly qualified executives while creating a strong connection between financial and operational performance and stockholder value, which is exemplified in the mix of the compensation that we provide to our Named Executive Officers. In furtherance of our objective to align executive compensation with stockholder value, a significant portion of our Named Executive Officers’ compensation in 2019 was in the form of equity awards.

Our executive compensation program is designed to do the following:

● Align the compensation of our Named Executive Officers and other managers with our stockholders’ interests and motivate our executive officers to meet the Company’s objectives;

● Pay for performance, taking into consideration both the performance of the Company and the individual in determining executive compensation;

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● Promote Named Executive Officer accountability by compensating Named Executive Officers for their contributions to the achievement of the Company’s objectives (while discouraging excessive risk-taking not in the interest of long term value for our stockholders); and

● Attract and retain highly qualified executives with significant industry knowledge and experience by providing them with a fair compensation program that provides financial stability and incentivizes growth in stockholder value.

Our Compensation Committee and Board believe that our executive compensation program provides our executive officers with incentives to meet the Company’s goals and objectives, while discouraging excessive risk taking. We believe our executive compensation program is consistently aligned with creating value to our stockholders.

The table below lists each material element of our executive compensation program and the compensation objective or objectives that it is designed to achieve.

COMPENSATION ELEMENT	COMPENSATION OBJECTIVES
Base Salary	Attract and retain qualified executives with significant industry knowledge, experience and expertise. Provide stability in compensation through a fixed compensation element that takes into account the Named Executive Officer’s skills, experience, expertise, and tenure with the Company.
Bonus Compensation	Motivate and reward executives’ performance. Reward achievement of the Company’s goals and objectives. Enhance profitability of the Company and stockholder value.
Equity-Based Compensation – Stock Options and Restricted Stock Awards	Enhance profitability of the Company and stockholder value by aligning long-term incentives with stockholders’ long-term interests. Incentivize achievement of both strategic goals and objectives by providing Named Executive Officers with rewards for their contributions to achieving such goals and objectives. Promote Named Executive Officer accountability by compensating Named Executive Officers for their contributions to the achievement of the Company’s objectives (while discouraging excessive risk-taking). Promote pay-for-performance and allow our Named Executive Officers to acquire meaningful interests in the Company. Encourage long-term value creation for stockholders and retention of talented executive officers.

As illustrated by the table above, base salary is primarily intended to attract and retain qualified executives who have significant industry knowledge, experience and expertise. This is the element of the Company’s current executive compensation program where the value of the benefit in any given year is not wholly dependent on performance. Base salaries are intended to attract and retain qualified executives as well as to provide stability in the Named Executive Officer’s compensation and discourage excessive risk-taking. Base salaries are reviewed annually and take into account a number of factors, including: experience and retention considerations; past performance; improvement in historical performance; anticipated future potential performance; and other issues specific to the individual executive.

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There are specific elements of the current executive compensation program that are designed to reward performance and enhance profitability and stockholder value, and, therefore, the value of these benefits is based on performance. The Company’s discretionary annual bonus plan is primarily intended to motivate and reward Named Executive Officers’ performance to achieve specific strategies and operating objectives, as well as improved financial performance. The Company also awards stock options and restricted stock grants to promote long-term value creation for stockholders and to retain talented executives for an extended period.

Peer Review, Benchmarking and Compensation Consultant

The Compensation Committee reviews, evaluates and benchmarks the compensation practices of peer companies on a regular basis and has determined that the Company is efficient and is generally more effective than its peer companies in aligning the compensation of its executive officers with the interests of stockholders. The Compensation Committee believes that bonuses and equity compensation should fluctuate with the Company’s success in achieving financial, operating and strategic goals. The Compensation Committee’s philosophy is that the Company should continue to use long-term compensation such as stock options and restricted stock awards to align stockholders’ and executives’ interests and should allocate a much greater portion of an executive’s compensation package to long-term compensation. Based on this belief, the Compensation Committee reviews the performance of the Company’s executive officers throughout the year to evaluate the performance of each executive officer relative to the performance of the Company and the progress in meeting the Company’s goals and objectives.

The Company has not deemed it necessary to hire an outside consultant to assist the Compensation Committee, as compensation paid by its peers is generally available.

Setting Executive Compensation and Evaluating Named Executive Officer Performance

Our executive compensation programs are determined and approved by our Compensation Committee based on a comprehensive evaluation of the Company’s and individual executive officer’s performance, as well as consideration of industry compensation data reviewed by the Compensation Committee. The Compensation Committee takes into consideration the recommendations by our Chairman of the Board and our Chief Executive Officer (as to the compensation of executive officers other than the Chief Executive Officer). None of the Named Executive Officers are members of the Compensation Committee. The Compensation Committee has the direct responsibility and authority to review and approve the Company’s goals and objectives relative to the compensation of the Named Executive Officers, and to determine and approve (either as a committee or with the other members of the Company’s Board who qualify as “independent” directors under applicable guidelines adopted by the NYSE American) the compensation of our Named Executive Officers.

For purposes of evaluating performance, our Compensation Committee, in consultation with our management and the Board, sets performance goals and objectives for the Company, regularly assesses progress towards meeting such goals and objectives throughout the year, and determines the appropriate compensation for each of our Named Executive Officers. The Compensation Committee evaluates various factors in determining the appropriate compensation for each of our Named Executive Officers.

PERFORMANCE OBJECTIVES AND GOALS

Our Compensation Committee considered the following 2019 goals and objectives, among other factors such as industry compensation data and the commodity pricing environment, in determining the compensation of our Named Executive Officers:

Objectives	Evaluation/Analysis for 2019
Increase Production	Production increased 77%, from 2,232,658 BOE in 2018 to 3,948,871 BOE for 2019.
Increase Proved Reserves	Increased our proved reserves 121% to 81.1 million BOE.

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The Compensation Committee reviewed the performance of our Named Executive Officers in conjunction with the Company’s performance objectives and goals for 2019. The Compensation Committee also took into consideration other circumstances in determining executive compensation including, without limitation, changes in commodity prices, market conditions, supply and demand, weather conditions, governmental regulation, and other factors. The Compensation Committee determined that, despite volatile commodity prices, the Company exceeded the objectives and goals for 2019 and tied the compensation (as discussed below) to the Company’s performance.

ROLE OF STOCKHOLDER SAY-ON-PAY ADVISORY VOTE

In determining 2019 executive compensation, the Compensation Committee considered the approval received from the stockholders of the say-on-pay vote at the last annual meeting. Based on the results of the say-on-pay vote, the Company has continued to focus on ensuring our executive compensation program is designed primarily to align the interests of our executives with stockholders and incentivize our management to achieve the Company’s objectives and goals. The Company is developing a plan to communicate regularly with its stockholders to gather feedback on the Company’s performance and executive compensation program.

Our Board and Compensation Committee utilize the “say-on-pay” vote as an additional guide to ensure our executive compensation programs are aligned with the interests of our stockholders. Our Compensation Committee will continue to evaluate the Company’s compensation program to ensure competitiveness, the alignment of the Company’s executive compensation with stockholders’ interests and to meet other compensation objectives.

EXECUTIVE COMPENSATION PROGRAM ELEMENTS FOR 2019

Our Compensation Committee believes that our executive compensation program has played a significant role in our ability to enhance our stockholders with value based upon our continued growth in production and reserves, in addition to our continued commitment to meeting our objectives and goals.

In 2019, we continued to grow our production and reserves by focusing on operational efficiency continued to focus on safety in our operations.

● Significant Production Growth – We created significant production growth in 2019. Our production increased approximately 77%, to 3,948,871 BOE in 2019, as compared to production of 2,232,658 BOE for 2018.

● Reserve Growth – Through December 31, 2019, we increased our proved reserves to approximately 81.1 million BOE. As of December 31, 2019, our estimated proved reserves had a pre-tax “PV10” (present value of future net revenues before income taxes discounted at 10%) of approximately $1.1 billion and a Standardized Measure of Discounted Future Net Cash Flows of approximately $923.2 million.

● Continued Successful Development – We improved our operational efficiency through employing technological advancements, which have provided a significant benefit in our continuous drilling program in the volatile commodity price environment. As of December 31, 2019, Ring has drilled 309 wells, with 193 being vertical wells and 116 being horizontal wells in its Central Basin acreage, 15 wells, with 10 being vertical wells and 5 being horizontal wells on its Delaware Basin acreage and 16 wells, all horizontal, on the Northwest Shelf.

● Safety and Training – We continued our strong safety performance in 2019.

Our Compensation Committee assessed each of our executive officers’ performance and contribution to the Company meeting its objectives for 2019. Below is a discussion of the compensation of each of our Named Executive Officers under our compensation program, which should be read in conjunction with the “Summary Compensation Table.”

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Base Salaries

The Compensation Committee believes base salary is an integral element of executive compensation to provide executive officers with a base level of monthly income. We provide all of our employees, including our Named Executive Officers, with an annual base salary to compensate them for their services to the Company. Similar to most companies within the industry, our policy is to pay Named Executive Officers’ base salaries in cash.

The base salary of each Named Executive Officer is reviewed annually, with the salary of the Chief Executive Officer being established by the Compensation Committee and the salaries of the other executive officers being determined and approved by the Compensation Committee after consideration of recommendations by the Chairman of the Board and Chief Executive Officer. The Compensation Committee analyzes many factors in its evaluation of our Named Executive Officers’ base salary, including the experience, skills, contributions and tenure of such officer with the Company and such executive officers’ current and future roles, responsibilities and contributions to the Company.

For the year ended December 31, 2017, Mr. Broaddrick received a salary of $145,000.  Effective January 1, 2018, the Compensation Committee recommended an increase of $30,000 for Mr. Broaddrick, increasing his base salary to $175,000.  Effective January 1, 2019, the Compensation Committee recommended an increase of $20,000 for Mr. Broaddrick, increasing his base salary to $195,000.

For the year ended December 31, 2017, Mr. Hoffman received a salary of $205,000.  Effective January 1, 2018, the Compensation Committee recommended an increase of $30,000 for Mr. Hoffman, increasing his base salary to $235,000.  Effective January 1, 2019, the Compensation Committee recommended an increase of $15,000 for Mr. Hoffman, increasing his base salary to $250,000.

For the year ended December 31, 2017, Mr. Fowler received a salary of $175,000.  Effective January 1, 2018, the Compensation Committee recommended an increase of $25,000 for Mr. Fowler, increasing his base salary to $200,000.  Effective January 1, 2019, the Compensation Committee recommended an increase of $25,000 for Mr. Fowler, increasing his base salary to $225,000.

For the year ended December 31, 2017, Mr. Wilson received a salary of $175,000.  Effective January 1, 2018, the Compensation Committee recommended an increase of $25,000 for Mr. Wilson, increasing his base salary to $200,000.  Effective January 1, 2019, the Compensation Committee recommended an increase of $25,000 for Mr. Wilson, increasing his base salary to $225,000.

While Mr. Rochford has been Chairman of the Board of Directors since 2013, Mr. Rochford was hired as an employee effective October 1, 2019. The Compensation Committee designated a starting salary for Mr. Rochford of $180,000. For the partial year 2019, Mr. Rochford received $45,000 in salary.

The salary of each of our Named Executive Officers is reported in the “Salary” column of the “Summary Compensation Table” for each Named Executive Officer.

Annual Bonuses

The Company’s payment of bonuses has been discretionary and is largely based on the recommendations of the Compensation Committee. Cash incentive bonuses are designed to provide our executive officers with an incentive to achieve the Company’s business goals and objectives and are tied to the performance of the Company. Cash bonuses have not been, and are not expected to be, a significant portion of the Company’s executive compensation package. Cash bonuses are determined for Named Executive Officers based on the Company’s performance for the prior year, the officer’s individual performance in the prior year, the officer’s expected future contribution to the performance of the Company, and other competitive data on grant values of peer companies.

No cash bonuses have been granted to Named Executive Officers in 2017 or 2018.  In December 2019, the Compensation Committee recommended cash bonuses to Mr. Hoffman, Mr. Fowler, Mr. Wilson and Mr. Broaddrick totaling $100,000 based on achieving the Company's production growth objectives.  The annual discretionary bonus is reported in the “Bonus” column of the “Summary Compensation Table” for each Named Executive Officer.

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Equity-Based Compensation – Stock Options and Restricted Stock Awards

A significant component of our executive compensation program is equity-based compensation. It is our policy that the Named Executive Officers’ long-term compensation should be directly linked to enhancing stockholders’ value. Accordingly, the Compensation Committee grants to the Company’s Named Executive Officers equity awards under the Company’s long term incentive plan designed to link an increase in stockholder value to compensation. The purpose of granting equity-based compensation is to incentivize and reward the Company’s executive officers for the Company’s achievement of its objectives and goals and the individual’s contribution to meeting such goals and objectives and to encourage continued dedication to the Company by providing executives with meaningful ownership interests in the Company.

Messrs. Hoffman, Fowler, Wilson, Broaddrick and Rochford were granted restricted stock in 2017, 2018 and 2019.

Stock option grants are valued using the Black-Scholes Model and are calculated as a part of the executive compensation package for the year based on the amount of the requisite service period served. Non-qualified stock options and restricted stock granted to Named Executive Officers and other key employees generally vest ratably over five years. The Compensation Committee believes that the grant of equity awards encourages Named Executive Officers to continue to use their best professional skills and helps to retain Named Executive Officers for longer terms.

Grants are determined for Named Executive Officers based on performance in the prior year, expected future contribution to the performance of the Company, and other competitive data on grant values of peer companies. Awards may be granted to new key employees or Named Executive Officers on their respective hire dates. Other grant date determinations are made by the Compensation Committee, which are based upon the date the Compensation Committee met and proper communication was made to the Named Executive Officer or key employee as defined in the definition of grant date by generally accepted accounting principles. Exercise prices are equal to the value of the Company’s stock on the close of business on the determined grant date. The Company has no program or practice to coordinate timing of grants with release of material, nonpublic information.

The grant date fair value as determined under generally accepted accounting principles is shown in the “Summary Compensation Table” below.

Pension Plans, Non-Qualified Deferred Compensation Plans, Change-In-Control Arrangements and Retirement Plans

The Company did not have any pension plans, non-qualified deferred compensation plans or severance, retirement, termination, constructive termination or change in control arrangements for any of its Named Executive Officers for the year ended December 31, 2019.

Other Benefits

Our Named Executive Officers are eligible to participate in all of our employee benefit plans, such as medical, dental, vision, group life, and short and long-term disability, in each case, on the same basis as other employees, subject to applicable laws. We also provide vacation and other paid holidays to all employees, including our Named Executive Officers.

We maintain a 401(k) plan for eligible employees. Under the 401(k) plan, eligible employees may elect to contribute a portion of their eligible compensation on a pre-tax basis in accordance with the limitations imposed under the Internal Revenue Code of 1986, as amended, or the Code. The plan allows eligible employees to make pre-tax or after-tax contributions of up to 100% of their annual eligible compensation. The Company makes matching contributions of up to 6% of any employee's compensation.

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TAX CONSIDERATIONS

Although our Compensation Committee considers the tax and accounting treatment associated with the cash and equity grants it makes to its executive officers, these considerations are not dispositive. Section 162(m) of the Code places a limit of $1.0 million per person on the amount of compensation that we may deduct in any year with respect to our Chief Executive Officer, Chief Financial Officer and our three most highly compensated executive officers other than the Chief Executive Officer and the Chief Financial Officer. There is an exemption from the $1.0 million limitation for performance-based compensation that meets certain requirements. Our benefit plans are generally designed to permit compensation to be structured to meet the qualified performance-based compensation exception. To maintain flexibility in compensating Named Executive Officers in a manner designed to promote our Company goals and objectives, our Compensation Committee has not adopted a policy requiring all compensation to be deductible. The Compensation Committee retains the ability to evaluate the performance of our executive officers and to pay appropriate compensation, even if some of it may be non-deductible, to ensure competitive levels of total compensation are paid to certain individuals.

We account for stock-based awards based on their grant date fair value, as determined under FASB ASC Topic 718. In connection with its approval of stock-based awards, the Compensation Committee is cognizant of and sensitive to the impact of such awards on stockholder dilution. The Compensation Committee also endeavors to avoid stock-based awards made subject to a market condition, which may result in an expense that must be marked to market on a quarterly basis. The accounting treatment for stock-based awards does not otherwise impact the Compensation Committee’s compensation decisions.

RISK CONSIDERATIONS IN OUR OVERALL COMPENSATION PROGRAM

Our compensation program is designed to focus on meeting the Company’s objectives and goals while discouraging management from undue risk-taking. When establishing and reviewing our executive compensation program, the Compensation Committee has considered whether the program encourages unnecessary or excessive risk taking and has concluded that it does not. While behavior that may result in inappropriate risk taking cannot necessarily be prevented by the structure of compensation practices, we believe that our compensation policies and practices do not create risks that are reasonably likely to have a material adverse effect on us.

Our compensation program is comprised of both fixed and incentive-based elements. The fixed compensation (i.e., base salary) provides reliable, foreseeable income that mitigates the focus of our employees on our immediate financial performance or our stock price, encouraging employees to make decisions in our best long-term interests. The incentive components are designed to be sensitive to our goals and objectives, performance and stock price. In combination, we believe that our compensation structure does not encourage our officers and employees to take unnecessary or excessive risks in performing their duties.

Moreover, with limited exceptions, our Compensation Committee retains discretion to impose additional conditions and adjust compensation pursuant to our clawback policy as well as for quality of performance and adherence to the Company’s values. The stock options and restricted stock that the Company has granted to its executive officers have a five year vesting period, which further mitigates risk in the event any executive officer departs or is terminated and his options have not vested. The Board may seek reimbursement from an executive officer if it determines that the officer engaged in conduct that was detrimental to the Company and resulted in a material inaccuracy in either our financial statements or in performance metrics that affected the officer’s compensation. If the Compensation Committee or the Board determines that an officer engaged in fraudulent misconduct, it will seek such reimbursement. In cases of misconduct by an executive officer, the Board has discretion to take a range of actions to remedy the misconduct and prevent its recurrence, including terminating the individual’s employment.

We believe that our compensation policies and practices for all employees, including executive officers, do not create risks that are reasonably likely to have a material adverse effect on our Company.

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COMPENSATION OF NAMED EXECUTIVE OFFICERS FROM 2017 THROUGH 2019

The “Summary Compensation Table” set forth below should be read in connection with the tables and narrative descriptions contained in this Compensation Discussion & Analysis. The “Outstanding Equity Awards at Fiscal Year End Table” and “Option Exercises and Stock Vested Table” provide further information on the Named Executive Officers’ potential realizable value and actual value realized with respect to their equity awards.

								All Other
Name and Principal						Equity Awards		Compensation
Position	Year	Salary ($)		Bonus ($)		(1)  ($)		($) (2) (3)		Total ($)
	2019	$	250,000	$	30,000	$	229,010	$	24,000	$	533,010
Kelly Hoffman,
Chief Executive Officer	2018		235,000		—		407,615		24,000		666,615
	2017		205,000		—		618,240		24,000		259,000
	2019		225,000		30,000		143,448		24,000		422,448
David Fowler,
President	2018		200,000		—		265,768		24,000		489,768
	2017		175,000		—		403,200		24,000		602,200
	2019		225,000		20,000		143,448				388,448
Daniel D. Wilson,
Executive Vice President	2018		200,000		—		265,768				465,768
	2017		175,000		—		403,200		—		578,200
	2019		195,000		20,000		143,448		4,875		363,323
William R. Broaddrick,
Chief Financial Officer	2018		175,000		—		265,768		—		440,768
	2017		145,000		—		403,200		—		548,200
	2019		45,000		—		334,755		48,000		427,755
Lloyd. T. Rochford,
Chairman of the Board	2018		—		—		620,205		40,500		660,705
	2017		—		—		940,800		36,000		976,800

(1) See discussion of assumptions made in valuing these awards in the notes to our financial statements.

(2) Other Compensation for Messrs. Hoffman, Fowler and Rochford consists of director’s fees.

(3) Other Compensation for Mr. Broaddrick consists of the contributions by the Company match into the Company's sponsored 401(k) plan. Subject to IRS limits, Company contributions to each employee's 401(k) account consist of a matching contribution of up to 6% of the employee's eligible salary.

The Company awards equity through the grant of stock options or restricted stock to key employees and the Named Executive Officers either on the initial date of employment or based on performance incentives throughout the year. The following table reflects the restricted stock granted during 2019.

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Grants of Plan-Based Awards

	Date of Board			Fair Value on
Name	approval	Grant Date	Restricted stock grants (#)	Grant Date
Kelly Hoffman	12/21/2019	12/21/2019	85,275	$	220,010
David Fowler	12/21/2019	12/21/2019	55,600		143,448
Daniel D. Wilson	12/21/2019	12/21/2019	55,600		143,448
William R. Broaddrick	12/21/2019	12/21/2019	55,600		143,448
Lloyd T. Rochford	12/21/2019	12/21/2019	129,750		334,755

Named Executive Officers are not separately entitled to receive dividend equivalent rights with respect to each stock option. Each nonqualified stock option award described in the “Grants of Plan-Based Awards Table” above expires ten years from the grant date and vests in equal installments over the course of five years.

The following table provides certain information regarding unexercised stock options outstanding for each Named Executive Officer as of December 31, 2019.

Outstanding Option Awards

	Number of Securities	Number of Securities
	Underlying	Underlying Unexercised	Options			Option
	Unexercised Options	Options (#)	Exercise Price		Option Grant	Expiration
Name	(#) Exercisable	Unexercisable	($)		Date	Date
Kelly Hoffman	500,000	—	$	4.50	01/01/13	01/01/23
	25,000	—		10.00	12/16/13	12/16/23
	30,000	—		8.00	12/01/14	12/01/24
	45,000	30,000		11.75	12/13/16	12/13/26
David Fowler	500,000	—		4.50	01/01/13	01/01/23
	25,000	—		10.00	12/16/13	12/16/23
	30,000	—		8.00	12/01/14	12/01/24
	30,000	20,000		11.75	12/13/16	12/13/26
Daniel D. Wilson	300,000	—		4.50	01/01/13	01/01/23
	20,000	—		10.00	12/16/13	12/16/23
	25,000	—		8.00	12/01/14	12/01/24
	30,000	20,000		11.75	12/13/16	12/13/26
William R. Broaddrick	60,000	—		2.00	12/01/11	12/01/21
	40,000	—		4.50	08/15/12	08/15/22
	20,000	—		10.00	12/16/13	12/16/23
	25,000	—		8.00	12/01/14	12/01/24
	24,000	16,000		11.75	12/13/16	12/13/26
Lloyd T. Rochford	100,000	—		2.00	12/01/11	12/01/21
	40,000	—		8.00	12/01/14	12/01/24
	25,000	—		8.25	12/09/15	12/09/25
	150,000	60,000		11.75	12/13/16	12/13/26

The following table provides certain information regarding unvested restricted stock outstanding for each Named Executive Officer as of December 31, 2019. All restricted stock awards vest at the rate of 20% each year over five years beginning one year from the date granted and expire ten years from the grant date.

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Outstanding Unvested Restricted Stock Awards

	Unvested Restricted
Name	Stock Grants	Grant  Date
Kelly Hoffman	27,600	12/19/17
	68,220	12/26/18
	85,275	12/21/19
David Fowler	18,000	12/19/17
	44,480	12/26/18
	55,600	12/21/19
Daniel D. Wilson	18,000	12/19/17
	44,480	12/26/18
	55,600	12/21/19
William R. Broaddrick	18,000	12/19/17
	44,480	12/26/18
	55,600	12/21/19
Lloyd T. Rochford	42,000	12/19/17
	103,800	12/26/18
	129,750	12/21/19

We use the Black-Scholes option pricing model to calculate the fair-value of each option grant. The expected volatility is based on the historical price volatility of our Common Stock. We elected to use the simplified method for estimating the expected term as allowed by generally accepted accounting principles for options granted during the years ended December 31, 2017. Under the simplified method, the expected term is equal to the midpoint between the vesting period and the contractual term of the stock option. The risk-free interest rate represents the U.S. Treasury bill rate for the expected life of the related stock options. The dividend yield represents the Company’s anticipated cash dividend over the expected life of the stock options. The following are the Black-Scholes weighted-average assumptions used for options granted during the periods ended December 31, 2017:

	Risk free interest rate		Expected life (years)	Dividend yield	Volatility
April 20, 2017	1.78	%	6.5	—	94	%

No options were granted during 2018 or 2019.

For the years ended December 31, 2019, 2018 and 2017, the Company incurred stock based compensation expense related to stock options of $621,167, $1,853,913 and $3,618,309, respectively.  As of December 31, 2019, there was $702,934 of unrecognized compensation cost related to stock options that will be recognized over a weighted average period of 1.5 years. The aggregate intrinsic value of options vested and expected to vest at December 31, 2019 was $278,400. The aggregate intrinsic value of options exercisable at December 31, 2018 was $278,400. The year-end intrinsic values are based on a December 31, 2019 closing price of $2.64.

Options exercised of 193,000 in 2018 and 165,400 in 2017 had an aggregate intrinsic value on the date of exercise of $1,470,230 and $1,744,047, respectively.  No options were exercised in 2019.

For the years ended December 31, 2019, 2018 and 2017, the Company incurred stock based compensation expense related to restricted stock grants of $2,456,458, $2,017,021 and $66,770.  As of December 31, 2019, there was $4,451,903 of unrecognized compensation cost related to restricted stock grants that will be recognized over a weighted average period of 1.8 years.

During 2019 and 2018, 187,136 and 64,620 shares of restricted stock vested, respectively.  At the dates of vesting those shares were had an aggregate intrinsic value of $494,605 and $304,360, respectively.  No restricted stock vested during 2017.

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Executive Stock Compensation Plans

Please refer to the table set forth in Item 12 of this Annual Report for information concerning securities authorized for issuance under our executive stock compensation plan as of December 31, 2019.

Long Term Incentive Plan

The Ring Energy, Inc. Long Term Incentive Plan (the “Plan”) was in existence with Stanford Energy, Inc. (“Stanford”) and was adopted by the Board on June 27, 2012, and assumed by the Company upon the acquisition of Stanford. The Plan was also approved by vote of a majority of stockholders on January 22, 2013. The following is a summary of the material terms of the Plan.

Shares Available

Our Plan currently authorizes 5,000,000 shares of our Common Stock for issuance under the Plan. If any shares of Common Stock subject to an Award are forfeited or if any Award based on shares of Common Stock is otherwise terminated without issuance of such shares of Common Stock or other consideration in lieu of such shares of Common Stock, the shares of Common Stock subject to such Award shall to the extent of such forfeiture or termination, again be available for awards under the Plan if no participant shall have received any benefits of ownership in respect thereof. The shares to be delivered under the Plan shall be made available from (a) authorized but unissued shares of Common Stock, (b) Common Stock held in the treasury of the Company, or (c) previously issued shares of Common Stock reacquired by the Company, including shares purchased on the open market, in each situation as the Board of Directors or the Compensation Committee may determine from time to time at its sole option.

Administration

The Committee shall administer the Plan with respect to all eligible individuals or may delegate all or part of its duties under the Plan to a subcommittee or any executive officer of the Company, subject in each case to such conditions and limitations as the Board of Directors may establish. Under the Plan, “Committee” can be either the Board of Directors or a committee approved by the Board of Directors.

Eligibility

Awards may be granted pursuant to the Plan only to persons who are eligible individuals at the time of the grant thereof or in connection with the severance or retirement of Eligible Individuals. Under the Plan, “Eligible Individuals” means (a) employees, (b) non-employee Directors and (c) any other person that the Committee designates as eligible for an Award (other than for Incentive Options) because the Person performs bona fide consulting or advisory services for the Company or any of its subsidiaries (other than services in connection with the offer or sale of securities in a capital raising transaction).

Stock Options

Under the Plan, the plan administrator is authorized to grant stock options. Stock options may be either designated as non-qualified stock options or incentive stock options. Incentive stock options, which are intended to meet the requirements of Section 422 of the Code such that a participant can receive potentially favorable tax treatment, may only be granted to employees. Therefore, any stock option granted to consultants and non-employee directors are non-qualified stock options.

Options granted under the Plan become exercisable at such times as may be specified by the plan administrator. In general, options granted to participants become exercisable in five equal annual installments, subject to the optionee’s continued employment or service with our Company. However, the aggregate value (determined as of the grant date) of the shares subject to incentive stock options that may become exercisable by a participant in any year may not exceed $100,000.

Each option will be exercisable on such date or dates, during such period, and for such number of shares of Common Stock as shall be determined by the plan administrator on the day on which such stock option is granted and set forth in the option agreement with respect to such stock option; provided, however the maximum term of options granted under the Plan is ten years.

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Restricted Stock

Under the Plan, the plan administrator is also authorized to make awards of restricted stock. Before the end of a restricted period and/or lapse of other restrictions established by the plan administrator, shares received as restricted stock will contain a legend restricting their transfer, and may be forfeited in the event of termination of employment or upon the failure to achieve other conditions set forth in the award agreement.

An award of restricted stock will be evidenced by a written agreement between us and the participant. The award agreement will specify the number of shares of Common Stock subject to the award, the nature and/or length of the restrictions, the conditions that will result in the automatic and complete forfeiture of the shares and the time and manner in which the restrictions will lapse, subject to the participant’s continued employment by us, and any other terms and conditions the plan administrator imposes consistent with the provisions of the Plan. Upon the lapse of the restrictions, any legends on the shares of Common Stock subject to the award will be re-issued to the participant without such legend.

The plan administrator may impose such restrictions or conditions to the vesting of such shares as it, in its absolute discretion, deems appropriate. Prior to the vesting of a share of restricted stock granted under the Plan, no transfer of a participant’s rights to such share, whether voluntary or involuntary, by operation of law or otherwise, will vest the transferee with any interest, or right in, or with respect to, such share, but immediately upon any attempt to transfer such rights, such share, and all the rights related thereto, will be forfeited by the participant and the transfer will be of no force or effect; provided, however, that the plan administrator may, in its sole and absolute discretion, vest in the participant all or any portion of shares of restricted stock which would otherwise be forfeited.

Fair Market Value

Under the Plan, “Fair Market Value” means, for a particular day, the value determined in good faith by the plan administrator, which determination shall be conclusive for all purposes of the Plan. For purposes of valuing incentive options, the fair market value of stock: (i) shall be determined without regard to any restriction other than one that, by its terms, will never lapse; and (ii) will be determined as of the time the option with respect to such stock is granted.

Transferability Restrictions

Notwithstanding any limitation on a holder’s right to transfer an award, the plan administrator may (in its sole discretion) permit a holder to transfer an award, or may cause the Company to grant an award that otherwise would be granted to an eligible individual, in any of the following circumstances: (a) pursuant to a qualified domestic relations order, (b) to a trust established for the benefit of the eligible individual or one or more of the children, grandchildren or spouse of the eligible individual; (c) to a limited partnership or limited liability company in which all the interests are held by the eligible individual and that person’s children, grandchildren or spouse; or (d) to another person in circumstances that the plan administrator believes will result in the award continuing to provide an incentive for the eligible individual to remain in the service of the Company or its subsidiaries and apply his or her best efforts for the benefit of the Company or its subsidiaries. If the plan administrator determines to allow such transfers or issuances of awards, any holder or eligible individual desiring such transfers or issuances shall make application therefore in the manner and time that the plan administrator specifies and shall comply with such other requirements as the plan administrator may require to assure compliance with all applicable laws, including securities laws, and to assure fulfillment of the purposes of the Plan. The plan administrator shall not authorize any such transfer or issuance if it may not be made in compliance with all applicable federal and state securities laws. The granting of permission for such an issuance or transfer shall not obligate the Company to register the shares of stock to be issued under the applicable award.

Termination and Amendments to the Plan

The Board of Directors may (insofar as permitted by law and applicable regulations), with respect to any shares which, at the time, are not subject to awards, suspend or discontinue the Plan or revise or amend it in any respect whatsoever, and may amend any provision of the Plan or any award agreement to make the Plan or the award agreement, or both, comply with Section 16(b) of the Exchange Act and the exemptions therefrom, the Code, the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), the regulations promulgated under the Code or ERISA, or any other law, rule or regulation that may affect the Plan. The Board of Directors may also amend, modify, suspend or terminate the Plan for the purpose of meeting or addressing any changes in other legal requirements applicable to the Company or the Plan or for any other purpose permitted by law. The Plan may not be amended without the consent of the holders of a majority of the shares of Common Stock then outstanding to increase materially the aggregate number of shares of stock that may be issued under the Plan except for certain adjustments.

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Our Board and Compensation Committee retain discretion, with respect to shares not yet subject to awards, to impose a “second trigger” or other conditions in any future awards agreements in various circumstances, such as when an employees’ employment is not terminated upon a change in control.

CEO PAY RATIO

As required by Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2012, and Item 402(u) of Regulation S-K, we are providing the following information about the relationship of the annual total compensation of the Company’s employees and the annual total compensation of Kelly Hoffman, our CEO, for 2019:

Median Employee total annual compensation	$	125,405
Total Compensation of Chief Executive Officer - Kelly Hoffman	$	500,010
Ratio of CEO to Median Employee compensation		3.99 to 1

To identify the median of the annual total compensation of all our employees, as well as to determine the annual total compensation of our median employee and our CEO, we took the following steps:

● We determined that, as of December 31, 2019, our employee population consisted of 56 individuals with all of these individuals located in the U.S. This population consisted of our full-time and part-time employees, as we do not have temporary or seasonal workers. We selected December 31, 2019, as our identification date for determining our median employee because it enabled us to make such identification in a reasonably efficient and economic manner.

● We used a consistently applied compensation measure to identify our median employee by comparing the amount of salary or wages, bonuses and restricted stock awards granted in 2019 as reflected in our payroll records. To make them comparable, salaries for newly hired employees who had worked less than one year were annualized and the target incentive amount was applied to their total compensation measure.

● We identified our median employee by consistently applying this compensation measure to all of our employees included in our analysis. Since all of our employees, including our CEO, are located in the U.S., we did not make any cost of living adjustments in identifying the median employee.

● After we identified our median employee, we combined all of the elements of such employee’s compensation for the 2019 year in accordance with the requirements of Item 402(c)(2)(x) of Regulation S-K, resulting in annual total compensation of $125,405.

● With respect to the annual total compensation of our CEO, we used salary, bonus, restricted stock and stock option awards granted and all other compensation for the 2018 year in accordance with the requirements of Item 402(c)(2)(x) of Regulation S-K, resulting in annual total compensation of $500,010.

Director Compensation

Inside directors receive a monthly stipend of $2,000.  Outside directors receive a monthly stipend of $3,000. Additionally, each outside director receives an additional $500 per month for each Committee in which such director serves as a member.  In 2019, each outside director also received 55,600 shares of restricted stock as an annual bonus.  The stock options and restricted stock granted to our directors vest over a period of five (5) years. Director compensation to Messrs. Fowler, Hoffman and Rochford is included here but is also included in the executive compensation schedule above. No director receives a salary as a director.

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Director Compensation Table

		Fees Earned or Paid		Equity Awards		All Other
Name		in Cash ($)		($) (1)		Compensation ($)		Total ($)
Lloyd T. Rochford	(2)​	$	48,000	$	334,755	$	45,000	$	427,755
Stanley M. McCabe	(3)​		58,500		143,448		—		201,948
David A. Fowler	(4)​		24,000		143,448		—		167,448
Kelly Hoffman	(5)​		24,000		220,010		—		244,010
Clayton E. Woodrum	(6)​		43,500		143,448		—		186,948
Anthony B. Petrelli	(7)​		43,500		143,448		—		186,948
Regina Roesener	(8)​		13,500		158,148		—		171,648

(1) See discussion of assumptions made in valuing these awards in the notes to our financial statements.

(2) Lloyd T. Rochford has 315,000 options to purchase Ring stock and 216,130 shares of unvested restricted stock.

(3) Stanley McCabe has 215,000 options to purchase Ring stock and 118,080 shares of unvested restricted stock.

(4) David A. Fowler has an aggregate of 605,000 options to purchase Ring stock and 118,080 shares of unvested restricted stock.

(5) Kelly Hoffman has an aggregate of 630,000 options to purchase Ring stock and 181,095 shares of unvested restricted stock.

(6) Clayton E. Woodrum has 175,000 options to purchase Ring stock and 118,080 shares of unvested restricted stock.

(7) Anthony B. Petrelli has 140,000 options to purchase Ring stock and 118,080 shares of unvested restricted stock.

(8) Regina Roesener has 65,600 shares of unvested restricted stock.

Compensation Committee Report

Among the duties imposed on our Compensation Committee under its charter is the direct responsibility and authority to review and approve the Company’s goals and objectives relevant to the compensation of the Company’s Chief Executive Officer and other executive officers, to evaluate the performance of such officers in accordance with the policies and principles established by the Compensation Committee and to determine and approve, either as a Committee, or (as directed by the Board) with the other “independent” Board members (as defined by the NYSE American listing standards), the compensation level of the Chief Executive Officer and the other executive officers. During 2019, the Compensation Committee was comprised of the two non-employee Directors named at the end of this report each of whom is “independent” as defined by the NYSE American listing standards.

The Compensation Committee has reviewed and discussed with management the disclosures contained in the Compensation Discussion and Analysis section of this Item 11, as required by Item 402(b) of Regulation S-K. Based upon this review and our discussions, the Compensation Committee recommended to its Board of Directors that the Compensation Discussion and Analysis section be included in this annual report on Form 10-K for the fiscal year ended December 31, 2019.

Compensation Committee of the Board of Directors

Stanley McCabe (Chair)

Clayton E. Woodrum

(1)SEC filings sometimes “incorporate information by reference.” This means the Company is referring you to information that has previously been filed with the SEC, and that this information should be considered as part of the filing you are reading. Unless the Company specifically states otherwise, this Compensation Committee Report shall not be deemed to be incorporated by reference and shall not constitute soliciting material or otherwise be considered filed under the Securities Act of 1933 as amended, or the Securities Exchange act of 1934, as amended.

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Compensation Committee Interlocks and Insider Participation

As of December 31, 2019, the Compensation Committee was comprised of two directors, Messrs. McCabe and Woodrum, with Mr. McCabe acting as the chairman. Messrs. McCabe and Woodrum are currently serving as the members of the Compensation Committee. Neither of our directors who currently serve as members of our Compensation Committee is, or has at any time in the past been, an officer or employee of the Company or any of its subsidiaries. The office space being leased by the Company in Tulsa, Oklahoma, is owned by Arenaco, LLC, a company that is co-owned by Mr. Rochford, Chairman of the Board of the Company, and Mr. McCabe, a director of the Company. During the years ended December 31, 2017 through December 31, 2019, the Company paid an aggregate of $180,000 to Arenaco, LLC.

None of our executive officers serves, or has served, during the last completed fiscal year, on the compensation committee or board of directors of any other company that has one or more executive officers serving on our Compensation Committee or Board.

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

Securities Authorized for Issuance Under Equity Compensation Plan

The following table sets forth information concerning our executive stock compensation plans as of December 31, 2019.

	Restricted	Number of securities			Number of securities remaining
	stock granted	to be issued upon	Weighted-average		available for future issuance under
	that has not	exercise of	exercise price of		compensation plans (excluding
	vested	outstanding options	outstanding options		securities in column (a))
Equity compensation plans approved by security holders	1,341,889	2,748,500	$	6.28	28,955
Equity compensation plans not approved by security holders	—	—		—	—
Total	1,341,889	2,748,500	$	6.28	28,955

The Plan was in existence with Stanford and was adopted by the Board of Directors on June 27, 2012, and assumed by the Company upon the acquisition of Stanford. The Plan was subsequently approved by vote of a majority of stockholders on January 22, 2013. Information regarding the material terms of this plans may be found in this Annual Report under Part III, Item 11.

Security Ownership of Certain Beneficial Owners and Management

The following table sets forth certain information furnished by current management and others, concerning the ownership of our Common Stock by (i) each person who is known to us to be the beneficial owner of more than five percent (5%) of our Common Stock, without regard to any limitations on conversion or exercise of convertible securities or warrants; (ii) all directors and Named Executive Officers; and (iii) our directors and executive officers as a group. The mailing address for each of the persons indicated in the table below is our corporate headquarters. The percentage ownership is based on shares outstanding at March 3, 2020.

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Beneficial ownership is determined under the rules of the SEC. In general, these rules attribute beneficial ownership of securities to persons who possess sole or shared voting power and/or investment power with respect to those securities and includes, among other things, securities that an individual has the right to acquire within 60 days. Unless otherwise indicated, the stockholders identified in the following table have sole voting and investment power with respect to all shares shown as beneficially owned by them.

	Shares of Common Stock
	Beneficially Owned
Name of Beneficial Owners	Number		Percent
Blackrock, Inc.	9,403,401	(1)​	13.8	%
55 East 52nd Street
New York, NY  10055
Dimensional Fund Advisors LP	3,996,644	(2)​	5.9	%
Building One, 6300 Bee Cave Road
Austin, TX  78746
PEDEVCO Group	6,624,318	(3)​	9.7	%
575 N. Dairy Ashford, Energy Center II, Suite 210
Houston, TX 77079
The Vanguard Group	3,712,606	(4)​	5.5	%
100 Vanguard Blvd.
Malvern, PA 19355

(1) Based on the Schedule 13G/A filed on February 4, 2020, BlackRock, Inc. (“BlackRock”) may be deemed to be the beneficial owner of 9,403,401 shares.  BlackRock reports sole voting power over 9,304,648 shares and sole dispositive power over 9,403,401 shares.

(2) Based on the Schedule 13G/A filed on February 12, 2020, Dimensional Fund Advisors LP (“Dimensional”) may be deemed to be the beneficial owner of 3,996,644 shares.  Dimensional reports sole voting power over 3,928,898 shares and sole dispositive power over 3,996,644 shares.

(3) Based on the Schedule 13D/A filed on March 2, 2020, PEDEVCO Group may be deemed to be the beneficial owner of 6,624,318 shares.  The PEDEVCO Group reports sole voting and dispositive power over all 6,624,318 shares.

(3) Based on the Schedule 13G filed on January 28, 2019, The Vanguard Group (“Vanguard”) may be deemed to be the beneficial owner of 3,712,606 shares.  Vanguard reports sole voting power over 87,648 shares, sole dispositive power over 3,634,381 shares and shares dispositive power over 78,225 shares.

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	Shares of Common Stock
	Beneficially Owned
Name	Number		Percent
Kelly Hoffman	705,001	(1)​	1	%
David A. Fowler	761,020	(2)​	1	%
Daniel D. Wilson	448,600	(3)​	1	%
William R. Broaddrick	242,120	(4)​	*
Lloyd T. Rochford	1,653,950	(5)​	2	%
Stanley M. McCabe	1,903,754	(6)​	3	%
Anthony B. Petrelli	258,120	(7)​	*
Clayton E. Woodrum	187,968	(8)​	*
Regina Roesener	16,000		*
All directors and executive officers as a group (9 persons)	6,176,533	(9)​	9	%

*             Represents beneficial ownership of less than 1%.

(1) Includes 600,000 shares issuable upon the exercise of stock options that are currently exercisable.

(2) Includes 585,000 shares issuable upon the exercise of stock options that are currently exercisable.

(3) Includes 375,000 shares issuable upon the exercise of stock options that are currently exercisable.

(4) Includes 169,000 shares issuable upon the exercise of stock options that are currently exercisable.

(5) Includes (i) 250,000 shares issuable upon the exercise of stock options that are currently exercisable and (ii) 1,403,950 shares held by a family trust controlled by Mr. Rochford.

(6) Includes (i) 190,000 shares issuable upon the exercise of stock options that are currently exercisable and (ii) 1,713,754 shares held by a family trust controlled by Mr. McCabe.

(7) Includes 120,000 shares issuable upon the exercise of stock options that are currently exercisable.

(8) Includes (i) 137,000 shares issuable upon the exercise of stock options that are currently exercisable, (ii) 3,648 shares held by the Patricia Woodrum Trust and (iii) 29,320 shares held by the Clayton Woodrum Trust.

(9) Includes 2,444,000 shares issuable upon the exercise of stock options that are currently exercisable.

Changes in Control

There are no arrangements known to us, including any pledge by any person of our securities, the operation of which may at a subsequent date result in a change in control of the Company.

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

Transactions with Related Persons

The office space being leased by the Company in Tulsa, Oklahoma, is owned by Arenaco, LLC, a company that is owned by Mr. Rochford, Chairman of the Board of the Company, and Mr. McCabe, a Director of the Company. During the years ended December 31, 2019, 2018 and 2017, the Company paid an aggregate of $180,000 to Arenaco, LLC for the lease of the office space.

The Audit Committee reviews any related party transactions. Annually, each Board member is required to submit an Independence Certificate, disclosing any affiliations or relationships for evaluation as possible related party transactions.

Review, Approval or Ratification of Transactions with Related Parties

The Board of Directors reviews and approves all relationships and transactions in which it and its directors, director nominees and executive officers and their immediate family members, as well as holders of more than 5% of any class of its voting securities and their family members, have a direct or indirect material interest. In approving or rejecting such proposed relationships and transactions, the Board shall consider the relevant facts and circumstances available and deemed relevant to this determination. In each case the standard applied in approving the transaction is the best interests of the Company without regard to the interests of the individual officer or director involved in the transaction. These procedures for reviewing and approving conflict of interest transactions are based on the Company’s past practice and are not contained in any written policy.

Director Independence

The standards relied upon by the Board in determining whether a director is “independent” are those set forth in the rules of the NYSE American. The NYSE American generally defines the term “independent director” as a person other than an executive officer or employee of a company, who does not have a relationship with the company that would interfere with the director’s exercise of independent judgment in carrying out the responsibilities of a director. Because the Board of Directors believes it is not possible to anticipate or provide for all circumstances that might give rise to conflicts of interest or that might bear on the materiality of a relationship between a director and the Company, the Board has not established specific objective criteria, apart from the criteria set forth in the NYSE American rules, to determine “independence”. In addition to such criteria, in making the determination of “independence”, the Board of Directors considers such other matters including (i) the business and non-business relationships that each independent director has or may have had with the Company and its other Directors and executive officers, (ii) the stock ownership in the Company held by each such Director, (iii) the existence of any familial relationships with any executive officer or Director of the Company, and (iv) any other relevant factors which could cause any such Director to not exercise his independent judgment.

Consistent with these standards, the Board of Directors has determined that Messrs. Woodrum, Petrelli and McCabe and Mrs. Roesener are each “independent” directors within the meaning of the NYSE American definition of independent director set forth in the Company Guide, Part 8, Section 803(A).

Item 14:     Principal Accounting Fees and Services

The Audit Committee selected Eide Bailly as its independent registered public accounting firm for the fiscal years ended December 31, 2017, 2018 and 2019. The Audit Committee has adopted a policy that requires advance approval of all audit, audit-related, tax services and other services performed by the independent auditor.

Fees and Independence

Audit Fees. Eide Bailly billed the Company an aggregate of $149,000 for professional services rendered for the review of the Company’s financial statements included in its Form 10-Q’s for 2018 and the audit of the Company’s financial statements for the year ended December 31, 2018 and an aggregate of $165,000 for professional services rendered for the review of the Company’s financial statements included in its Form 10-Q’s for 2019 and the audit of the Company’s financial statements for the year ended December 31, 2019.

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Audit Related Fees. Eide Bailly billed the Company $16,601 and $34,200 for the years ended December 31, 2018 and 2019 for services related to the Company’s filing of registration statements and a Form 8-K related to an acquisition.

Tax Fees. Eide Bailly billed the Company $10,500 and $11,500, respectively, for professional services rendered for tax compliance, tax advice and tax planning for the years ended December 31, 2018 and 2019.

All Other Fees. No other fees were billed by Eide Bailly to the Company during 2018 and 2019.

The Audit Committee of the Board of Directors has determined that the provision of services by Eide Bailly described above is compatible with maintaining Eide Bailly’s independence as the Company’s principal accountant. The policy of the Audit Committee and our Board, as applicable, is to pre-approve all services by our independent registered public accounting firm. The Audit Committee has adopted a pre-approval policy that provides guidelines for the audit, audit-related, tax and other non-audit services that may be provided by our independent registered public accounting firm. The policy (a) identifies the guiding principles that must be considered by the Audit Committee in approving services to ensure that the independent registered public accounting firm’s independence is not impaired; (b) describes the audit, audit-related, tax and other services that may be provided and the non-audit services that are prohibited; and (c) sets forth the pre-approval requirements for all permitted services. Under the policy, all services to be provided by our independent registered public accounting firm must be pre-approved by the Audit Committee; the Company obtained all required approvals during 2019.

PART IV

Item 15:     Exhibits, Financial Statement Schedules

(a)Financial Statements

The following financial statements are filed with this Annual Report:

Report of Independent Registered Public Accounting Firm

Balance Sheets at December 31, 2019 and 2018

Statements of Operations for the years ended December 31, 2019, 2018 and 2017

Statements of Stockholders’ Equity for the years ended December 31, 2019, 2018 and 2017

Statements of Cash Flows for the year ended December 31, 2019, 2018 and 2017

Notes to Financial Statements

Supplemental Information on Oil and Gas Producing Activities

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		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	File No.	Exhibit	Filing Date	Filed Here-with
2.1	Stock for Stock Exchange Agreement dated May 3, 2012	8-K	000-53920	2.1	7/5/12
2.2	Merger Agreement dated November 7, 2012	8-K	000-53920	2.1	11/26/12
2.3	Purchase and Sale Agreement, dated February 25, 2019 by and among Ring Energy, Inc. and Wishbone Energy Partners, LLC, Wishbone Texas operating Company LLC and WB WaterWorks, LLC	8-K	001-36057	2.1	02/28/19
3.1	Articles of Incorporation (as amended)	10-K	000-53920	3.1	4/1/13
3.2	Current Bylaws	8-K	000-53920	3.2	1/24/13
4.1	Registration Rights Agreement, dated April 9, 2019 by and between Ring Energy, Inc. and Wishbone Energy Partners, LLC	10-Q	001-36057	4.1	5/8/19
4.2	Description of Ring Energy, Inc. equity securities registered under Section 12(b) of the Securities Exchange Act of 1934, as amended				X
10.1	Letter Agreement with Patriot Royalty & Land, LLC entered into on March 1, 2012	10-K	000-53920	10.1	3/20/12
10.2*	Ring Energy Inc. Long Term Incentive Plan, as Amended	8-K	000-53920	99.3	1/24/13
10.3*	Form of Option Grant for Long-Term Incentive Plan	10-Q	000-53920	10.2	8/14/12
10.4	Executive Committee Charter	10-K	000-53920	3.1	4/1/13
10.5	Audit Committee Charter	10-K	000-53920	3.1	4/1/13
10.6	Compensation Committee Charter	10-K	000-53920	3.1	4/1/13
10.7	Nominating and Corporate Governance Committee Charter	10-K	000-53920	3.1	4/1/13
10.8	Credit Agreement dated July 1, 2014 with SunTrust Bank	8-K	001-36057	10.1	7/3/14
10.9	First Amendment to Credit Agreement with SunTrust Bank	8-K	001-36057	10.1	6/29/15
10.10	Second Amendment to Credit Agreement with SunTrust Bank	8-K	001-36057	10.1	7/29/15
10.11	Third Amendment to Credit Agreement with SunTrust Bank	8-K	001-36057	10.1	5/20/16
10.12	Development Agreement with Torchlight Energy Resources, Inc.	8-K	001-36057	10.1	10/18/13
10.13	Purchase and Sale Agreement, dated February 4, 2014, between Ring Energy, Inc. and Raw Oil & Gas, Inc., JDH Raw LC, and Smith Energy Company	8-K	001-36057	10.1	2/7/14
10.14	Purchase and Sale Agreement effective May 1, 2015, with Finley Production Co., LP, BDT Oil & Gas, LP, Metcalfe Oil, LP, Grasslands Energy, LP, Buffalo Oil & Gas, LP and Finley Resources, Inc.	8-K	001-36057	2.1	5/22/15
10.15	Fifth Amendment to Credit Agreement with SunTrust Bank	8-K	001-36057	10.1	6/19/18
10.16	Commitment Letter dated February 24, 2019, between Ring Energy, Inc., SunTrust Bank and SunTrust Robinson Humphrey, Inc.	8-K	001-36057	2.1	02/28/19
10.17	Amended and Restated Credit Agreement with SunTrust Bank	10-Q	001-36057	10.2	5/8/19

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10.18	First Amendment to Amended and Restated Credit Agreement with SunTrust Bank	8-K	001-36057	10.1	12/9/19
14.1	Code of Ethics	8-K	000-53920	14.1	1/24/13
16.1	Letter dated April 19, 2012, from Haynie & Company	8-K	000-53920	16.1	4/19/12
23.1	Consent of Cawley, Gillespie & Associated, Inc.					X
23.2	Consent of Eide Bailly LLC					X
23.3	Consent of Moss Adams LLP	8-K/A	001-36057	23.1	6/19/19
31.1	Rule 13a-14(a) Certification by Chief Executive Officer					X
31.2	Rule 13a-14(a) Certification by Chief Financial Officer					X
32.1	Section 1350 Certification of Chief Executive Officer					X
32.2	Section 1350 Certification Chief Financial Officer					X
99.1	Reserve Report of Cawley, Gillespie & Associates, Inc.					X
101.INS	Inline XBRL Instance Document					X
101.SCH	Inline XBRL Taxonomy Extension Schema Document					X
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document					X
101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document					X
101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document					X
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document					X
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

* Management contract

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SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on behalf by the undersigned, thereunto duly authorized.

Ring Energy, Inc.
By:	/s/ Kelly Hoffman
Mr. Kelly Hoffman
Chief Executive Officer
Date:  March 16, 2020
By:	/s/ William R. Broaddrick
Mr. William R. Broaddrick
Chief Financial Officer
Date:  March 16, 2020

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.

/s/ Lloyd T. Rochford	/s/ Anthony B. Petrelli
Mr. Lloyd T. Rochford	Mr. Anthony B. Petrelli
Director	Director
Date:  March 16, 2020	Date:  March 16, 2020
/s/ Stanley McCabe	/s/ David A. Fowler
Mr. Stanley McCabe	Mr. David A. Fowler
Director	Director
Date:  March 16, 2020	Date:  March 16, 2020
/s/ Clayton E. Woodrum	/s/ Kelly Hoffman
Mr. Clayton E. Woodrum	Mr. Kelly Hoffman
Director	Director
Date:  March 16, 2020	Date:  March 16, 2020
/s/ Regina Roesener
Mrs. Regina Roesener
Director
Date: March 16, 2020

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RING ENERGY, INC.

INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets	F-4
Statements of Operations	F-5
Statements of Stockholders’ Equity	F-6
Statements of Cash Flows	F-7
Notes to Financial Statements	F-8
Supplemental Information on Oil and Natural Gas Producing Activities	F-56

F-1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and

Stockholders of Ring Energy, Inc.

Midland, Texas

Opinion on the Financial Statements and Internal Control Over Financial Reporting

We have audited the accompanying balance sheets of Ring Energy, Inc. (Ring Energy) as of December 31, 2019 and 2018, and the related statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of Ring Energy as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

We also have audited Ring Energy’s internal control over financial reporting as of 2019, based on criteria established in 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, Ring Energy maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in 2013 Internal Control—Integrated Framework issued by COSO.

Basis for Opinion

Ring Energy’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’ Annual Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express an opinion on the entity’s financial statements and an opinion on the entity’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to Ring Energy in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that responds to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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7001 E. Belleview Ave., Ste. 700 | Denver, CO 80237-2733 | TF 866.740.4100 | T 303.770.5700 | F 303.770.7581 | EOE

Definition and Limitations of Internal Control Over Financial Reporting

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

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

We have served as Ring Energy’s auditor since 2013.

Denver, Colorado

March 16, 2020

F-3

RING ENERGY, INC.

BALANCE SHEETS

As of December 31,	2019		2018
ASSETS
Current Assets
Cash	$	10,004,622	$	3,363,726
Accounts receivable		22,909,195		12,643,478
Joint interest billing receivable		1,812,469		578,144
Prepaid expenses and retainers		3,982,255		258,909
Total Current Assets		38,708,541		16,844,257
Properties and Equipment
Oil and natural gas properties subject to amortization		1,083,966,135		641,121,398
Financing lease asset subject to depreciation		858,513		—
Fixed assets subject to depreciation		1,465,551		1,465,551
Total Properties and Equipment		1,086,290,199		642,586,949
Accumulated depreciation, depletion and amortization		(157,074,044)		(100,576,087)
Net Properties and Equipment		929,216,155		542,010,862
Operating lease asset		1,867,044		—
Deferred Income Taxes		—		7,786,479
Deferred Financing Costs		3,214,408		424,061
Total Assets	$	973,006,148	$	567,065,659
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	54,635,602	$	51,910,432
Financing lease liability		280,970		—
Operating lease liability		1,175,904		—
Derivative liabilities		3,000,078		—
Total Current Liabilities		59,092,554		51,910,432
Deferred income taxes		6,001,176		—
Revolving line of credit		366,500,000		39,500,000
Financing lease liability, less current portion		424,126		—
Operating lease liability, less current portion		691,140
Asset retirement obligations		16,787,219		13,055,797
Total Liabilities		449,496,215		104,466,229
Stockholders’ Equity
Preferred stock - $0.001 par value; 50,000,000 shares authorized; 0 shares issued or outstanding		—		—
Common stock - $0.001 par value; 150,000,000 shares authorized; 67,993,797 shares and 63,229,710 shares issued and outstanding, respectively		67,994		63,230
Additional paid-in capital		526,301,281		494,892,093
Accumulated deficit		(2,859,342)		(32,355,893)
Total Stockholders’ Equity		523,509,933		462,599,430
Total Liabilities and Stockholders’ Equity	$	973,006,148	$	567,065,659

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

F-4

RING ENERGY, INC.

STATEMENTS OF OPERATIONS

For the years ended December 31,	2019		2018		2017
Oil and Natural Gas Revenues	$	195,702,831	$	120,065,361	$	66,699,700
Costs and Operating Expenses
Oil and natural gas production costs		48,496,225		27,801,989		15,978,362
Oil and natural gas production taxes		9,130,379		5,631,093		3,152,562
Depreciation, depletion and amortization		56,204,269		39,024,886		20,517,780
Ceiling test impairment		—		14,172,309		—
Asset retirement obligation accretion		943,707		606,459		567,968
Operating lease expense		925,217		—		—
General and administrative expense		19,866,706		12,867,686		10,515,887
Total Costs and Operating Expenses		135,566,503		100,104,422		50,732,559
Income from Operations		60,136,328		19,960,939		15,967,141
Other Income (Expense)
Interest income		13,511		97,855		291,083
Interest expense		(13,865,556)		(427,898)		—
Realized (loss) on derivatives		—		(11,153,702)		(119,897)
Unrealized gain (loss) on change in fair value of derivatives		(3,000,078)		3,968,287		(3,968,287)
Net Other (Expense)		(16,852,123)		(7,515,458)		(3,797,101)
Income Before Provision for Income Taxes		43,284,205		12,445,481		12,170,040
(Provision for) Income Taxes		(13,787,654)		(3,445,721)		(10,416,171)
Net Income	$	29,496,551	$	8,999,760	$	1,753,869
Basic Earnings per share	$	0.44	$	0.15	$	0.03
Diluted Earnings per share	$	0.44	$	0.15	$	0.03

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

F-5

RING ENERGY, INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

				Additional		Retained Earnings		Total
	Common Stock			Paid-in		(Accumulated		Stockholders’
	Shares	Amount		Capital		Deficit)		Equity
Balance, December 31, 2016	49,113,063	$	49,113	$	335,197,845	$	(44,705,985)	$	290,540,973
Modified Retrospective adjustment	—		—		—		1,596,463		1,596,463
Share-based compensation	—		—		3,685,079		—		3,685,079
Options exercised (cashless exercise)	133,308		133		(133)		—		—
Options exercised	—		—		—		—		—
Common stock issued for cash, net	4,977,658		4,978		59,021,978		—		59,026,956
Net income	—		—		—		1,753,869		1,753,869
Balance, December 31, 2017	54,224,029	$	54,224	$	397,904,769	$	(41,355,653)	$	356,603,340
Share-based compensation	—		—		3,870,934		—		3,870,934
Options exercised (cashless exercise)	103,113		103		(103)		—		—
Options exercised	50,000		50		99,950		—		100,000
Restricted stock vested	64,620		65		(65)		—		—
Common stock issued for cash, net	6,164,000		6,164		81,814,974		—		81,821,138
Common stock issued for property acquisition	2,623,948		2,624		11,201,634		—		11,204,258
Net income	—		—		—		8,999,760		8,999,760
Balance, December 31, 2018	63,229,710	$	63,230	$	494,892,093	$	(32,355,893)	$	462,599,430
Common stock issued as partial consideration in acquisition	4,576,951		4,577		28,326,750		—		28,331,327
Restricted stock vested	187,136		187		(187)		—		—
Share-based compensation	—		—		3,082,625		—		3,082,625
Net income	—		—		—		29,496,551		29,496,551
Balance, December 31, 2019	67,993,797	$	67,994	$	526,301,281	$	(2,859,342)	$	523,509,933

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

F-6

RING ENERGY, INC.

STATEMENTS OF CASH FLOWS

For the Years Ended December 31,	2019		2018		2017
Cash Flows From Operating Activities
Net income	$	29,496,551	$	8,999,760	$	1,753,869
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		56,204,269		39,024,886		20,517,780
Ceiling test impairment		—		14,172,309		—
Accretion expense		943,707		606,459		567,968
Amortization of deferred financing costs		991,310		—		—
Share-based compensation		3,082,625		3,870,934		3,685,079
Deferred income tax expense		9,500,517		2,537,837		3,862,827
Excess tax expense (benefit) related to share-based compensation		3,855,389		907,884		(49,896)
Adjustment to deferred tax asset for change in effective tax rate		431,748		—		6,603,240
Change in fair value of derivative instruments		3,000,078		(3,968,286)		3,968,286
Changes in assets and liabilities:
Accounts receivable		(10,035,648)		666,283		(9,980,206)
Prepaid expenses and retainers		(1,878,667)		(318,190)		268,080
Accounts payable		12,320,308		4,435,269		12,375,772
Settlement of asset retirement obligation		(1,295,966)		(577,824)		(766,595)
Net Cash Provided by Operating Activities		106,616,221		70,357,321		42,806,204
Cash Flows From Investing Activities
Payments for the Wishbone Acquisition		(276,061,594)		—		—
Payments to purchase oil and natural gas properties		(3,400,411)		(4,656,484)		(28,682,298)
Proceeds from divestiture of oil and natural gas properties		8,547,074		—		—
Payments to develop oil and natural gas properties		(152,125,320)		(198,870,366)		(124,680,469)
Proceeds from disposal of fixed assets subject to depreciation		—		105,536		—
Purchase of fixed assets subject to depreciation		—		—		(335,507)
Purchase of inventory for development		—		—		(4,214,686)
Net Cash Used in Investing Activities		(423,040,251)		(203,421,314)		(157,912,960)
Cash Flows From Financing Activities
Proceeds from revolving line of credit		327,000,000		39,500,000		—
Proceeds from issuance of common stock		—		81,821,138		59,026,956
Proceeds from option exercise		—		100,000		—
Payment of deferred financing costs		(3,781,657)		—		—
Reduction of financing lease liabilities		(153,417)		—		—
Net Cash Provided by Financing Activities		323,064,926		121,421,138		59,026,956
Net Increase (Decrease) in Cash		6,640,896		(11,642,855)		(56,079,800)
Cash at Beginning of Period		3,363,726		15,006,581		71,086,381
Cash at End of Period	$	10,004,622	$	3,363,726	$	15,006,581
Supplemental Cash Flow Information
Cash paid for interest	$	10,364,313	$	323,916	$	—
Noncash Investing and Financing Activities
Asset retirement obligation incurred during development	$	631,727	$	1,311,956	$	1,297,289
Asset retirement obligation acquired		39,701		2,571,549		—
Asset retirement obligation revision of estimate		—		87,960
Operating lease assets obtained in exchange for new operating lease liability		2,319,185		—		—
Financing lease assets obtained in exchange for new financing lease liability		858,513		—		—
Prepaid asset settled in diverstiture of oil and natural gas properties		1,019,876		—		—
Oil and gas assets and properties acquired through stock issuance		—		11,204,258		—
Capitalized expenditures attributable to drilling projects financed through current liabilities		15,170,000		26,000,000		23,000,000
Use of inventory in property development		—		—		5,797,113
Supplemental Schedule of Investing Activities Wishbone Acquisition
Assumption of joint interest billing receivable		1,464,394		—		—
Assumption of prepaid assets		2,864,554		—		—
Assumption of accounts and revenue payables		(1,234,861)		—		—
Asset retirement obligation incurred through acquisition		(3,705,941)		—		—
Common stock issued as partial consideration in acquisition		(28,331,327)		—		—
Oil and gas properties subject to amortization		305,004,775		—		—
Cash paid		276,061,594		—		—

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

F-7

RING ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

NOTE 1 – ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Nature of Operations – Ring Energy, Inc. is a Nevada corporation. Ring Energy, Inc. is referred to herein as the “Company.” The Company owns interests in oil and natural gas properties located in Texas and New Mexico and is engaged primarily in the acquisition, exploration and development of oil and natural gas properties and the production and sale of oil and natural gas.

Use of Estimates – The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Changes in the future estimated oil and natural gas reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analysis could have a significant impact on the future results of operations.

Fair Value Measurements - Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Financial Accounting Standards Board ("FASB") has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.

Fair Values of Financial Instruments – The carrying amounts reported for the revolving line of credit approximates fair value because the underlying instruments are at interest rates which approximate current market rates. The carrying amounts of receivables and accounts payable and other current assets and liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities.

Fair Value of Non-financial Assets and Liabilities – The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on managements’ expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows or third-party offers or prices of comparable assets with consideration of current market conditions to value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy.

Concentration of Credit Risk and Accounts Receivable – Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and accounts receivable. The Company has cash in excess of federally insured limits of and $9,754,622 and $3,113,726 at December 31, 2019 and 2018, respectively. The Company places its cash with a high credit quality financial institution.

Substantially all of the Company’s accounts receivable is from purchasers of oil and natural gas. Oil and natural gas sales are generally unsecured. The Company has not had any significant credit losses in the past and believes its accounts receivable are fully collectable. Accordingly, no allowance for doubtful accounts has been provided at December 31, 2019 and 2018. The Company also has a joint interest billing receivable. Joint interest billing receivables are collateralized by the pro rata revenue attributable to the joint interest holders and further by the interest itself.

Cash – The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

F-8

Oil and Natural Gas Properties – The Company uses the full cost method of accounting for oil and natural gas properties. Under this method, all costs associated with acquisition, exploration, and development of oil and natural gas properties are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and costs of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. Capitalized costs are categorized either as being subject to amortization or not subject to amortization.

The Company records a liability in the period in which an asset retirement obligation (“ARO”) is incurred, in an amount equal to the discounted estimated fair value of the obligation that is capitalized. Thereafter this liability is accreted up to the final retirement cost. An ARO is a future expenditure related to the disposal or other retirement of certain assets. The Company’s ARO relates to future plugging and abandonment expenses of its oil and natural gas properties and related facilities disposal.

All capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves and estimated future costs to plug and abandon wells and costs of site restoration, less the estimated salvage value of equipment associated with the oil and natural gas properties, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent engineers. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is offset to the capitalized costs to be amortized. The following table shows total depletion and depletion per barrel-of-oil-equivalent rate, for the years ended December 31, 2019, 2018 and 2017.

	For the Years Ended December 31,
	2019		2018		2017
Depletion	$	55,870,246	$	38,810,864	$	20,197,690
Depletion rate, per barrel-of-oil-equivalent (BOE)	$	14.15	$	17.38	$	13.92

In addition, capitalized costs less accumulated amortization and related deferred income taxes shall not exceed an amount (the full cost ceiling) equal to the sum of:

1) the present value of estimated future net revenues discounted ten percent computed in compliance with SEC guidelines;

2) plus the cost of properties not being amortized;

3) plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized;

4) less income tax effects related to differences between the book and tax basis of the properties.

For the year ended December 31, 2018, the Company took write downs on oil and natural gas properties as a result of the ceiling test in the amount of $14,172,309. NaN impairment was recorded for the year ended December 31, 2019 or 2017.

Land, Buildings, Equipment and Leasehold Improvements – Land, buildings, equipment and leasehold improvements are valued at historical cost, adjusted for impairment loss less accumulated depreciation. Historical costs include all direct costs associated with the acquisition of land, buildings, equipment and leasehold improvements and placing them in service.

Depreciation of buildings and equipment is calculated using the straight-line method based upon the following estimated useful lives:

Leasehold improvements	3‑10 years
Office equipment and software	3‑7 years
Machinery and equipment	5‑10 years

Depreciation expense was $334,023, $214,022 and $320,090 for the years ended December 31, 2019, 2018 and 2017, respectively.

F-9

Revenue Recognition – In January 2018, the Company adopted Accounting Standards Update (“ASU”) 2014-09 Revenues from Contracts with Customers (Topic 606) (“ASU 2014-09”). The timing of recognizing revenue from the sale of produced crude oil and natural gas was not changed as a result of adopting ASU 2014-09. The Company predominantly derives its revenue from the sale of produced crude oil and natural gas. The contractual performance obligation is satisfied when the product is delivered to the customer. Revenue is recorded in the month the product is delivered to the purchaser and the Company receives payment from one to three months after delivery. The transaction price includes variable consideration as product pricing is based on published market prices and reduced for contract specified differentials. The new guidance regarding ASU 2014-09 does not require that the transaction price be fixed or stated in the contract. Estimating the variable consideration does not require significant judgment and Ring engages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products. See Note 3 for additional information.

Income Taxes – Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes. Deferred taxes are provided on differences between the tax bases of assets and liabilities and their reported amounts in the financial statements, and tax carry forwards. Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the provision for income taxes.

In January 2017, the Company adopted ASU 2016-09, Compensation – Stock Compensation (Topic 718.) The Company used the modified retrospective method to account for unrecognized excess tax benefits from prior periods, resulting in an adjustment to our beginning balances of Deferred Income Taxes and Retained Loss of $1,596,463 and uses the prospective method to account for current period and future excess tax benefit. For the years ended December 31, 2019, 2018 and 2017, we recorded an increase of $3,855,389, an increase of $907,884 and a decrease of $49,896, respectively, to our income tax provision.

On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act of 2017 (the “Tax Act”). The SEC subsequently issued a Staff Accounting Bulletin No. 118, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act” (“SAB 118”), which provides guidance on accounting for the tax effects of the Tax Act. Among other changes, the Tax Act lowered the corporate tax rate to 21%.

Accounting for Uncertainty in Income Taxes – In accordance with generally accepted accounting principles, the Company has analyzed its filing positions in all jurisdictions where it is required to file income tax returns for the open tax years in such jurisdictions. The Company has identified its federal income tax return and its franchise tax return in Texas in which it operates as “major” tax jurisdictions. The Company’s federal income tax returns for the years ended December 31, 2015 through 2018 remain subject to examination. The Company’s franchise tax returns in Texas remain subject to examination for 2014 through 2018. The Company currently believes that all significant filing positions are highly certain and that all of its significant income tax filing positions and deductions would be sustained upon audit. Therefore, the Company has no significant reserves for uncertain tax positions and no adjustments to such reserves were required by generally accepted accounting principles. No interest or penalties have been levied against the Company and none are anticipated; therefore, no interest or penalty has been included in our provision for income taxes in the statements of operations.

Earnings (Loss) Per Share – Basic earnings (loss) per share is computed by dividing net income by the weighted-average number of common shares outstanding during the year. Diluted earnings (loss) per share are calculated to give effect to potentially issuable dilutive common shares.

Major Customers – During the year ended December 31, 2019, sales to three customers represented 42%, 36% and 7%, respectively, of total oil and natural gas sales. At December 31, 2019, sales to these three customers represented 47%, 31% and 9%, respectively, of accounts receivable. During the year ended December 31, 2018, sales to two customers represented 85% and 11%, respectively, of total oil and natural gas sales. At December 31, 2018, sales to one customer made up 90% of accounts receivable. During the year ended December 31, 2017, sales to two customers represented 76% and 18%, respectively, or total oil and natural gas revenues. At December 31, 2017, sales to two of our customers made up 88% and 10%, respectively, of accounts receivable. The loss of any of our customers would not have a material adverse effect on the Company as there is an available market for its crude oil and natural gas production from other purchasers.

F-10

Stock-Based Employee and Non-Employee Compensation – The Company has outstanding stock options to directors, employees and contract employees, which are described more fully in Note 13. The Company accounts for its stock options grants in accordance with generally accepted accounting principles. Generally accepted accounting principles require the recognition of the cost of employee services received in exchange for an award of equity instruments in the financial statements and is measured based on the grant date fair value of the award. Generally accepted accounting principles also requires stock option compensation expense to be recognized over the period during which an employee is required to provide service in exchange for the award (the vesting period).

Stock-based employee compensation incurred for the years ended December 31, 2019, 2018 and 2017 was $3,082,625, $3,870,934 and $3,685,079, respectively.

Derivative Instruments and Hedging Activities - The Company may periodically enter into derivative contracts to manage its exposure to commodity risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options. The oil and gas reference prices upon which the commodity derivative contracts are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil and gas production.

When applicable, the Company records all derivative instruments, other than those that meet the normal purchases and sales exception, on the balance sheet as either an asset or liability measured at fair value. Changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met.

Recently Adopted Accounting Pronouncements – In February 2016, FASB issued ASU 2016-02, Leases (Topic 842) (“ASU 2016-02”). For lessees, the amendments in this update require that for all leases not considered to be short term, a company recognize both a lease liability and right-of-use asset on its balance sheet, representing the obligation to make payments and the right to use or control the use of a specified asset for the lease term. The amendments in this update are effective for annual periods beginning after December 15, 2018.  The Company adopted ASU 2016-02 effective January 1, 2019 using the modified retrospective method and chose the option to not restate prior periods and to record any cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption.  The Company’s adoption of ASU 2016-02 did not require a cumulative-effect adjustment to retained earnings.  The Company evaluated any leases with terms of 12 months or less to determine appropriate application of ASU 2016-02. For short term leases that the Company intends to continue for longer than 12 months despite their short current term, the Company applied ASU 2016-02. For short term leases that the Company does not intend to continue longer than 12 months, the Company has elected not to apply ASU 2016-02.  See Note 4 – Leases for new disclosures required as a result of our adoption of ASU 2016-02.

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815), which makes significant changes to the current hedge accounting guidance. The new standard eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in the fair value of a hedging instrument to be presented in the same income statement line as the hedged item. The new standard also eases certain documentation and assessment requirements and modifies the accounting for components excluded from the assessment of hedge effectiveness. The Company adopted this guidance in January 2019.  The adoption of this guidance did not have a material impact on the Company’s financial statements.

In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The new standard allows for stranded tax effects resulting from tax reform legislation known as the Tax Act previously recognized in accumulated other comprehensive income to be reclassified to retained earnings.  The Company adopted this guidance in January 2019.  The adoption of this guidance did not have a material impact on the Company’s financial statements.  

Recent Accounting Pronouncements – In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”). ASU 2018-13 will eliminate, add and modify certain disclosure requirements for fair value measurement.  ASU 2018-13 is effective for annual and interim periods beginning January 1, 2020, with early adoption permitted for either the entire standard or only the provisions that eliminate or modify requirements.  ASU 2018-13 requires that the additional disclosure requirements be adopted using a retrospective approach.  The adoption of this guidance will not have a material impact on the Company’s financial statements.

NOTE 2 – RESTATEMENT OF PREVIOUSLY FILED FINANCIAL INFORMATION

Overview – Ring Energy, Inc. is filing this Annual Report on Form 10-K for the year ended December 31, 2019 which contains financial statements for the years ended December 31, 2018 and 2017 and quarterly unaudited financial information for the three months ended March 31, 2019 and 2018, the three and six months ended June 30, 2019 and 2018 and the three and nine months ended September 30, 2019 and 2018.  The unaudited financial statements for the quarter and year to date periods ended March 31, 2019, June 30, 2019 and September 30, 2019 have been restated.  The restatement of the financial statements for the quarter and

F-11

year to date periods included herein restates and replaces Ring’s previously issued unaudited quarterly and year to date financial statements and related financial information, which was originally filed on Form 10-Q with the Securities and Exchange commission (“SEC”) on May 8, 2019, August 7, 2019 and November 6, 2019, respectively.  The restatement principally adjusts the income tax provision related to equity compensation.  The Company does not intend to file amendments to the previously filed Forms 10-Q.

Background – On February 27, 2020, the Company issued a press release announcing that the Audit Committee of the Company’s Board of Directors, upon the recommendation of the Company’s management, concluded that the previously issued financial statements for the three months ended March 31, 2019, the three and six months ended June 30, 2019 and the three and nine months ended September 30, 2019 contained an error.

Effect of Restatement on Previously Filed March 31, 2019 Form 10-Q

Restated Balance Sheet as of March 31, 2019 (unaudited)

	As of March 31, 2019
	As Previously		Restatement
	Reported		Adjustment		As Restated
ASSETS
Current Assets
Cash	$	2,606,769			$	2,606,769
Accounts receivable		27,941,378				27,941,378
Joint interest billing receivable		2,553,377				2,553,377
Operating lease asset		417,567				417,567
Prepaid expenses and retainers		3,013,688				3,013,688
Total Current Assets		36,532,779				36,532,779
Properties and Equipment
Oil and natural gas properties subject to depletion and amortization		990,608,164				990,608,164
Fixed assets subject to depreciation		1,465,551				1,465,551
Total Properties and Equipment		992,073,715				992,073,715
Accumulated depreciation, depletion and amortization		(113,505,141)				(113,505,141)
Net Properties and Equipment		878,568,574				878,568,574
Deferred Income Taxes		9,741,903		(6,820,183)		2,921,720
Deferred Financing Costs		353,384				353,384
Total Assets	$	925,196,640	$	(6,820,183)	$	918,376,457
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable	$	63,862,098			$	63,862,098
Acquisition liability to be settled through equity		28,356,396				28,356,396
Operating lease liability		417,567				417,567
Derivative liabilities		340,685				340,685
Total Current Liabilities		92,976,746				92,976,746
Revolving line of credit		84,500,000				84,500,000
Acquisition liability to be settled through refinancing into credit facility		256,877,766				256,877,766
Asset retirement obligations		16,318,790				16,318,790
Total Liabilities		450,673,302				450,673,302
Stockholders' Equity
Preferred stock - $0.001 par value; 50,000,000 shares authorized; 0 shares issued or outstanding		—				—
Common stock - $0.001 par value; 150,000,000 shares authorized; 63,229,710 shares and 63,229,710 shares issued and outstanding, respectively		63,230				63,230
Additional paid-in capital		495,726,558				495,726,558
Accumulated deficit		(21,266,450)		(6,820,183)		(28,086,633)
Total Stockholders' Equity		474,523,338		(6,820,183)		467,703,155
Total Liabilities and Stockholders' Equity	$	925,196,640	$	(6,820,183)	$	918,376,457

F-12

Restated Statement of Operations for the three months ended March 31, 2019 (unaudited)

	For the Three Months Ended March 31, 2019
	As Previously		Restatement
	Reported		Adjustment		As Restated
Oil and Gas Revenues	$	41,798,315			$	41,798,315
Costs and Operating Expenses
Oil and gas production costs		9,408,764				9,408,764
Oil and gas production taxes		2,082,875				2,082,875
Depreciation, depletion and amortization		12,929,054				12,929,054
Asset retirement obligation accretion		215,945				215,945
Lease expense		128,175				128,175
General and administrative expense		6,798,017				6,798,017
Total Costs and Operating Expenses		31,562,830				31,562,830
Income from Operations		10,235,485				10,235,485
Other Income (Expense)
Interest income		12,236				12,236
Interest expense		(773,017)				(773,017)
Realized loss on derivatives		—				—
Unrealized loss on change in fair value of derivatives		(340,685)				(340,685)
Net Other Income (Expense)		(1,101,466)				(1,101,466)
Income before tax provision		9,134,019				9,134,019
Benefit from (Provision for) Income Taxes		1,955,424		(6,820,183)		(4,864,759)
Net Income	$	11,089,443	$	(6,820,183)	$	4,269,260
Basic Income per Share	$	0.18	$	(0.11)	$	0.07
Diluted Income per Share	$	0.17	$	(0.11)	$	0.07

Restated Statement of Stockholders’ Equity for the three months ended March 31, 2019 (unaudited)

				Additional		Retained Earnings		Total
	Common Stock			Paid-in		(Accumulated		Stockholders'
	Shares	Amount		Capital		Deficit)		Equity
For the three Months Ended March 31, 2019
Balance, December 31, 2018	63,229,710	$	63,230	$	494,892,093	$	(32,355,893)	$	462,599,430
Share-based compensation	—		—		834,465		—		834,465
Net income	—		—		—		11,089,443		11,089,443
As reported Balance, March 31, 2019	63,229,710	$	63,230	$	495,726,558	$	(21,266,450)	$	474,523,338
Restatement Adjustment							(6,820,183)		(6,820,183)
As Restated	63,229,710	$	63,230	$	495,726,558	$	(28,086,633)	$	467,703,155

F-13

Restated Statement of Cash Flow for the three months ended March 31, 2019 (unaudited)

	For the Three Months Ended March 31, 2019
	As Previously		Restatement
	Reported		Adjustment		As Restated
Cash Flows From Operating Activities
Net income	$	11,089,443	$	(6,820,183)	$	4,269,260
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		12,929,054				12,929,054
Accretion expense		215,945				215,945
Share-based compensation		834,465				834,465
Deferred income tax provision		1,918,144				1,918,144
Excess tax deficiency related to share-based compensation		(3,873,568)		6,820,183		2,946,615
Change in fair value of derivative instruments		340,685				340,685
Changes in assets and liabilities:
Accounts receivable		(15,808,739)				(15,808,739)
Prepaid expenses and retainers		180,452				180,452
Accounts payable		2,111,804				2,111,804
Settlement of asset retirement obligation		(107,770)				(107,770)
Net Cash Provided by (Used in) Operating Activities		9,829,915		—		9,829,915
Cash Flows From Investing Activities
Payments to purchase oil and natural gas properties		(13,358,132)				(13,358,132)
Payments to develop oil and natural gas properties		(42,228,740)				(42,228,740)
Proceeds from disposal of fixed assets subject to depreciation		—				—
Net Cash Used in Investing Activities		(55,586,872)				(55,586,872)
Cash Flows From Financing Activities
Proceeds from revolving line of credit		45,000,000				45,000,000
Proceeds from issuance of common stock, net of offering costs		—				—
Net Cash Provided by Financing Activities		45,000,000				45,000,000
Net Change in Cash		(756,957)				(756,957)
Cash at Beginning of Period		3,363,726				3,363,726
Cash at End of Period	$	2,606,769			$	2,606,769
Supplemental Cash Flow Information
Cash paid for interest	$	708,951			$	708,951
Noncash Investing and Financing Activities
Asset retirement obligation incurred during development	$	175,173			$	175,173
Capitalized expenditures attributable to drilling projects financed through current liabilities		34,605,000				34,605,000
Acquisition of oil and gas properties
Assumption of joint interest billing receivable		1,464,394				1,464,394
Assumption of prepaid assets		2,864,554				2,864,554
Assumption of accounts and revenue payables		(1,234,862)				(1,234,862)
Asset retirement obligation incurred through acquisition		(2,979,645)				(2,979,645)
Acquisition payable to be settled through equity		(28,356,396)				(28,356,396)
Acquisition payable to be settled through cash payment		(256,877,766)				(256,877,766)
Oil and gas properties subject to amortization		285,119,721				285,119,721

F-14

NOTE A1 - ABRIDGED BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

Condensed Financial Statements - The accompanying condensed financial statements prepared by Ring Energy, Inc. (the "Company" or "Ring") have not been audited by an independent registered public accounting firm. In the opinion of the Company's management, the accompanying unaudited financial statements contain all adjustments necessary for fair presentation of the results of operations for the periods presented, which adjustments were of a normal recurring nature, except as disclosed herein. The results of operations for the three months ended March 31, 2019, are not necessarily indicative of the results to be expected for the full year ending December 31, 2019.

Certain notes and other disclosures have been omitted from these interim financial statements. Therefore, these financial statements should be read in conjunction with the Company's annual report on Form 10-K for the year ended December 31, 2018.

Income Taxes - Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes. Deferred taxes are provided on differences between the tax bases of assets and liabilities and their reported amounts in the financial statements, and tax carry forwards. Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the provision for income taxes.

In January 2017, the Company adopted ASU 2016-09, Compensation - Stock Compensation (Topic 718.) The Company used the modified retrospective method to account for unrecognized excess tax benefits from prior periods. For the three months ended March 31, 2019, we recorded an increase of $2,946,615 to our income tax provision. For the three months ended March 31, 2018, we recorded an increase of $1,158,604 to our income tax provision.

On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act of 2017 (the "Tax Act"). The SEC subsequently issued a Staff Accounting Bulletin No. 118, "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" ("SAB 118"), which provides guidance on accounting for the tax effects of the Tax Act. Among other changes, the Tax Act lowered the corporate tax rate to 21%.

NOTE B1 - REVENUE RECOGNITION

Oil sales

Under the Company's oil sales contracts, the Company sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received.

Natural gas sales

Under the Company's natural gas sales contracts, the Company delivers unprocessed natural gas to a midstream processing entity at the wellhead. The midstream processing entity obtains control of the natural gas at the wellhead. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of natural gas. Under these agreements, the Company recognizes revenue when control transfers to the purchaser at the point of delivery.

Natural gas liquids sales

Under the Company's natural gas liquids sales contracts, the Company delivers natural gas liquids to a midstream entity. The Company recognizes revenue at the price received when control transfers to the purchaser at the point of delivery.

F-15

Disaggregation of Revenue. The following table presents revenues disaggregated by product for the three months ended March 31, 2019 and 2018:

	For The Three Months
	Ended March 31,
	2019		2018
Operating revenues
Oil	$	40,877,983	$	29,140,165
Natural gas		782,139		751,226
Natural gas liquids		138,193		—
Total operating revenues	$	41,798,315	$	29,891,391

All revenues are from production from the Permian Basin in Texas and New Mexico.

NOTE C1 – LEASES

Effective January 1, 2019, the Company adopted ASU No. 2016-02, Leases (Topic 842). This guidance attempts to increase transparency and comparability among organizations by recognizing certain lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP methodology and the method proposed by this new guidance is the recognition on the balance sheet of certain lease assets and lease liabilities by lessees for those leases that were classified as operating leases under previous GAAP.

The Company made accounting policy elections to not capitalize leases with a lease term of twelve months or less and to not separate lease and non-lease components for all asset classes. The Company has also elected to adopt the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases and the practical expedient regarding land easements that exist prior to the adoption of ASU 2016-02. The Company did not elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date.

The Company has operating leases for our offices in Midland, Texas and Tulsa, Oklahoma with terms through January 31, 2020. The office space being leased in Tulsa is owned by Arenaco, LLC, a company that is owned by Mr. Rochford, Chairman of the Board of the Company, and Mr. McCabe, a Director of the Company. Future lease payments associated with these operating leases as of March 31, 2019 are as follows:

	2019 (1)		2020
Operating lease payments	$	384,525	$	42,725

(1) 2019 excludes the three months ended March 31, 2019.

The following table provides supplemental information regarding cash flows from operations:

	2019
Cash paid for amounts included in the measurement of lease liabilities	$	128,175

Short term lease costs for the period ended March 31, 2019 were $153,759.

F-16

NOTE D1 – EARNINGS PER SHARE INFORMATION

	For the Three Months Ended March 31, 2019
	As Previously		Restatement
	Reported		Adjustment		As Restated
Net Income	$	11,089,443	$	(6,820,183)	$	4,269,260
Basic Weighted-Average Shares Outstanding		63,229,710		63,229,710		63,229,710
Effect of dilutive securities:
Stock options		590,098		590,098		590,098
Restricted stock		172,741		172,741		172,741
Diluted Weighted-Average Shares Outstanding		63,992,549		63,992,549		63,992,549
Basic Income per Share	$	0.18	$	(0.11)	$	0.07
Diluted Income per Share	$	0.17	$	(0.11)	$	0.07

Stock options to purchase 993,500 shares of common stock and 326,200 shares of unvested restricted stock were excluded from the computation of diluted earnings per share during the three months ended March 31, 2019, as their effect would have been anti-dilutive.

NOTE E1 – ACQUISITIONS

On April 9, 2019, the Company completed the acquisition of oil and gas 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 (the “Acquisition”). The acquired properties consist of 49,754 gross (38,230 net) acres and include a 77% average working interest and a 58% average net revenue interest. The Company incurred approximately $3.5 million in acquisition related costs, which were recognized in general and administrative expense during the three months ended March 31, 2019.

The Acquisition was recognized as a business combination whereby Ring recorded the assets acquired and the liabilities assumed at their fair values as of February 1, 2019, which is the date the Company obtained control of the properties and was the acquisition date for financial reporting purposes. Revenues and related expenses for the Acquisition are included in our condensed statement of operations beginning February 1, 2019. The estimated fair value of the acquired properties approximated the consideration paid, which the Company concluded approximated the fair value that would be paid by a typical market participant. The following table summarizes the fair values of the assets acquired and the liabilities assumed:

Assets acquired:
Joint interest billing receivable	$	1,464,394
Prepaid assets		2,864,554
Liabilities assumed
Draw on revolving line of credit		(15,000,000)
Accounts and revenues payable		(1,234,862)
Asset retirement obligations		(2,979,645)
Acquisition payable to be settled through equity		(28,356,396)
Acquisition payable to be settled through cash payment		(256,877,766)
Total Identifiable Net Assets	$	(300,119,721)

The $15 million draw on the revolving line of credit was the deposit placed at the signing of the Purchase and Sale Agreement on February 25, 2019. The Acquisition payable to be settled through equity was settled at the closing on April 9, 2019 through the issuance of 4,581,001 shares of common stock, of which 2,538,071 shares are being held in escrow to satisfy potential indemnification claims. The Acquisition payable to be settled through cash payment was settled at closing with the amendment and restatement of the Credit Facility as discussed further in Note H1.

The Company will continue to evaluate the fair value of the assets and liabilities reflected above and will record any adjustments, if needed, in future periods.

F-17

The following unaudited pro forma information for the three months ended March 31, 2019 and 2018, respectively, is presented to reflect the operations of the Company as if the acquisition of assets had been completed on January 1, 2019 and 2018, respectively:

	For The Three Months
	Ended March 31,
	2019		2018
Oil and Gas Revenues	$	48,463,729	$	42,759,403
Net Income (Loss)	$	11,379,247	$	10,939,149
Basic Earnings (Loss) per Share	$	0.17	$	0.18
Diluted Earnings (Loss) per Share	$	0.17	$	0.17

NOTE F1 – DERIVATIVE FINANCIAL INSTRUMENTS

The Company is exposed to fluctuations in crude oil and natural gas prices on its production. It can utilize derivative strategies that consist of either a single derivative instrument or a combination of instruments to manage the variability in cash flows associated with the forecasted sale of its future domestic oil and natural gas production. While the use of derivative instruments may limit or partially reduce the downside risk of adverse commodity price movements, the use also may limit future income from favorable commodity price movements.

During March 2019, the Company entered into new derivative contracts in the form of costless collars of WTI Crude Oil prices in order to protect the Company’s cash flow from price fluctuation and maintain its capital programs.  “Costless collars” are the combination of two options, a put option (floor) and 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.  The trades were for a total of 3,500 barrels of oil per day and were for the period of April 2019 through December 2019. The following is a table reflects the put and call prices of those contracts:

Date entered into	Barrels per day	Put price		Call price
03/12/19	1,500	$	50.00	$	66.00
03/13/19	500		50.00		67.40
03/20/19	500		50.00		67.90
03/20/19	1,000		50.00		68.71

On September 25, 2017, the Company entered into derivative contracts in the form of costless collars for the period of January 2018 through December 2018 for 1,000 barrels per day with a put price of $49.00 and a call price of $54.60.

On October 27, 2017, the Company entered into costless collars of WTI Crude Oil for the period of January 2018 through December 2018 for an additional 1,000 barrels of oil per day with a put price of $51.00 and a call price of $54.80.

Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying balance sheets. Any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included as a component of other income (expense) in the accompanying statements of operations.

The use of derivative transactions involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. At March 31, 2019, 100% of our volumes subject to derivative instruments are with lenders under our Credit Facility (as defined in Note H1).

The Company entered into additional derivative contracts subsequent to March 31, 2019. These contracts were for an additional 2,000 barrels per day for the period April 2019 through December 2019 and for 2,000 barrels per day for the period January 2020 through December 2020.

F-18

NOTE G1 – FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The authoritative guidance requires disclosure of the framework for measuring fair value and requires that fair value measurements be classified and disclosed in one of the following categories:

Level 1:        Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2:        Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3:        Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity).

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy. We continue to evaluate our inputs to ensure the fair value level classification is appropriate. When transfers between levels occur, it is our policy to assume that the transfer occurred at the date of the event or change in circumstances that caused the transfer.

The fair values of the Company’s derivatives are not actively quoted in the open market. The Company uses a market approach to estimate the fair values of its derivative instruments on a recurring basis, utilizing commodity futures pricing for the underlying commodities provided by a reputable third party, a Level 2 fair value measurement.

The following table summarizes the valuation of our assets and liabilities that are measured at fair value on a recurring basis.

	Fair Value Measurement Classification
	Quoted prices in
	Actives Markets
	for Identical Assets		Significant Other		Significant
	or (Liabilities)		Observable Inputs		Unobservable
	(Level 1)		(Level 2)		Inputs (Level 3)		Total
As of March 31, 2019
Oil and gas derivative contracts	$	—	$	(340,685)	$	—	$	(340,685)
Total	$	—	$	(340,685)	$	—	$	(340,685)

NOTE H1 – REVOLVING LINE OF CREDIT

On July 1, 2014, the Company entered into a Credit Agreement with SunTrust Bank, as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (“Administrative Agent”), which was amended on June 14, 2018, May 18, 2016, June 26, 2015, and July 24, 2015 (as amended, the “Credit Facility”).  The Credit Facility provides for a senior secured revolving credit facility with a maximum borrowing amount of $500 million. The Credit Facility matures on June 26, 2020, and is secured by substantially all of the Company’s assets.

F-19

In June 2018, the borrowing base (the “Borrowing Base”) for the Credit Facility was increased from $60 million to $175 million. The Borrowing Base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time.  The Borrowing Base will be redetermined semi-annually on each May 1 and November 1.  The Borrowing Base will also be reduced in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and cancellation of certain hedging positions.

The Credit Facility allows for Eurodollar Loans and Base Rate Loans (each as defined in the Credit Facility).  The interest rate on each Eurodollar Loan will be the adjusted LIBOR for the applicable interest period plus a margin between 1.75% and 2.75% (depending on the then-current level of borrowing base usage). The annual interest rate on each Base Rate Loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the federal funds rate plus 0.5% per annum or the (iii) adjusted LIBOR determined on a daily basis for an interest period of one-month, plus 1.00% per annum, plus (b) a margin between 2.75% and 3.75% (depending on the then-current level of borrowing base usage).  

The Credit Facility contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio (as defined in the Credit Facility) of not more than 4.0 to 1.0 and (ii) a minimum Current Ratio (as defined in the Credit Facility) of 1.0 to 1.0. The Credit Facility also contains other customary affirmative and negative covenants and events of default. As of March 31, 2019, $84,500,000 was outstanding on the Credit Facility. We are in compliance with all covenants contained in the Credit Facility.

Subsequent to March 31, 2019, the Company amended and restated its Credit Facility with SunTrust Bank, as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (the “Amended and Restated Senior Credit Facility”). The Amended and Restated Senior Credit Facility, among other things, increases the maximum facility amount to $1 billion, increases the Borrowing Base to $425 million, extends the maturity date and makes other modifications to the terms of the Credit Facility. The Amended and Restated Senior Credit Facility is secured by a first lien with substantially the same collateral requirements as the Credit Facility, has substantially the same covenants as the Credit Facility and is for a term of five years.

NOTE I1 – ASSET RETIREMENT OBLIGATION

The Company provides for the obligation to plug and abandon oil and gas wells at the dates properties are either acquired or the wells are drilled. The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The asset retirement obligation incurred at the time of drilling was computed using the annual credit-adjusted risk-free discount rate at the applicable dates. Changes in the asset retirement obligation were as follows:

Balance, December 31, 2018	$	13,055,797
Liabilities acquired		2,979,645
Liabilities incurred		175,173
Liabilities settled		(107,770)
Accretion expense		215,945
Balance, March 31, 2019	$	16,318,790

NOTE J1 – STOCKHOLDERS’ EQUITY

Common Stock Issued in Public Offering – In February 2018, the Company closed on an underwritten public offering of 6,164,000 shares of its common stock, including 804,000 shares sold pursuant to the full exercise of an over-allotment option, at $14.00 per share for gross proceeds of $86,296,000. Total net proceeds from the offering were $81,819,073, after deducting underwriting commissions and offering expenses payable by the Company of $4,476,927.

NOTE K1 – EMPLOYEE STOCK OPTIONS AND RESTRICTED STOCK AWARD PLAN

Compensation expense charged against income for share-based awards during the three months ended March 31, 2019, was $834,465, as compared to $1,081,199 for the three months ended March 31, 2018. These amounts are included in general and administrative expense in the accompanying financial statements.

F-20

In 2011, the board of directors and stockholders approved and adopted a long-term incentive plan which allowed for the issuance of up to 2,500,000 shares of common stock through the grant of qualified stock options, non-qualified stock options and restricted stock. In 2013, the Company’s board of directors and stockholders approved an amendment to the long-term incentive plan, increasing the number of shares eligible under the plan to 5,000,000 shares. As of March 31, 2019, there were 684,020 shares remaining eligible for issuance under the plan.

Stock Options

A summary of the stock option activity as of March 31, 2019, and changes during the three months then ended is as follows:

				Weighted-
		Weighted-		Average
		Average		Remaining	Aggregate
		Exercise		Contractual	Intrinsic
	Shares	Price		Term	Value
Outstanding, December 31, 2018	2,751,000	$	6.28
Granted	—	$	—
Forfeited or rescinded	(2,500)	$	11.70
Vested	—	$	—
Outstanding, March 31, 2019	2,748,500	$	6.28	5.3 Years	$	3,366,300
Exercisable, March 31, 2019	2,323,400	$	5.42	4.6 Years

The intrinsic value was calculated using the closing price on March 29, 2019 of $5.87. As of March 31, 2019, there was $1,501,300 of unrecognized compensation cost related to stock options that is expected be recognized over a weighted-average period of 1.8 years.

Restricted Stock

A summary of the restricted stock activity as of March 31, 2019, and changes during the three months then ended is as follows:

		Weighted-
		Average Grant
	Restricted stock	Date Fair Value
Outstanding, December 31, 2018	878,360	$	7.36
Granted	—		—
Forfeited or rescinded	(4,400)		7.53
Vested	—		—
Outstanding, March 31, 2019	873,960	$	7.36

As of March 31, 2019, there was $2,547,688 of unrecognized compensation cost related to restricted stock grants that will be recognized over a weighted average period of 2.3 years.

NOTE L1 – CONTINGENCIES AND COMMITMENTS

Standby Letters of Credit – A commercial bank issued a standby letter of credit on behalf of the Company to the state of Texas for $250,000 to allow the Company to do business there. The standby letter of credit is valid until cancelled or matured and is collateralized by the revolving credit facility with the bank. The terms of the letter of credit are extended for a term of one year at a time. The Company intends to renew the standby letters of credit for as long as the Company does business in the state of Texas. NaN amounts have been drawn under the standby letters of credit.

F-21

Effect of Restatement on Previously Filed June 30, 2019 Form 10-Q

Restatement of Balance Sheet as of June 30, 2019 (unaudited)

	As of June 30, 2019
	As Previously		Restatement
	Reported		Adjustment		As Restated
ASSETS
Current Assets
Cash	$	10,578,982			$	10,578,982
Accounts receivable		21,777,491				21,777,491
Joint interest billing receivable		1,291,817				1,291,817
Operating lease asset		294,095				294,095
Derivative asset		1,189,545				1,189,545
Prepaid expenses and retainers		3,479,218				3,479,218
Total Current Assets		38,611,148				38,611,148
Properties and Equipment
Oil and natural gas properties subject to depletion and amortization		1,037,871,094				1,037,871,094
Financing lease asset		637,757				637,757
Fixed assets subject to depreciation		1,465,551				1,465,551
Total Properties and Equipment		1,039,974,402				1,039,974,402
Accumulated depreciation, depletion and amortization		(128,120,411)				(128,120,411)
Net Properties and Equipment		911,853,991				911,853,991
Deferred Income Taxes		7,209,160		(7,209,160)		—
Deferred Financing Costs		3,592,575				3,592,575
Total Assets	$	961,266,874	$	(7,209,160)	$	954,057,714
LIABILITIES AND STOCKHOLDERS' EQUITY						—
Current Liabilities						—
Accounts payable	$	67,258,467			$	67,258,467
Financing lease liability		204,047				204,047
Operating lease liability		294,095				294,095
Total Current Liabilities		67,756,609				67,756,609
						—
Deferred income taxes		—		643,680		643,680
Revolving line of credit		360,500,000				360,500,000
Financing lease liability		409,634				409,634
Asset retirement obligations		16,536,909				16,536,909
Total Liabilities		445,203,152		643,680		445,846,832
Stockholders' Equity
Preferred stock - $0.001 par value; 50,000,000 shares authorized; no shares issued or outstanding		—				—
Common stock - $0.001 par value; 150,000,000 shares authorized; 67,811,111 shares and 63,229,710 shares issued and outstanding, respectively		67,811				67,811
Additional paid-in capital		524,887,107				524,887,107
Accumulated deficit		(8,891,196)		(7,852,840)		(16,744,036)
Total Stockholders' Equity		516,063,722		(7,852,840)		508,210,882
Total Liabilities and Stockholders' Equity	$	961,266,874	$	(7,209,160)	$	954,057,714

F-22

Restatement of Statement of Operations for the three and six months ended June 30, 2019 (unaudited)

	For the Three Months Ended June 30, 2019							For the Six Months Ended June 30, 2019
	As Previously		Restatement				As Previously		Restatement
	Reported		Adjustment		As Restated		Reported		Adjustment		As Restated
Oil and Gas Revenues	$	51,334,225			$	51,334,225	$	93,132,540			$	93,132,540
Costs and Operating Expenses
Oil and gas production costs		11,569,109				11,569,109		20,977,873				20,977,873
Oil and gas production taxes		2,412,895				2,412,895		4,495,770				4,495,770
Depreciation, depletion and amortization		14,615,270				14,615,270		27,544,324				27,544,324
Asset retirement obligation accretion		229,234				229,234		445,179				445,179
Lease expense		128,175				128,175		256,350				256,350
General and administrative expense		4,743,127				4,743,127		11,541,144				11,541,144
Total Costs and Operating Expenses		33,697,810				33,697,810		65,260,640				65,260,640
Income from Operations		17,636,415				17,636,415		27,871,900				27,871,900
Other Income (Expense)
Interest income		1,260				1,260		13,496				13,496
Interest expense		(4,259,908)				(4,259,908)		(5,032,925)				(5,032,925)
Realized loss on derivatives		—				—		—				—
Unrealized gain on change in fair value of derivatives		1,530,230				1,530,230		1,189,545				1,189,545
Net Other Income (Expense)		(2,728,418)				(2,728,418)		(3,829,884)				(3,829,884)
Income before tax provision		14,907,997				14,907,997		24,042,016				24,042,016
Benefit from (Provision for) Income Taxes		(2,532,743)		(1,032,657)		(3,565,400)		(577,319)		(7,852,840)		(8,430,159)
Net Income	$	12,375,254	$	(1,032,657)	$	11,342,597	$	23,464,697	$	(7,852,840)	$	15,611,857
Basic Income per Share	$	0.18	$	(0.02)	$	0.17	$	0.36	$	(0.12)	$	0.24
Diluted Income per Share	$	0.18	$	(0.02)	$	0.17	$	0.36	$	(0.12)	$	0.24

Restatement of Statement of Shareholder’ Equity for the six month period ended June 30, 2019 (unaudited)

				Additional		Retained Earnings		Total
	Common Stock			Paid-in		(Accumulated		Stockholders'
	Shares	Amount		Capital		Deficit)		Equity
For the Nine Months Ended September 30, 2019
Balance, December 31, 2018	63,229,710	$	63,230	$	494,892,093	$	(32,355,893)	$	462,599,430
Share-based compensation	—		—		834,465		—		834,465
Net income	—		—		—		11,089,443		11,089,443
Balance, March 31, 2019	63,229,710	$	63,230	$	495,726,558	$	(21,266,450)	$	474,523,338
Common stock issued as consideration in asset acquisition	4,581,001		4,581		28,351,815		—		28,356,396
Restricted stock vested	400		—		—		—		—
Share-based compensation	—		—		808,734		—		808,734
Net income	—		—		—		12,375,254		12,375,254
As Reported Balance, June 30, 2019	67,811,111	$	67,811	$	524,887,107	$	(8,891,196)	$	516,063,722
Restatement Adjustment							(7,852,840)		(7,852,840)
As Restated	67,811,111	$	67,811	$	524,887,107	$	(16,744,036)	$	508,210,882

F-23

Restatement of Statement of Cash Flows for the six months ended June 30, 2019 (unaudited)

	For the Six Months Ended June 30, 2019
	As Previously		Restatement
	Reported		Adjustment		As Restated
Cash Flows From Operating Activities
Net income	$	23,464,697	$	(7,852,840)	$	15,611,857
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		27,544,324				27,544,324
Accretion expense		445,179				445,179
Share-based compensation		1,643,199				1,643,199
Deferred income tax provision		5,049,219				5,049,219
Excess tax deficiency related to share-based compensation		(4,471,900)		7,852,840		3,380,940
Change in fair value of derivative instruments		(1,189,545)				(1,189,545)
Changes in assets and liabilities:
Accounts receivable		(9,847,686)				(9,847,686)
Prepaid expenses and retainers		(6,388,823)				(6,388,823)
Accounts payable		(451,965)				(451,965)
Settlement of asset retirement obligation		(384,956)				(384,956)
Net Cash Provided by (Used in) Operating Activities		35,411,743		—		35,411,743
Cash Flows From Investing Activities
Payments to purchase oil and natural gas properties		(268,120,579)				(268,120,579)
Payments to develop oil and natural gas properties		(81,051,832)				(81,051,832)
Proceeds from disposal of fixed assets subject to depreciation		—				—
Net Cash Used in Investing Activities		(349,172,411)				(349,172,411)
Cash Flows From Financing Activities
Proceeds from revolving line of credit		321,000,000				321,000,000
Proceeds from issuance of common stock, net of offering costs		—				—
Reduction of financing lease liability		(24,076)				(24,076)
Net Cash Provided by Financing Activities		320,975,924		—		320,975,924
Net Change in Cash		7,215,256				7,215,256
Cash at Beginning of Period		3,363,726				3,363,726
Cash at End of Period	$	10,578,982				10,578,982
Supplemental Cash Flow Information
Cash paid for interest	$	932,896			$	932,896
Noncash Investing and Financing Activities
Asset retirement obligation incurred during development	$	441,244				441,244
Operating lease assets obtained in exchange for new operating lease liability		539,577				539,577
Financing lease assets obtained in exchange for new financing lease liability		637,757				637,757
Capitalized expenditures attributable to drilling projects financed through current liabilities		41,800,000				41,800,000
Acquisition of oil and gas properties
Assumption of joint interest billing receivable		1,464,394				1,464,394
Assumption of prepaid assets		2,864,554				2,864,554
Assumption of accounts and revenue payables		(1,234,862)				(1,234,862)
Asset retirement obligation incurred through acquisition		(2,979,645)				(2,979,645)
Common stock issued as partial consideration in asset acquisition		(28,356,396)				(28,356,396)
Oil and gas properties subject to amortization		296,910,774				296,910,774

F-24

NOTE A2 – ABRIDGED BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

Condensed Financial Statements – The accompanying condensed financial statements prepared by Ring Energy, Inc. (the “Company” or “Ring”) have not been audited by an independent registered public accounting firm. In the opinion of the Company’s management, the accompanying unaudited financial statements contain all adjustments necessary for fair presentation of the results of operations for the periods presented, which adjustments were of a normal recurring nature, except as disclosed herein. The results of operations for the three and six months ended June 30, 2019, are not necessarily indicative of the results to be expected for the full year ending December 31, 2019.

Certain notes and other disclosures have been omitted from these interim financial statements. Therefore, these financial statements should be read in conjunction with the Company’s annual report on Form 10-K for the year ended December 31, 2018.

Income Taxes – Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes. Deferred taxes are provided on differences between the tax bases of assets and liabilities and their reported amounts in the financial statements, and tax carry forwards. Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the provision for income taxes.

In January 2017, the Company adopted ASU 2016-09, Compensation – Stock Compensation (Topic 718.) The Company used the modified retrospective method to account for unrecognized excess tax benefits from prior periods. For the three and six months ended June 30, 2019, we recorded an increase of $434,720 and $3,380,940, respectively, to our income tax provision. For the three months ended June 30, 2018, the Company recorded 0 change in the income tax provision. For the six months ended June 30, 2018, we recorded an increase of $1,158,604 to our income tax provision.

On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act of 2017 (the “Tax Act”). The SEC subsequently issued a Staff Accounting Bulletin No. 118, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act”, which provides guidance on accounting for the tax effects of the Tax Act. Among other changes, the Tax Act lowered the corporate tax rate to 21%.

NOTE B2 – REVENUE RECOGNITION

Oil sales

Under the Company’s oil sales contracts, the Company sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received.

Natural gas sales

Under the Company’s natural gas sales contracts, the Company delivers unprocessed natural gas to a midstream processing entity at the wellhead. The midstream processing entity obtains control of the natural gas at the wellhead. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of natural gas. Under these agreements, the Company recognizes revenue when control transfers to the purchaser at the point of delivery.

Disaggregation of Revenue. The following table presents revenues disaggregated by product for the three and six months ended June 30, 2019 and 2018:

	For The Three Months				For The Six Months
	Ended June 30,				Ended June 30,
	2019		2018		2019		2018
Operating revenues
Oil	$	50,793,472	$	28,962,880	$	91,671,455	$	58,103,045
Natural gas		540,753		962,003		1,461,085		1,713,229
Total operating revenues	$	51,334,225	$	29,924,883	$	93,132,540	$	59,816,274

All revenues are from production from the Permian Basin in Texas and New Mexico.

F-25

NOTE C2 – LEASES

Effective January 1, 2019, the Company adopted ASU 2016-02, Leases (Topic 842). This guidance attempts to increase transparency and comparability among organizations by recognizing certain lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP methodology and the method proposed by this new guidance is the recognition on the balance sheet of certain lease assets and lease liabilities by lessees for those leases that were classified as operating leases under previous GAAP.

The Company made accounting policy elections to not capitalize leases with a lease term of twelve months or less and to not separate lease and non-lease components for all asset classes. The Company has also elected to adopt the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases and the practical expedient regarding land easements that exist prior to the adoption of ASU 2016-02. The Company did not elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date.

The Company has operating leases for our offices in Midland, Texas and Tulsa, Oklahoma with terms through January 31, 2020. The office space being leased in Tulsa is owned by Arenaco, LLC, a company that is owned by Mr. Rochford, Chairman of the Board of the Company, and Mr. McCabe, a Director of the Company. The Company has financing leases for vehicles. Future lease payments associated with these operating leases as of June 30, 2019 are as follows:

	2019		2020		2021		2022
Operating lease payments (1)	$	256,350	$	42,725	$	—	$	—
Financing lease payments (2)		115,783		231,565		231,565		88,478

(1) The weighted average discount rate as of June 30, 2019 for operating leases was 5.01%. Based on this rate, the future lease payments above include imputed interest of $4,980.

(2) The weighted average discount rate as of June 30, 2019 for financing leases was 5.28%. Based on this rate, the future lease payments above included imputed interest of $53,710.

The following table provides supplemental information regarding cash flows from operations:

	2019
Operating lease costs	$	256,350
Short term lease costs (1)		307,518
Financing lease costs:
Amortization of financing lease assets (2)		25,956
Interest on lease liabilities (3)		4,029

(1) Amount included in Oil and gas production costs

(2) Amount included in Depreciation, depletion and amortization

(3) Amount included in Interest expense

F-26

NOTE D2 – EARNINGS PER SHARE INFORMATION

	For the Three Months Ended June 30, 2019						For the Six Months Ended June 30, 2019
	As Previously		Restatement				As Previously		Restatement
	Reported		Adjustment		As Restated		Reported		Adjustment		As Restated
Net Income	$	12,375,254	$	(1,032,657)	$	11,342,597	$	23,464,697	$	(7,852,840)	$	15,611,857
Basic Weighted-Average Shares Outstanding		67,357,645		67,357,645		67,357,645		65,305,081		65,305,081		65,305,081
Effect of dilutive securities:
Stock options		217,472		217,472		217,472		418,397		418,397		418,397
Restricted stock		95,142		95,142		95,142		128,870		128,870		128,870
Diluted Weighted-Average Shares Outstanding		67,670,259		67,670,259		67,670,259		65,852,348		65,852,348		65,852,348
Basic Income per Share	$	0.18	$	(0.02)	$	0.17	$	0.36	$	(0.12)	$	0.24
Diluted Income per Share	$	0.18	$	(0.02)	$	0.17	$	0.36	$	(0.12)	$	0.24

Stock options to purchase 1,013,500 shares of common stock and 276,860 shares of unvested restricted stock were excluded from the computation of diluted earnings per share during the three months ended June 30, 2019, as their effect would have been anti-dilutive.  Stock options to purchase 2,353,500 shares of common stock and 276,860 shares of unvested restricted stock were excluded from the computation of diluted earnings per share during the six months ended June 30, 2019, as their effect would have been anti-dilutive.

NOTE E2 – ACQUISITIONS

On April 9, 2019, the Company completed the acquisition of oil and gas 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 (the “Acquisition”). The acquired properties consist of 49,754 gross (38,230 net) acres and include a 77% average working interest and a 58% average net revenue interest. The Company incurred approximately $4.1 million in acquisition related costs, which were recognized in general and administrative expense during the six months ended June 30, 2019. Total consideration after purchase price adjustments included a cash payment of approximately $264.1 million and the issuance of 4,581,001 shares of common stock, of which 2,538,071 shares are being held in escrow to satisfy potential indemnification claims.  The full amount of the shares placed into escrow remain in escrow as of June 30, 2019.  The escrow shares will be released pursuant to the terms of the Purchase and Sale Agreement.  The shares were valued at the price on the date of the signing of the Purchase and Sale Agreement, February 25, 2019, of $6.19 per share.

The Acquisition was recognized as a business combination whereby Ring recorded the assets acquired and the liabilities assumed at their fair values as of February 1, 2019, which is the date the Company obtained control of the properties and was the acquisition date for financial reporting purposes. Revenues and related expenses for the Acquisition are included in our condensed statement of operations beginning February 1, 2019. The estimated fair value of the acquired properties approximated the consideration paid, which the Company concluded approximated the fair value that would be paid by a typical market participant. The following table summarizes the fair values of the assets acquired and the liabilities assumed:

Assets acquired:
Proved oil and gas properties	$	296,910,774
Joint interest billing receivable		1,464,394
Prepaid assets		2,864,554
Liabilities assumed
Accounts and revenues payable		(1,234,862)
Asset retirement obligations		(2,979,645)
Total Identifiable Net Assets	$	297,025,215

The Company will continue to evaluate the fair value of the assets and liabilities reflected above and will record any adjustments, if needed, in future periods.

F-27

The following unaudited pro forma information for the three and six months ended June 30, 2019 and 2018, respectively, is presented to reflect the operations of the Company as if the acquisition of assets had been completed on January 1, 2019 and 2018, respectively:

	For The Three Months				For The Six Months
	Ended June 30,				Ended June 30,
	2019		2018		2019		2018
Oil and Gas Revenues	$	57,999,639	$	48,490,870	$	99,797,954	$	91,250,272
Net Income	$	12,435,698	$	12,990,504	$	23,525,139	$	24,721,646
Basic Earnings per Share	$	0.18	$	0.21	$	0.35	$	0.41
Diluted Earnings per Share	$	0.18	$	0.21	$	0.34	$	0.40

NOTE F2 – DERIVATIVE FINANCIAL INSTRUMENTS

The Company is exposed to fluctuations in crude oil and natural gas prices on its production. It can utilize derivative strategies that consist of either a single derivative instrument or a combination of instruments to manage the variability in cash flows associated with the forecasted sale of its future domestic oil and natural gas production. While the use of derivative instruments may limit or partially reduce the downside risk of adverse commodity price movements, the use also may limit future income from favorable commodity price movements.

During March and April 2019, the Company entered into new derivative contracts in the form of costless collars of WTI Crude Oil prices in order to protect the Company’s cash flow from price fluctuation and maintain its capital programs. “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. The trades were for a total of 5,500 barrels of oil per day for the period of April 2019 through December 2019 and 2,000 barrels of oil per day for the period of January 2020 through December 2020. The following table reflects the put and call prices of those contracts:

Date entered into	Barrels per day	Put price		Call price
2019 contracts
03/12/19	1,500	$	50.00	$	66.00
03/13/19	500		50.00		67.40
03/20/19	500		50.00		67.90
03/20/19	1,000		50.00		68.71
04/01/19	1,000		50.00		69.50
04/03/19	1,000		50.00		70.20
2020 contracts
04/01/19	1,000		50.00		65.83
04/01/19	1,000		50.00		65.40

On September 25, 2017, the Company entered into derivative contracts in the form of costless collars for the period of January 2018 through December 2018 for 1,000 barrels per day with a put price of $49.00 and a call price of $54.60.

On October 27, 2017, the Company entered into costless collars of WTI Crude Oil for the period of January 2018 through December 2018 for an additional 1,000 barrels of oil per day with a put price of $51.00 and a call price of $54.80.

Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying balance sheets. Any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included as a component of other income (expense) in the accompanying statements of operations.

The use of derivative transactions involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. At June 30, 2019, 100% of our volumes subject to derivative instruments are with lenders under our Credit Facility (as defined in Note H2).

NOTE G2 – FAIR VALUE MEASUREMENTS

F-28

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The authoritative guidance requires disclosure of the framework for measuring fair value and requires that fair value measurements be classified and disclosed in one of the following categories:

Level 1:        Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2:        Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3:        Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity).

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy. We continue to evaluate our inputs to ensure the fair value level classification is appropriate. When transfers between levels occur, it is our policy to assume that the transfer occurred at the date of the event or change in circumstances that caused the transfer.

The fair values of the Company’s derivatives are not actively quoted in the open market. The Company uses a market approach to estimate the fair values of its derivative instruments on a recurring basis, utilizing commodity futures pricing for the underlying commodities provided by a reputable third party, a Level 2 fair value measurement.

The following table summarizes the valuation of our assets and liabilities that are measured at fair value on a recurring basis.

	Fair Value Measurement Classification
	Quoted prices in
	Actives Markets
	for Identical Assets		Significant Other		Significant
	or (Liabilities)		Observable Inputs		Unobservable
	(Level 1)		(Level 2)		Inputs (Level 3)		Total
As of June 30, 2019
Oil and gas derivative contracts	$	—	$	1,189,545	$	—	$	1,189,545
Total	$	—	$	1,189,545	$	—	$	1,189,545

NOTE H2 – REVOLVING LINE OF CREDIT

On July 1, 2014, the Company entered into a Credit Agreement with SunTrust Bank, as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (the “Administrative Agent”), which was amended on June 14, 2018, May 18, 2016, July 24, 2015, and June 26, 2015. In April 2019, the Company amended and restated its Credit Agreement with the Administrative Agent (as amended and restated, the “Credit Facility”). The amendment and restatement of the Credit Facility, among other things, increases the maximum borrowing amount to $1 billion, increases the borrowing base (the “Borrowing Base”) to $425 million, extends the maturity date through April 2024 and makes other modifications to the terms of the Credit Facility. The Credit Facility is secured by a first lien on substantially all of the Company’s assets.

The Borrowing Base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The Borrowing Base will be redetermined semi-annually on each May 1 and November 1. The Borrowing Base will also be reduced in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and cancellation of certain hedging positions.

The Credit Facility allows for Eurodollar Loans and Base Rate Loans. The interest rate on each Eurodollar Loan will be the adjusted LIBOR for the applicable interest period plus a margin between 1.75% and 2.75% (depending on the then-current level of Borrowing Base usage). The annual interest rate on each Base Rate Loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate,

F-29

(ii) the Federal Funds Rate (as defined in the Credit Facility) plus 0.5% per annum, the (iii) adjusted LIBOR determined on a daily basis for an interest period of one-month, plus 1.00% per annum and (iv) 0.00% per annum, plus (b) a margin between 0.75% and 1.75% (depending on the then-current level of Borrowing Base usage).

The Credit Facility contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio (as defined in the Credit Facility) of not more than 4.0 to 1.0 and (ii) a minimum current ratio of Current Assets to Current Liabilities (as such terms are defined in the Credit Facility) of 1.0 to 1.0. The Credit Facility also contains other customary affirmative and negative covenants and events of default. As of June 30, 2019, $360,500,000 was outstanding on the Credit Facility. We are in compliance with all covenants contained in the Credit Facility.

NOTE I2 – ASSET RETIREMENT OBLIGATION

The Company provides for the obligation to plug and abandon oil and gas wells at the dates properties are either acquired or the wells are drilled. The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The asset retirement obligation incurred at the time of drilling was computed using the annual credit-adjusted risk-free discount rate at the applicable dates. Changes in the asset retirement obligation were as follows:

Balance, December 31, 2018	$	13,055,797
Liabilities acquired		2,979,645
Liabilities incurred		441,244
Liabilities settled		(384,956)
Accretion expense		445,179
Balance, June 30, 2019	$	16,536,909

NOTE J2 – STOCKHOLDERS’ EQUITY

Common Stock Issued in Public Offering – In April 2019, the Company completed the acquisition of assets from Wishbone Partners, LLC as disclosed in Note E2. As a part of the consideration for the acquisition, the Company issued 4,581,001 shares of common stock, of which 2,538,071 shares are being held in escrow to satisfy potential indemnification claims arising under the Purchase Agreement.  The full amount of the shares placed into escrow remain in escrow as of June 30, 2019.  The escrow shares will be released pursuant to the terms of the Purchase and Sale Agreement. The shares were valued at February 25, 2019, the date of the signing of the Purchase and Sale Agreement. The price on February 25, 2019 was $6.19 per share. The aggregate value of the shares issued, based on this price, was $28,356,396.

In February 2018, the Company closed on an underwritten public offering of 6,164,000 shares of its common stock, including 804,000 shares sold pursuant to the full exercise of an over-allotment option, at $14.00 per share for gross proceeds of $86,296,000. Total net proceeds from the offering were $81,819,073, after deducting underwriting commissions and offering expenses payable by the Company of $4,476,927.

NOTE K2 – EMPLOYEE STOCK OPTIONS AND RESTRICTED STOCK AWARD PLAN

Compensation expense charged against income for share-based awards during the three and six months ended June 30, 2019, was $808,734 and $1,643,199, respectively, as compared to $1,081,199 and $2,083,547, respectively, for the three and six months ended June 30, 2018. These amounts are included in general and administrative expense in the accompanying financial statements.

In 2011, the board of directors and stockholders approved and adopted a long-term incentive plan which allowed for the issuance of up to 2,500,000 shares of common stock through the grant of qualified stock options, non-qualified stock options and restricted stock. In 2013, the Company’s board of directors and stockholders approved an amendment to the long-term incentive plan, increasing the number of shares eligible under the plan to 5,000,000 shares. As of June 30, 2019, there were 668,340 shares remaining eligible for issuance under the plan.

F-30

Stock Options

A summary of the stock option activity as of June 30, 2019, and changes during the six months then ended is as follows:

				Weighted-
		Weighted-		Average
		Average		Remaining	Aggregate
		Exercise		Contractual	Intrinsic
	Shares	Price		Term	Value
Outstanding, December 31, 2018	2,751,000	$	6.28
Granted	—	$	—
Forfeited or rescinded	(2,500)	$	11.70
Vested	—	$	—
Outstanding, June 30, 2019	2,748,500	$	6.28	4.5 Years	$	493,750
Exercisable, June 30, 2019	2,327,400	$	5.42	4.0 Years

The intrinsic value was calculated using the closing price on June 28, 2019 of $3.25. As of June 30, 2019, there was $1,239,664 of unrecognized compensation cost related to stock options that is expected be recognized over a weighted-average period of 1.7 years.

Restricted Stock

A summary of the restricted stock activity as of June 30, 2019, and changes during the six months then ended is as follows:

		Weighted-
		Average Grant
	Restricted stock	Date Fair Value
Outstanding, December 31, 2018	878,360	$	7.36
Granted	15,400		5.01
Forfeited or rescinded	(4,120)		7.13
Vested	(400)		13.32
Outstanding, June 30, 2018	889,240	$	7.31

As of June 30, 2019, there was $4,046,963 of unrecognized compensation cost related to restricted stock grants that will be recognized over a weighted average period of 1.9 years.

NOTE L2 – CONTINGENCIES AND COMMITMENTS

Standby Letters of Credit – A commercial bank issued standby letters of credit on behalf of the Company totaling $260,000 to state and federal agencies and $741,000 to an electric utility company. The standby letters of credit are valid until cancelled or matured and is collateralized by the revolving credit facility with the bank. The terms of the letters of credit to the state and federal agencies are extended for a term of one year at a time. The Company intends to renew the standby letters of credit to the state and federal agencies for as long as the Company does business in the States of Texas  and New Mexico. The letters of credit to the utility company should not require renewal after the initial one year term. NaN amounts have been drawn under the standby letters of credit.

Surety Bonds - An insurance company issued surety bonds on behalf of the Company totaling $500,438 to various State of New Mexico agencies in order for the Company to do business in the State of New Mexico. The surety bonds are valid until canceled or matured. The terms of the surety bonds are extended for a term of one year at a time. The Company intends to renew the surety bonds on $400,000 as long as the Company does business in the State of New Mexico. The remaining $100,438 should not require renewal after the initial one year term.

F-31

Effect of Restatement on Previously Filed September 30, 2019 Form 10-Q

Restatement of Balance Sheet as of September 30, 2019 (unaudited)

	As of September 30, 2019
	As Previously		Restatement
	Reported		Adjustment		As Restated
ASSETS
Current Assets
Cash	$	7,599,089			$	7,599,089
Accounts receivable		18,291,698				18,291,698
Joint interest billing receivable		2,025,180				2,025,180
Operating lease asset		169,115				169,115
Derivative asset		2,386,066				2,386,066
Prepaid expenses and retainers		3,340,178				3,340,178
Total Current Assets		33,811,326				33,811,326
Properties and Equipment
Oil and natural gas properties subject to depletion and amortization		1,059,284,347				1,059,284,347
Financing lease asset		947,435				947,435
Fixed assets subject to depreciation		1,465,551				1,465,551
Total Properties and Equipment		1,061,697,333				1,061,697,333
Accumulated depreciation, depletion and amortization		(142,235,581)				(142,235,581)
Net Properties and Equipment		919,461,752				919,461,752
Derivative asset		680,847				680,847
Deferred Income Taxes		5,434,238		(5,434,238)		—
Deferred Financing Costs		3,403,491				3,403,491
Total Assets	$	962,791,654	$	(5,434,238)	$	957,357,416
LIABILITIES AND STOCKHOLDERS' EQUITY						—
Current Liabilities						—
Accounts payable	$	51,813,690			$	51,813,690
Financing lease liability		272,498				272,498
Operating lease liability		169,115				169,115
Total Current Liabilities		52,255,303				52,255,303
						—
Deferred income taxes		—		3,448,958		3,448,958
Revolving line of credit		366,500,000				366,500,000
Financing lease liability		588,251				588,251
Asset retirement obligations		16,703,186				16,703,186
Total Liabilities		436,046,740		3,448,958		439,495,698
Stockholders' Equity
Preferred stock - $0.001 par value; 50,000,000 shares authorized; no shares issued or outstanding		—				—
Common stock - $0.001 par value; 150,000,000 shares authorized; 67,811,111 shares and 63,229,710 shares issued and outstanding, respectively		67,812				67,812
Additional paid-in capital		525,679,942				525,679,942
Accumulated deficit		997,160		(8,883,196)		(7,886,036)
Total Stockholders' Equity		526,744,914		(8,883,196)		517,861,718
Total Liabilities and Stockholders' Equity	$	962,791,654	$	(5,434,238)	$	957,357,416

F-32

Restatement of Statement of Operations for the three and nine months ended September 30, 2019 (unaudited)

	For the Three Months Ended September 30, 2019						For the Nine Months Ended September 30, 2019
	As Previously		Restatement				As Previously		Restatement
	Reported		Adjustment		As Restated		Reported		Adjustment		As Restated
Oil and Gas Revenues	$	50,339,105			$	50,339,105	$	143,471,645			$	143,471,645
Costs and Operating Expenses
Oil and gas production costs		15,478,052				15,478,052		36,455,925				36,455,925
Oil and gas production taxes		2,307,226				2,307,226		6,802,996				6,802,996
Depreciation, depletion and amortization		14,115,170				14,115,170		41,659,494				41,659,494
Asset retirement obligation accretion		236,207				236,207		681,386				681,386
Lease expense		114,112				114,112		370,462				370,462
General and administrative expense		3,745,928				3,745,928		15,287,072				15,287,072
Total Costs and Operating Expenses		35,996,695				35,996,695		101,257,335				101,257,335
Income from Operations		14,342,410				14,342,410		42,214,310				42,214,310
Other Income (Expense)
Interest income		9				9		13,505				13,505
Interest expense		(4,556,509)				(4,556,509)		(9,589,434)				(9,589,434)
Realized loss on derivatives		—				—		—				—
Unrealized gain on change in fair value of derivatives		1,877,368				1,877,368		3,066,913				3,066,913
Net Other Income (Expense)		(2,679,132)				(2,679,132)		(6,509,016)				(6,509,016)
Income before tax provision		11,663,278				11,663,278		35,705,294				35,705,294
Benefit from (Provision for) Income Taxes		(1,774,922)		(1,030,356)		(2,805,278)		(2,352,241)		(8,883,196)		(11,235,437)
Net Income	$	9,888,356	$	(1,030,356)	$	8,858,000	$	33,353,053	$	(8,883,196)	$	24,469,857
Basic Income per Share	$	0.15	$	(0.02)	$	0.13	$	0.50	$	(0.13)	$	0.37
Diluted Income per Share	$	0.15	$	(0.02)	$	0.13	$	0.50	$	(0.13)	$	0.37

Restatement of Statement of Shareholders’ Equity for the nine months ended September 30, 2019 (unaudited)

				Additional		Retained Earnings		Total
	Common Stock			Paid-in		(Accumulated		Stockholders'
	Shares	Amount		Capital		Deficit)		Equity
For the Nine Months Ended September 30, 2019
Balance, December 31, 2018	63,229,710	$	63,230	$	494,892,093	$	(32,355,893)	$	462,599,430
Share-based compensation	—		—		834,465		—		834,465
Net income	—		—		—		11,089,443		11,089,443
Balance, March 31, 2019	63,229,710	$	63,230	$	495,726,558	$	(21,266,450)	$	474,523,338
Common stock issued as consideration in asset acquisition	4,581,001		4,581		28,351,815		—		28,356,396
Restricted stock vested	400		—		—		—		—
Share-based compensation	—		—		808,734		—		808,734
Net income	—		—		—		12,375,254		12,375,254
Balance, June 30, 2019	67,811,111	$	67,811	$	524,887,107	$	(8,891,196)	$	516,063,722
Share-based compensation	—		—		792,836		—		792,836
Restricted stock vested	500		1		(1)		—		—
Net income	—		—		—		9,888,356		9,888,356
As Reported Balance, September 30, 2019	67,811,611	$	67,812	$	525,679,942	$	997,160	$	526,744,914
Restatement Adjustment							(8,883,196)		(8,883,196)
As Restated	67,811,611	$	67,812	$	525,679,942	$	(7,886,036)	$	517,861,718

F-33

Restatement of Statement of Cash Flows for the nine months ended September 30, 2019 (unaudited)

	For the Nine Months Ended September 30, 2019
	As Previously		Restatement
	Reported		Adjustment		As Restated
Cash Flows From Operating Activities
Net income	$	33,353,053	$	(8,883,196)	$	24,469,857
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		41,659,494				41,659,494
Accretion expense		681,386				681,386
Share-based compensation		2,436,035				2,436,035
Deferred income tax provision		7,498,112				7,498,112
Excess tax deficiency related to share-based compensation		(5,145,871)		8,883,196		3,737,325
Change in fair value of derivative instruments		(3,066,913)				(3,066,913)
Changes in assets and liabilities:
Accounts receivable		(7,095,256)				(7,095,256)
Prepaid expenses and retainers		(6,060,699)				(6,060,699)
Accounts payable		(1,055,397)				(1,055,397)
Settlement of asset retirement obligation		(615,732)				(615,732)
Net Cash Provided by (Used in) Operating Activities		62,588,212		—		62,588,212
Cash Flows From Investing Activities
Payments to purchase oil and natural gas properties		(263,262,046)				(263,262,046)
Payments to develop oil and natural gas properties		(122,004,117)				(122,004,117)
Proceeds from disposal of fixed assets subject to depreciation		—				—
Net Cash Used in Investing Activities		(385,266,163)				(385,266,163)
Cash Flows From Financing Activities
Proceeds from revolving line of credit		327,000,000				327,000,000
Proceeds from issuance of common stock, net of offering costs		—				—
Reduction of financing lease liability		(86,686)				(86,686)
Net Cash Provided by Financing Activities		326,913,314		—		326,913,314
Net Change in Cash		4,235,363				4,235,363
Cash at Beginning of Period		3,363,726				3,363,726
Cash at End of Period	$	7,599,089				7,599,089
Supplemental Cash Flow Information
Cash paid for interest	$	5,821,545			$	5,821,545
Noncash Investing and Financing Activities
Asset retirement obligation incurred during development	$	602,090				602,090
Operating lease assets obtained in exchange for new operating lease liability		539,577				539,577
Financing lease assets obtained in exchange for new financing lease liability		947,435				947,435
Capitalized expenditures attributable to drilling projects financed through current liabilities		26,958,655				26,958,655
Acquisition of oil and gas properties
Assumption of joint interest billing receivable		1,464,394				1,464,394
Assumption of prepaid assets		2,864,554				2,864,554
Assumption of accounts and revenue payables		(1,234,862)				(1,234,862)
Asset retirement obligation incurred through acquisition		(2,979,645)				(2,979,645)
Common stock issued as partial consideration in asset acquisition		(28,356,396)				(28,356,396)
Oil and gas properties subject to amortization		296,910,774				296,910,774

F-34

NOTE A3 – ABRIDGED BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

Condensed Financial Statements – The accompanying condensed financial statements prepared by Ring Energy, Inc. (the “Company” or “Ring”) have not been audited by an independent registered public accounting firm.  In the opinion of the Company’s management, the accompanying unaudited financial statements contain all adjustments necessary for fair presentation of the results of operations for the periods presented, which adjustments were of a normal recurring nature, except as disclosed herein. The results of operations for the three and nine months ended September 30, 2019, are not necessarily indicative of the results to be expected for the full year ending December 31, 2019.

Certain notes and other disclosures have been omitted from these interim financial statements. Therefore, these financial statements should be read in conjunction with the Company’s annual report on Form 10-K for the year ended December 31, 2018.

Income Taxes – Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes. Deferred taxes are based on differences between the tax bases of assets and liabilities and their reported amounts in the financial statements, and tax carry forwards. Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the provision for income taxes.

In January 2017, the Company adopted ASU 2016-09, Compensation – Stock Compensation (Topic 718) The Company used the modified retrospective method to account for unrecognized excess tax benefits from prior periods. For the three and nine months ended September 30, 2019, we recorded an increase of $355,990 and $3,737,325, respectively, to our income tax provision. For the three and nine months ended September 30, 2018, we recorded a decrease of $724,073 and an increase of $434,530, respectively, to our income tax provision.

On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act of 2017 (the “Tax Act”). The SEC subsequently issued a Staff Accounting Bulletin No. 118, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act”, which provides guidance on accounting for the tax effects of the Tax Act. Among other changes, the Tax Act lowered the corporate tax rate to 21%.

NOTE B3 – REVENUE RECOGNITION

Oil sales

Under the Company’s oil sales contracts, the Company sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received.

Natural gas sales

Under the Company’s natural gas sales contracts, the Company delivers unprocessed natural gas to a midstream processing entity at the wellhead. The midstream processing entity obtains control of the natural gas at the wellhead. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of natural gas. Under these agreements, the Company recognizes revenue when control transfers to the purchaser at the point of delivery.

Disaggregation of Revenue. The following table presents revenues disaggregated by product for the three and nine months ended September 30, 2019 and 2018:

	For The Three Months				For The Nine Months
	Ended September 30,				Ended September 30,
	2019		2018		2019		2018
Operating revenues
Oil	$	49,502,656	$	31,633,777	$	141,174,111	$	89,736,822
Natural gas		836,449		1,053,402		2,297,534		2,766,631
Total operating revenues	$	50,339,105	$	32,687,179	$	143,471,645	$	92,503,453

All revenues are from production from the Permian Basin in Texas and New Mexico.

F-35

NOTE C3 – LEASES

Effective January 1, 2019, the Company adopted ASU 2016-02, Leases (Topic 842). This guidance attempts to increase transparency and comparability among organizations by recognizing certain lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP methodology and the method proposed by this new guidance is the recognition on the balance sheet of certain lease assets and lease liabilities by lessees for those leases that were classified as operating leases under previous GAAP.

The Company made accounting policy elections to not capitalize leases with a lease term of twelve months or less and to not separate lease and non-lease components for all asset classes. The Company has also elected to adopt the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases and the practical expedient regarding land easements that exist prior to the adoption of ASU 2016-02. The Company did not elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date.

The Company has operating leases for our offices in Midland, Texas and Tulsa, Oklahoma with terms through January 31, 2020. The office space being leased in Tulsa is owned by Arenaco, LLC, a company that is owned by Mr. Rochford, Chairman of the Board of the Company, and Mr. McCabe, a Director of the Company. The Company has financing leases for vehicles. Future lease payments associated with these operating leases as of September 30, 2019 are as follows:

	2019		2020		2021		2022
Operating lease payments (1)	$	128,175	$	42,725	$	—	$	—
Financing lease payments (2)		77,802		311,206		311,206		132,499

(1) The weighted average discount rate as of September 30, 2019 for operating leases was 5.01%.  Based on this rate, the future lease payments above include imputed interest of $1,785.

(2) The weighted average discount rate as of September 30, 2019 for financing leases was 5.26%.  Based on this rate, the future lease payments above include imputed interest of $71,116.

The following table provides supplemental information regarding cash flows from operations:

	2019
Operating lease costs	$	384,525
Short term lease costs (1)		461,277
Financing lease costs:
Amortization of financing lease assets (2)		98,868
Interest on lease liabilities (3)		15,019

(1) Amount included in Oil and gas production costs

(2) Amount included in Depreciation, depletion and amortization

(3) Amount included in Interest expense

F-36

NOTE D3 – EARNINGS PER SHARE INFORMATION

	For the Three Months Ended September 30, 2019						For the Nine Months Ended September 30, 2019
	As Previously		Restatement				As Previously		Restatement
	Reported		Adjustment		As Restated		Reported		Adjustment		As Restated
Net Income	$	9,888,356	$	(1,030,356)	$	8,858,000	$	33,353,053	$	(8,883,196)	$	24,469,857
Basic Weighted-Average Shares Outstanding		67,811,127		67,811,127		67,811,127		66,149,469		66,149,469		66,149,469
Effect of dilutive securities:
Stock options		25,841		25,841		25,841		204,639		204,639		204,639
Restricted stock		—		—		—		47,314		47,314		47,314
Diluted Weighted-Average Shares Outstanding		67,836,968		67,836,968		67,836,968		66,401,422		66,401,422		66,401,422
Basic Income per Share	$	0.15	$	(0.02)	$	0.13	$	0.50	$	(0.13)	$	0.37
Diluted Income per Share	$	0.15	$	(0.02)	$	0.13	$	0.50	$	(0.13)	$	0.37

Stock options to purchase 2,353,500 shares of common stock and 3,250,420 shares of unvested restricted stock were excluded from the computation of diluted earnings per share during the three months ended September 30, 2019, as their effect would have been anti-dilutive.  Stock options to purchase 2,353,500 shares of common stock and 2,639,540 shares of unvested restricted stock were excluded from the computation of diluted earnings per share during the nine months ended September 30, 2019, as their effect would have been anti-dilutive.

NOTE E3 – ACQUISITIONS

On April 9, 2019, the Company completed the acquisition of oil and gas 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 (the “Acquisition”). The acquired properties consist of 49,754 gross (38,230 net) acres and include a 77% average working interest and a 58% average net revenue interest. The Company incurred approximately $4.1 million in acquisition related costs, which were recognized in general and administrative expense during the nine months ended September 30, 2019. Total consideration after purchase price adjustments included a cash payment of approximately $264.1 million and the issuance of 4,581,001 shares of common stock, of which 2,538,071 shares are being held in escrow to satisfy potential indemnification claims.  The full amount of the shares placed into escrow remain in escrow as of September 30, 2019.  The escrow shares will be released pursuant to the terms of the Purchase and Sale Agreement.  The shares were valued at the price on the date of the signing of the Purchase and Sale Agreement, February 25, 2019, of $6.19 per share.

The Acquisition was recognized as a business combination whereby Ring recorded the assets acquired and the liabilities assumed at their fair values as of February 1, 2019, which is the date the Company obtained control of the properties and was the acquisition date for financial reporting purposes. Revenues and related expenses for the Acquisition are included in our condensed statement of operations beginning February 1, 2019. The estimated fair value of the acquired properties approximated the consideration paid, which the Company concluded approximated the fair value that would be paid by a typical market participant. The following table summarizes the fair values of the assets acquired and the liabilities assumed:

Assets acquired:
Proved oil and gas properties	$	296,910,774
Joint interest billing receivable		1,464,394
Prepaid assets		2,864,554
Liabilities assumed
Accounts and revenues payable		(1,234,862)
Asset retirement obligations		(2,979,645)
Total Identifiable Net Assets	$	297,025,215

The Company will continue to evaluate the fair value of the assets and liabilities reflected above and will record any adjustments, if needed, in future periods.

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The following unaudited pro forma information for the three and nine months ended September 30, 2019 and 2018, respectively, is presented to reflect the operations of the Company as if the acquisition of assets had been completed on January 1, 2019 and 2018, respectively:

	For The Three Months				For The Nine Months
	Ended September 30,				Ended September 30,
	2019		2018		2019		2018
Oil and Gas Revenues	$	57,004,519	$	51,167,164	$	150,137,059	$	142,417,436
Net Income	$	9,948,798	$	14,004,402	$	33,413,495	$	38,125,515
Basic Earnings per Share	$	0.15	$	0.23	$	0.49	$	0.63
Diluted Earnings per Share	$	0.15	$	0.22	$	0.49	$	0.61

NOTE F3 – DERIVATIVE FINANCIAL INSTRUMENTS

The Company is exposed to fluctuations in crude oil and natural gas prices on its production. It can utilize derivative strategies that consist of either a single derivative instrument or a combination of instruments to manage the variability in cash flows associated with the forecasted sale of its future domestic oil and natural gas production. While the use of derivative instruments may limit or partially reduce the downside risk of adverse commodity price movements, the use also may limit future income from favorable commodity price movements.

During March and April 2019, the Company entered into new derivative contracts in the form of costless collars of WTI Crude Oil prices in order to protect the Company’s cash flow from price fluctuation and maintain its capital programs. “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. The trades were for a total of 5,500 barrels of oil per day for the period of April 2019 through December 2019 and 2,000 barrels of oil per day for the period of January 2020 through December 2020. The following table reflects the put and call prices of those contracts:

Date entered into	Barrels per day	Put price		Call price
2019 contracts
03/12/19	1,500	$	50.00	$	66.00
03/13/19	500		50.00		67.40
03/20/19	500		50.00		67.90
03/20/19	1,000		50.00		68.71
04/01/19	1,000		50.00		69.50
04/03/19	1,000		50.00		70.20
2020 contracts
04/01/19	1,000		50.00		65.83
04/01/19	1,000		50.00		65.40

On September 25, 2017, the Company entered into derivative contracts in the form of costless collars for the period of January 2018 through December 2018 for 1,000 barrels per day with a put price of $49.00 and a call price of $54.60.

On October 27, 2017, the Company entered into costless collars of WTI Crude Oil for the period of January 2018 through December 2018 for an additional 1,000 barrels of oil per day with a put price of $51.00 and a call price of $54.80.

On August 27, 2018, the Company entered into additional costless collars of WTI Crude Oil.  This trade is for the period January 1, 2019 through December 31, 2019 for 2,000 barrels of oil per day with a put price of $60.00 and a call price of $70.05.  Subsequent to September 30, 2018, the Company terminated all of the costless collars for calendar year 2019 described above through the payment of $3,438,300.

Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying balance sheets. Any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included as a component of other income (expense) in the accompanying statements of operations.

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The use of derivative transactions involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. At September 30, 2019, 100% of our volumes subject to derivative instruments are with lenders under our Credit Facility (as defined in Note H3).

NOTE G3 – FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The authoritative guidance requires disclosure of the framework for measuring fair value and requires that fair value measurements be classified and disclosed in one of the following categories:

Level 1:        Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2:        Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3:        Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity).

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy. We continue to evaluate our inputs to ensure the fair value level classification is appropriate. When transfers between levels occur, it is our policy to assume that the transfer occurred at the date of the event or change in circumstances that caused the transfer.

The fair values of the Company’s derivatives are not actively quoted in the open market. The Company uses a market approach to estimate the fair values of its derivative instruments on a recurring basis, utilizing commodity futures pricing for the underlying commodities provided by a reputable third party, a Level 2 fair value measurement.

The following table summarizes the valuation of our assets and liabilities that are measured at fair value on a recurring basis.

	Fair Value Measurement Classification
	Quoted prices in
	Actives Markets
	for Identical Assets		Significant Other		Significant
	or (Liabilities)		Observable Inputs		Unobservable
	(Level 1)		(Level 2)		Inputs (Level 3)		Total
As of September 30, 2019
Oil and gas derivative contracts	$	—	$	3,066,913	$	—	$	3,066,913
Total	$	—	$	3,066,913	$	—	$	3,066,913

NOTE H3 – REVOLVING LINE OF CREDIT

On July 1, 2014, the Company entered into a Credit Agreement with SunTrust Bank, as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (the “Administrative Agent”), which was amended on June 14, 2018, May 18, 2016, July 24, 2015, and June 26, 2015. In April 2019, the Company amended and restated its Credit Agreement with the Administrative Agent (as amended and restated, the “Credit Facility”). The amendment and restatement of the Credit Facility, among other things, increases the maximum borrowing amount to $1 billion, increases the borrowing base (the “Borrowing Base”) to $425 million, extends the maturity date through April 2024 and makes other modifications to the terms of the Credit Facility. The Credit Facility is secured by a first lien on substantially all of the Company’s assets.

The Borrowing Base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The Borrowing Base will be redetermined semi-annually on each May 1 and November 1. The Borrowing Base will also be reduced in

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certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and cancellation of certain hedging positions.

The Credit Facility allows for Eurodollar Loans and Base Rate Loans. The interest rate on each Eurodollar Loan will be the adjusted LIBOR for the applicable interest period plus a margin between 1.75% and 2.75% (depending on the then-current level of Borrowing Base usage). The annual interest rate on each Base Rate Loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the Federal Funds Rate (as defined in the Credit Facility) plus 0.5% per annum, the (iii) adjusted LIBOR determined on a daily basis for an interest period of one-month, plus 1.00% per annum and (iv) 0.00% per annum, plus (b) a margin between 0.75% and 1.75% (depending on the then-current level of Borrowing Base usage).

The Credit Facility contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio (as defined in the Credit Facility) of not more than 4.0 to 1.0 and (ii) a minimum current ratio of Current Assets to Current Liabilities (as such terms are defined in the Credit Facility) of 1.0 to 1.0. The Credit Facility also contains other customary affirmative and negative covenants and events of default. As of September 30, 2019, $366,500,000 was outstanding on the Credit Facility. We are in compliance with all covenants contained in the Credit Facility.

NOTE I3 – ASSET RETIREMENT OBLIGATION

The Company provides for the obligation to plug and abandon oil and gas wells at the dates properties are either acquired or the wells are drilled. The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The asset retirement obligation incurred at the time of drilling was computed using the annual credit-adjusted risk-free discount rate at the applicable dates. Changes in the asset retirement obligation were as follows:

Balance, December 31, 2018	$	13,055,797
Liabilities acquired		2,979,645
Liabilities incurred		602,090
Liabilities settled		(615,732)
Accretion expense		681,386
Balance, September 30, 2019	$	16,703,186

NOTE J3 – STOCKHOLDERS’ EQUITY

Common Stock Issued in Public Offering – In April 2019, the Company completed the acquisition of assets from Wishbone Partners, LLC as disclosed in Note E3. As a part of the consideration for the acquisition, the Company issued 4,581,001 shares of common stock, of which 2,538,071 shares are being held in escrow to satisfy potential indemnification claims arising under the Purchase Agreement.  The full amount of the shares placed into escrow remain in escrow as of September 30, 2019.  The escrow shares will be released pursuant to the terms of the Purchase and Sale Agreement. The shares were valued at February 25, 2019, the date of the signing of the Purchase and Sale Agreement. The price on February 25, 2019 was $6.19 per share. The aggregate value of the shares issued, based on this price, was $28,356,396.

In February 2018, the Company closed on an underwritten public offering of 6,164,000 shares of its common stock, including 804,000 shares sold pursuant to the full exercise of an over-allotment option, at $14.00 per share for gross proceeds of $86,296,000. Total net proceeds from the offering were $81,819,073, after deducting underwriting commissions and offering expenses payable by the Company of $4,476,927.

Common Stock Issued in Option Exercise – During the nine months ended September 30, 2018, the Company issued 103,113 shares of common stock as the result of cashless option exercises.  The following table presents the details of those exercises:

	Exercise	Shares	Shares	Stock price on	Aggregate value of
Options exercised	price ($)	issued	retained	date of exercise ($)	shares retained ($)
25,000	7.50	9,829	15,171	12.36	187,500
3,000	8.00	1,059	1,941	12.36	24,000
3,000	5.25	1,750	1,250	12.36	15,750
2,000	11.75	100	1,900	12.36	23,500
110,000	2.00	90,375	19,625	11.21	220,000

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Totals	143,000		103,113	39,887		470,750
Average		3.29			11.80

NOTE K3 – EMPLOYEE STOCK OPTIONS AND RESTRICTED STOCK AWARD PLAN

Compensation expense charged against income for share-based awards during the three and nine months ended September 30, 2019, was $792,836 and $2,436,035, respectively, as compared to $1,007,789 and $3,091,336, respectively, for the three and nine months ended September 30, 2018. These amounts are included in general and administrative expense in the accompanying financial statements.

In 2011, the board of directors and stockholders approved and adopted a long-term incentive plan which allowed for the issuance of up to 2,500,000 shares of common stock through the grant of qualified stock options, non-qualified stock options and restricted stock. In 2013, the Company’s board of directors and stockholders approved an amendment to the long-term incentive plan, increasing the number of shares eligible under the plan to 5,000,000 shares. As of September 30, 2019, there were 665,160 shares remaining eligible for issuance under the plan.

Stock Options

A summary of the stock option activity as of September 30, 2019, and changes during the nine months then ended is as follows:

				Weighted-
		Weighted-		Average
		Average		Remaining	Aggregate
		Exercise		Contractual	Intrinsic
	Shares	Price		Term	Value
Outstanding, December 31, 2017	3,193,000	$	6.07
Granted	—	$	—
Forfeited or rescinded	(24,500)	$	11.39
Exercised	(143,000)	$	3.29
Outstanding, September 30, 2018	3,025,500	$	6.15	5.3 Years	$	12,470,645
Exercisable, September 30, 2018	2,265,400	$	4.92	4.6 Years
Outstanding, December 31, 2018	2,751,000	$	6.28
Granted	—	$	—
Forfeited or rescinded	(2,500)	$	11.70
Vested	—	$	—
Outstanding, September 30, 2019	2,748,500	$	6.28	4.2 Years	$	—
Exercisable, September 30, 2019	2,329,400	$	5.43	3.7 Years

The intrinsic value was calculated using the closing price on September 30, 2018 and 2019 of $9.91 and $1.64, respectively. As of September 30, 2019, there was $919,908 of unrecognized compensation cost related to stock options that is expected be recognized over a weighted-average period of 1.6 years.

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Restricted Stock

A summary of the restricted stock activity as of September 30, 2019, and changes during the nine months then ended is as follows:

		Weighted-
		Average Grant
	Restricted stock	Date Fair Value
Outstanding, December 31, 2017	330,900	$	13.44
Granted	4,500		11.40
Forfeited or rescinded	(4,000)		13.44
Vested	—		—
Outstanding, September 30, 2018	331,400	$	13.41
Outstanding, December 31, 2018	878,360	$	7.36
Granted	20,400		4.59
Forfeited or rescinded	(5,940)		6.88
Vested	(900)		11.40
Outstanding, September 30, 2019	891,920	$	7.30

As of September 30, 2019, there was $3,451,385 of unrecognized compensation cost related to restricted stock grants that will be recognized over a weighted average period of 1.1 years.

NOTE L3 – CONTINGENCIES AND COMMITMENTS

Standby Letters of Credit – A commercial bank issued standby letters of credit on behalf of the Company totaling $260,000 to state and federal agencies and $741,000 to an electric utility company. The standby letters of credit are valid until cancelled or matured and is collateralized by the revolving credit facility with the bank. The terms of the letters of credit to the state and federal agencies are extended for a term of one year at a time. The Company intends to renew the standby letters of credit to the state and federal agencies for as long as the Company does business in the States of Texas  and New Mexico. The letters of credit to the utility company should not require renewal after the initial one year term. NaN amounts have been drawn under the standby letters of credit.

Surety Bonds - An insurance company issued surety bonds on behalf of the Company totaling $500,438 to various State of New Mexico agencies in order for the Company to do business in the State of New Mexico. The surety bonds are valid until canceled or matured. The terms of the surety bonds are extended for a term of one year at a time. The Company intends to renew the surety bonds on $400,000 as long as the Company does business in the State of New Mexico. The remaining $100,438 should not require renewal after the initial one year term.

NOTE 3 – REVENUE RECOGNITION

Oil sales

Under the Company’s oil sales contracts, the Company sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received.

Natural gas sales

Under the Company’s natural gas sales processing contracts for our Central Basin Platform properties, Delaware Basin properties and part of our Northwest Shelf assets, the Company delivers unprocessed natural gas to a midstream processing entity at the wellhead. The midstream processing entity obtains control of the natural gas at the wellhead. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of natural gas. Under these processing agreements, the Company recognizes revenue when control transfers to the purchaser at the point of delivery. As such, the Company accounts for any fees and deductions as a reduction of the transaction price.

Under the Company natural gas sales processing contracts for the bulk of our Northwest Shelf assets, the Company delivers unprocessed natural gas to a midstream processing entity at the well head.  However, the Company maintains ownership of the gas through processing and receives proceeds from the marketing of the resulting products.  Under this processing agreement, the Company recognizes the fees associated with the processing as an expense rather than netting these costs against revenue.

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Disaggregation of Revenue. The following table presents revenues disaggregated by product:

	For the years ended December 31,
	2019		2018		2017
Operating revenues
Oil	$	191,891,314	$	116,678,375	$	64,236,490
Natural gas		3,811,517		3,386,986		2,463,210
Total operating revenues	$	195,702,831	$	120,065,361	$	66,699,700

NOTE 4 – LEASES

Effective January 1, 2019, the Company adopted ASU 2016-02, Leases (Topic 842).  This guidance attempts to increase transparency and comparability among organizations by recognizing certain lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP methodology and the method proposed by this new guidance is the recognition on the balance sheet of certain lease assets and lease liabilities by lessees for those leases that were classified as operating leases under previous GAAP.

The Company made accounting policy elections to not capitalize leases with a lease term of twelve months or less and to not separate lease and non-lease components for all asset classes. The Company has also elected to adopt the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases and the practical expedient regarding land easements that exist prior to the adoption of ASU 2016-02. The Company did not elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date.

The Company has operating leases for our offices in Midland, Texas and Tulsa, Oklahoma that are month to month but which the Company intends to continue through at least December 31, 2020.  As such, these leases have been accounted for as operating leases with terms that end on December 31, 2020.  The office space being leased in Tulsa is owned by Arenaco, LLC, a company that is owned by Mr. Rochford, Chairman of the Board of the Company, and Mr. McCabe, a Director of the Company.

The Company also has month to month leases for office equipment and compressors used in our operations on which the Company has elected to apply ASU 2016-02.  While these leases are month to month, the Company intends to continue these leases for the useful life of the assets.  As such, these leases have been accounted for as if the lease term lasts through the estimated useful life of the assets.

The Company also has month to month leases or other short term leases for equipment used in our operations on which the Company has made accounting policy elections not to capitalize these leases.  These leases are for terms that are less than 12 months and the Company does not intend to continue to lease this equipment for more than 12 months.  The lease costs associated with these leases is reflected in the short term lease costs below.

The Company also has financing leases for vehicles.  These leases have a term of 36 months at the end of which the Company owns the vehicles.  These vehicles are generally sold at the end of their term and the proceeds applied to a new vehicle.

Future lease payments associated with these operating and financing leases as of December 31, 2019 are as follows:

	2020		2021		2022
Operating lease payments (1)	$	1,236,779	$	708,392	$	—
Financing lease payments (2)		311,206		311,206		132,499

(1) The weighted average discount rate as of December 31, 2019 for operating leases was 4.49%. Based on this rate, the future lease payments above include imputed interest of $78,126. The weighted average remaining term of operating leases was 1.7 years.

(2) The weighted average discount rate as of December 31, 2019 for financing leases was 5.26%. Based on this rate, the future lease payments above include imputed interest of $49,815. The weighted average remaining term of financing leases was 2.42 years.

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The following table provides supplemental information regarding cash flows from operations:

	2019
Operating lease costs	$	925,217
Short term lease costs (1)		5,692,924
Financing lease costs:
Amortization of financing lease assets (2)		178,132
Interest on lease liabilities (3)		26,090

(1) Amount included in Oil and gas production costs

(2) Amount included in Depreciation, depletion and amortization

(3) Amount included in Interest expense

NOTE 5 – EARNINGS (LOSS) PER SHARE INFORMATION

For the years ended December 31,	2019		2018		2017
Net Income	$	29,496,551	$	8,999,760	$	1,753,869
Basic Weighted-Average Shares Outstanding		66,571,738		59,531,200		51,383,008
Effect of dilutive securities:
Stock options		174,944		1,238,786		1,413,932
Restricted stock		10,346		78,191		9,772
Diluted Weighted-Average Shares Outstanding		66,757,028		60,848,177		52,806,712
Basic Earnings per Share	$	0.44	$	0.15	$	0.03
Diluted Earnings per Share	$	0.44	$	0.15	$	0.03

Stock options to purchase 2,353,500, 574,500 and 603,500 shares of common stock were excluded from the computation of diluted earnings per share during the years ended December 31, 2019, 2018 and 2017, respectively, as their effect would have been anti-dilutive.  704,684 and 2,500 shares of unvested restricted stock were excluded from the computation of diluted earnings per share during the years ended December 31, 2019 and 2018, respectively, as their effect would have been anti-dilutive.

NOTE 6 – ACQUISITIONS

In December 2018, Ring completed the acquisition of oil and natural gas assets and properties in assets in Andrews County. The acquired properties consist of 4,854 gross (4,788 net) acres and include a 100% working interest and a 75% net revenue interest. Consideration given by the Company consisted of 2,623,948 shares valued at $5.80 per share for an aggregate value of $11,204,258 and liabilities assumed of $2,571,549. The Company incurred approximately $23,321 in acquisition related costs, which were recognized in general and administrative expense during the year ended December 31, 2018.

The acquisition was recognized as a business combination whereby Ring recorded the assets acquired and the liabilities assumed at their fair values as of November 1, 2018, which is the date the Company obtained control of the properties and was the acquisition date for financial reporting purposes.

The estimated fair value of the acquired properties approximated the consideration paid, which the Company concluded approximated the fair value that would be paid by a typical market participant. The following table summarizes the fair values of the assets acquired and the liabilities assumed:

Assets acquired
Proved oil and natural gas properties	$	13,775,807
Liabilities assumed
Asset retirement obligations		(2,571,549)
Total Identifiable Net Assets	$	11,204,258

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On April 9, 2019, the Company completed the acquisition of oil and gas 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 (the “Acquisition”).  The acquired properties consist of 49,754 gross (38,230 net) acres and include a 77% average working interest and a 58% average net revenue interest. Ring executed the Acquisition for the existing production and future development potential. The Company incurred approximately $4.1 million in acquisition related costs, which were recognized in general and administrative expense.  Total consideration after purchase price adjustments included cash payments totaling approximately $276.1 million and the issuance of 4,576,951 shares of common stock, of which 2,538,071 shares were placed in escrow to satisfy potential indemnification claims.  One half of the shares placed into escrow remain in escrow as of December 31, 2019. The range of potential outcomes regarding the indemnification escrow shares cannot be determined as the Company evaluates whether there are any claims against the indemnification. If no claims are made, the remaining escrow shares will be released pursuant to the terms of the Purchase and Sale Agreement.  The shares were valued at the price on the date of the signing of the Purchase and Sale Agreement, February 25, 2019, of $6.19 per share.

The Acquisition was recognized as a business combination whereby Ring recorded the assets acquired and the liabilities assumed at their fair values as of February 1, 2019, which is the date the Company obtained control of the properties and was the acquisition date for financial reporting purposes. The Company determined that it had effective control of the properties effective February 1, 2019 based on Ring having primary decision making ability regarding the properties beginning at that time. Revenues and related expenses for the Acquisition are included in our condensed statement of operations beginning February 1, 2019.  The estimated fair value of the acquired properties approximated the consideration paid, which the Company concluded approximated the fair value that would be paid by a typical market participant. The following table summarizes the fair values of the assets acquired and the liabilities assumed:

Assets acquired:
Proved oil and gas properties	$	305,004,775
Joint interest billing receivable		1,464,394
Prepaid assets		2,864,554
Liabilities assumed
Accounts and revenues payable		(1,234,861)
Asset retirement obligations		(3,705,941)
Total Identifiable Net Assets	$	304,392,921

The revenues and direct operating costs associated with the acquired properties included in our financial statements for the year ended December 31, 2019 are as follows:

Revenue	$	105,102,038
Oil and natural gas production costs		17,037,228
Oil and natural gas production taxes		4,646,660
Total direct costs (1)		21,683,888
Earnings from the Acquired properties	$	83,418,150

(1) This includes only oil and natural gas production costs and oil and natural gas production taxes and does not give account to depreciation, depletion and amortization, accretion of asset retirement obligation, general and administrative expense, interest expense or any other cost that cannot be directly correlated to the Acquisition.

The following unaudited pro forma information for the years ended December 30, 2019 and 2018, respectively, is presented to reflect the operations of the Company as if the acquisition of assets had been completed on January 1, 2019 and 2018, respectively:

For the years ended December 31,	2019		2018
Oil and Gas Revenues	$	202,368,245	$	196,385,905
Net Income	$	29,556,993	$	29,105,827
Basic Earnings per Share	$	0.44	$	0.49
Diluted Earnings per Share	$	0.44	$	0.48

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NOTE 7 – OIL AND NATURAL GAS PRODUCING ACTIVITIES

Set forth below is certain information regarding the aggregate capitalized costs of oil and natural gas properties and costs incurred by the Company for its oil and natural gas property acquisitions, development and exploration activities:

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

As of December 31,	2019		2018
Proved oil and natural gas properties	$	1,083,966,135	$	641,121,398
Financing lease asset subject to depreciation		858,513		—
Fixed assets subject to depreciation		1,465,551		1,465,551
Total capitalized costs		1,086,290,199		642,586,949
Accumulated depletion, depreciation and amortization		(157,074,044)		(100,576,087)
Net Capitalized Costs	$	929,216,155	$	542,010,862

Net Costs Incurred in Oil and Gas Producing Activities

For the years Ended December 31,	2019		2018
Payments for the Wishbone Acquisition	$	276,061,594	$	—
Payments to purchase oil and natural gas properties		3,400,411		4,656,484
Proceeds from divestiture of oil and natural gas properties		(8,547,074)		—
Payments to develop oil and natural gas properties		152,125,320		198,870,366
Total Net Costs Incurred	$	423,040,251	$	203,526,850

NOTE 8 – DERIVATIVE FINANCIAL INSTRUMENTS

The Company is exposed to fluctuations in crude oil and natural gas prices on its production. We can utilize derivative strategies that consist of either a single derivative instrument or a combination of instruments to manage the variability in cash flows associated with the forecasted sale of our future domestic oil and natural gas production. While the use of derivative instruments may limit or partially reduce the downside risk of adverse commodity price movements, their use also may limit future income from favorable commodity price movements.

On September 25, 2017, the Company entered into new derivative contracts in the form of costless collars of WTI Crude Oil prices in order to protect the Company’s cash flow from price fluctuation and maintain its capital programs. “Costless collars” are the combination of two options, a put option (floor) and 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. The two trades were for each 1,000 barrels of oil per day. For the period of October 1, 2017 through December 31, 2017, the put price is $49.00 and the call price is $55.35. For the period of January 1, 2018 through December 31, 2018, the put price is $49.00 and the call price is $54.60.

On October 27, 2017, the Company entered in additional costless collars of WTI Crude Oil. This trade is for the period January 1, 2018 through December 31, 2018 for 1,000 barrels of oil per day with a put price of $51.00 and a call price of $54.80.

On August 27, 2018, the Company entered into additional costless collars of WTI Crude Oil. This trade is for the period January 1, 2019 through December 31, 2019 for 2,000 barrels of oil per day with a put price of $60.00 and a call price of $70.05. On October 10, 2018, the Company terminated these costless collars for calendar year 2019 through the payment of $3,438,300.

As of December 31, 2018, all derivative contracts had either expired or been terminated and the Company does not currently have any derivative contracts in place.

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On April and November 2019, the Company entered into costless collars of WTI Crude Oil for the period January 1, 2020 through December 31, 2020. The following table reflects the details of those contracts:

Date entered into	Barrels per day	Put price	Call price
2020 contracts
04/01/19	1,000	50.00	65.83
04/01/19	1,000	50.00	65.40
11/05/19	1,000	50.00	58.40
11/07/19	1,000	50.00	58.25
11/11/19	1,500	50.00	58.65

Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying balance sheets. Any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included as a component of other income in the accompanying statements of operations.

The use of derivative transactions involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. All previous derivative contracts have been with lenders under our credit facility.

NOTE 9 – FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The authoritative guidance requires disclosure of the framework for measuring fair value and requires that fair value measurements be classified and disclosed in one of the following categories:

Level 1:        Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2:        Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3:        Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity).

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy. We continue to evaluate our inputs to ensure the fair value level classification is appropriate. When transfers between levels occur, it is our policy to assume that the transfer occurred at the date of the event or change in circumstances that caused the transfer.

As a result of the Wishbone Acquisition, the Company evaluated the fair value of the assets acquired and the liabilities assumed. The Company recorded the oil and gas assets acquired in the Wishbone Acquisition at the price paid. Prior to doing so, the Company evaluated to determine that the price paid approximated the fair value of the assets acquired. In doing so, the Company compared the price paid per BOE of existing production to comparable companies enterprise value per BOE of existing production. Additionally, the Company did an evaluation of the reserves acquired, based on varying percentages of the present value discounted at 10 percent (PV-10) of the different categories (PDP, PDNP and PUD) of the reserves. Based on these evaluations, we determined that the price paid was a reasonable approximation of the fair value of the oil and gas assets acquired. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy.

The Company recorded the prepaid expenses, joint interest billing receivables and revenues payable at the carrying value assumed from Wishbone. The carrying amounts of receivables and accounts payable and other current assets and liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities.

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The fair values of the Company’s derivatives are not actively quoted in the open market. The Company uses a market approach to estimate the fair values of its derivative instruments on a recurring basis, utilizing commodity futures pricing for the underlying commodities provided by a reputable third party, a Level 2 fair value measurement.

The following table summarizes the valuation of our assets and liabilities that are measured at fair value on a recurring basis.

	Fair Value Measurement Classification
	Quoted prices in
	Active Markets
	for Identical Assets		Significant Other		Significant
	or (Liabilities)		Observable Inputs		Unobservable
	(Level 1)		(Level 2)		Inputs (Level 3)		Total
As of December 31, 2017
Oil and gas derivative contracts	$	—	$	(3,968,286)	$	—	$	(3,968,286)
Total	$	—	$	(3,968,286)	$	—	$	(3,968,286)
As of December 31, 2018
Oil and gas derivative contracts	$	—	$	—	$	—	$	—
Total	$	—	$	—	$	—	$	—
As of December 31, 2019
Oil and gas derivative contracts	$	—	$	(3,000,078)	$	—	$	(3,000,078)
Total	$	—	$	(3,000,078)	$	—	$	(3,000,078)

NOTE 10 – REVOLVING LINE OF CREDIT

On July 1, 2014, the Company entered into a Credit Agreement with SunTrust Bank, as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (the “Administrative Agent”), which was amended on June 14, 2018, May 18, 2016, July 24, 2015, and June 26, 2015. In April 2019, the Company amended and restated its Credit Agreement with the Administrative Agent (as amended and restated, the “Credit Facility”). The amendment and restatement of the Credit Facility, among other things, increases the maximum borrowing amount to $1 billion, increases the borrowing base (the “Borrowing Base”) to $425 million, extends the maturity date through April 2024 and makes other modifications to the terms of the Credit Facility. The Credit Facility is secured by a first lien on substantially all of the Company’s assets.

The Borrowing Base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The Borrowing Base will be redetermined semi-annually on each May 1 and November 1. The Borrowing Base will also be reduced in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and cancellation of certain hedging positions.

The Credit Facility allows for Eurodollar Loans and Base Rate Loans. The interest rate on each Eurodollar Loan will be the adjusted LIBOR for the applicable interest period plus a margin between 1.75% and 2.75% (depending on the then-current level of Borrowing Base usage). The annual interest rate on each Base Rate Loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the Federal Funds Rate (as defined in the Credit Facility) plus 0.5% per annum, the (iii) adjusted LIBOR determined on a daily basis for an interest period of one-month, plus 1.00% per annum and (iv) 0.00% per annum, plus (b) a margin between 0.75% and 1.75% (depending on the then-current level of Borrowing Base usage).

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The Credit Facility contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio (as defined in the Credit Facility) of not more than 4.0 to 1.0 and (ii) a minimum current ratio of Current Assets to Current Liabilities (as such terms are defined in the Credit Facility) of 1.0 to 1.0. The Credit Facility also contains other customary affirmative and negative covenants and events of default.  As of December 31, 2019, $366,500,000 was outstanding on the Credit Facility.  We are in compliance with all covenants contained in the Credit Facility.

NOTE 11 – ASSET RETIREMENT OBLIGATION

A reconciliation of the asset retirement obligation for the years ended December 31, 2017, 2018 and 2019 is as follows:

Balance, December 31, 2016	$	7,957,035
Liabilities incurred		1,297,289
Liabilities settled		(766,595)
Accretion expense		567,968
Balance, December 31, 2017	$	9,055,697
Liabilities acquired		2,571,549
Liabilities incurred		1,311,956
Liabilities settled		(577,824)
Revision of estimate (1)		87,960
Accretion expense		606,459
Balance, December 31, 2018	$	13,055,797
Liabilities acquired		3,745,642
Liabilities incurred		631,727
Liabilities settled		(1,589,654)
Accretion expense		943,707
Balance, December 31, 2019	$	16,787,219

(1) Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, and estimated remaining useful life of the assets. The 2018 revision of estimates reflect decreases in the estimated remaining useful life of certain assets.

NOTE 12 – STOCKHOLDERS’ EQUITY

The Company is authorized to issue 150,000,000 common shares, with a par value of $0.001 per share and 50,000,000 shares of Preferred Stock.

Common Stock Issued in Public Offering – In July 2017, the Company closed on an underwritten public offering of 4,977,658 shares of its common stock, including 477,658 shares sold pursuant to the partial exercise of an over-allotment option, at $12.50 per share for gross proceeds of $62,220,725. Total net proceeds from the offering were $59,026,956, after deducting underwriting commissions and offering expenses payable by the Company of $3,193,769.

In February 2018, the Company closed on an underwritten public offering of 6,164,000 shares of its common stock, including 804,000 shares sold pursuant to the full exercise of an over-allotment option, at $14.00 per share for gross proceeds of $86,296,000. Total net proceeds from the offering were $81,821,138, after deducting underwriting commissions and offering expenses payable by the Company of $4,474,862.

Common stock issued in property acquisition – As discussed in Note 6, in December 2018, the Company issued 2,623,948 shares of common stock as consideration for the acquisition of oil and natural gas properties. These shares were valued at $5.80 per share for an aggregate of $11,204,258.

Also as discussed in Note 6, in April 2019, the Company completed the acquisition of assets from Wishbone Partners, LLC.  As a part of the consideration for the acquisition, the Company issued 4,576,951 shares of common stock, of which 2,538,071 shares were placed in escrow to satisfy potential indemnification claims arising under the Purchase Agreement.  One half of the shares placed into escrow remain in escrow as of December 31, 2019.  The escrow shares will be released pursuant to the terms of the Purchase and Sale Agreement.  The shares were valued at February 25, 2019, the date of the signing of the Purchase and Sale Agreement.  The price on February 25, 2019 was $6.19 per share.  The aggregate value of the shares issued, based on this price, was $28,331,327.  

F-49

Common Stock Issued for option exercises – During the years ended December 31, 2017 and 2018, the Company issued 133,308 and 153,113 shares of common stock as a result of option exercises, respectively.   No options were exercised in 2019. The following tables present the details of the 2017 and 2018 exercises:

				���					Stock price on		Aggregate value
	Options	Exercise			Shares	Shares	Cash paid at		date of exercise		of shares retained
	exercised	price ($)			issued	retained	exercise ($)		($)		($)
2017	4,100	$	2.00		3,491	609	$	—	$	13.47	$	8,200
	60,000		2.00		50,156	9,844		—		12.19		120,000
	200		8.00		116	84		—		13.75		1,600
	1,500		10.89		1,188	312		—		13.75		16,335
	600		5.25		229	371		—		13.75		3,150
	20,000		5.50		11,953	8,047		—		13.67		110,000
	2,000		8.00		830	1,170		—		13.67		16,000
	2,000		5.25		1,232	768		—		13.67		10,500
	15,000		2.00		12,875	2,125		—		14.12		30,000
	60,000		2.00		51,238	8,762		—		13.70		120,000
2017 Totals	165,400				133,308	32,092	$	—			$	435,785
2017 Weighted Averages		$	2.63						$	13.18

								Stock price on		Aggregate value
	Options	Exercise		Shares	Shares	Cash paid at		date of exercise		of shares retained
	exercised	price ($)		issued	retained	exercise ($)		($)		($)
2018	110,000	$	2.00	90,375	19,625	$	—	$	11.21	$	220,000
	50,000		2.00	50,000	—		100,000		8.00		—
	25,000		7.50	9,829	15,171		—		12.36	$	187,500
	3,000		8.00	1,059	1,941		—		12.36	$	24,000
	3,000		5.25	1,750	1,250		—		12.36	$	15,750
	2,000		11.75	100	1,900		—		12.36	$	23,500
2018 Totals	193,000			153,113	39,887	$	100,000			$	470,750
2018 Weighted Averages		$	2.96					$	10.58

NOTE 13 – EMPLOYEE STOCK OPTIONS, RESTRICTED STOCK AWARD PLAN AND 401(k)

In 2011, the Company’s Board of Directors approved and adopted a long term incentive plan, which was subsequently approved and amended by the shareholders. There were 28,955 shares eligible for grant, either as options or as restricted stock, at December 31, 2019.

Employee Stock Options – Following is a table reflecting the issuances during 2017 and their related exercise prices (No options were granted in 2018 or 2019):

Grant date	# of options	Exercise price
April 20, 2017	7,500	$	11.70

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All granted options vest at the rate of 20% each year over five years beginning one year from the date granted and expire ten years from the grant date. A summary of the status of the stock options as of December 31, 2019, 2018 and 2017 and changes during the years ended December 31, 2019, 2018 and 2017 is as follows:

	2019			2018			2017
		Weighted-			Weighted-			Weighted-
		Average			Average			Average
	Options	Exercise Price		Options	Exercise Price		Options	Exercise Price
Outstanding at beginning of the year	2,751,000	$	6.28	3,193,000	$	6.07	3,362,350	$	5.90
Issued	—		—	—		—	7,500		11.70
Forfeited or rescinded	(2,500)		11.70	(249,000)		6.09	(11,450)		10.12
Exercised	—		—	(193,000)		2.96	(165,400)		2.63
Outstanding at end of year	2,748,500	$	6.28	2,751,000	$	6.28	3,193,000	$	6.07
Exercisable at end of year	2,506,700	$	5.78	2,323,900	$	5.42	2,091,900	$	4.85
Weighted average fair value of options granted during the year		$	—		$	—		$	9.14

The Company uses the Black-Scholes option pricing model to calculate the fair-value of each option grant. The expected volatility is based on the historical price volatility of the Company’s common stock. We elected to use the simplified method for estimating the expected term as allowed by generally accepted accounting principles for options granted during the years ended December 31, 2017.  No options were granted during 2018 or 2019.  Under the simplified method, the expected term is equal to the midpoint between the vesting period and the contractual term of the stock option. The risk-free interest rate represents the U.S. Treasury bill rate for the expected life of the related stock options. The dividend yield represents the Company’s anticipated cash dividend over the expected life of the stock options. The following are the Black-Scholes weighted-average assumptions used for options granted during the periods ended December 31, 2017:

	Risk free interest rate		Expected life (years)	Dividend yield	Volatility
April 20, 2017	1.78	%	6.5	—	94	%

No options were granted during 2018 or 2019.

For the years ended December 31, 2019, 2018 and 2017, the Company incurred stock based compensation expense related to stock options of $625,855, $1,853,913 and $3,618,309, respectively. As of December 31, 2019, there was $702,934 of unrecognized compensation cost related to stock options that will be recognized over a weighted average period of 1.5 years. The aggregate intrinsic value of options vested and expected to vest at December 31, 2019 was $278,400. The aggregate intrinsic value of options exercisable at December 31, 2019 was $278,400. The year-end intrinsic values are based on a December 31, 2019 closing price of $2.64.

Options exercised of 193,000 in 2018 and 165,400 in 2017 had an aggregate intrinsic value on the date of exercise of $1,470,230 and $1,744,047, respectively.  No options were exercised in 2019.

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The following table summarizes information related to the Company’s stock options outstanding at December 31, 2019:

	Options Outstanding
		Weighted-
		Average
		Remaining
	Number	Contractual Life	Number
Exercise price	Outstanding	(in years)	Exercisable
2.00	395,000	2.17	395,000
4.50	1,340,000	3.24	1,340,000
5.50	5,000	3.45	5,000
7.50	4,000	3.73	4,000
10.00	90,000	4.21	90,000
14.54	10,000	4.99	10,000
8.00	277,500	5.17	277,500
8.25	50,000	6.19	40,000
6.42	15,000	6.59	9,000
11.75	557,000	7.20	334,200
11.70	5,000	7.55	2,000
	2,748,500	4.20	2,506,700

Restricted stock grants – Following is a table reflecting the restricted stock grants during 2017, 2018 and 2019:

	# of shares of
Grant date	restricted stock
December 19, 2017	330,900
April 4, 2018	2,000
September 27, 2018	2,500
December 26, 2018	615,380
April 9, 2019	10,400
May 30, 2019	5,000
July 9, 2019	5,000
September 13, 2019	10,000
December 21, 2019	627,205

All restricted stock grants vest at the rate of 20% each year over five years beginning one year from the date granted. A summary of the status of restricted stock grants as of December 31, 2019, 2018 and 2017 and changes during the years ended December 31, 2019, 2018 and 2017 is as follows:

	2019			2018			2017
		Weighted-
		Average
		Grant			Weighted-			Weighted-
		Date Fair			Average Grant			Average Grant
	Restricted stock	Value		Restricted stock	Date Fair Value		Restricted stock	Date Fair Value
Outstanding at beginning of the year	878,360	$	7.33	330,900	$	13.44	—	$	—
Granted	657,605		2.63	619,880		4.78	330,900		13.44
Forfeited or rescinded	(6,940)		4.23	(7,800)		13.44	—		—
Vested	(187,136)		7.79	(64,620)		13.44	—		—
Outstanding at end of year	1,341,889	$	4.99	878,360	$	7.33	330,900	$	13.44

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For the years ended December 31, 2019, 2018 and 2017, the Company incurred stock based compensation expense related to restricted stock grants of $2,456,770, $2,017,021 and $66,770. As of December 31, 2019, there was $4,451,903 of unrecognized compensation cost related to restricted stock grants that will be recognized over a weighted average period of 1.8 years.

During 2019 and 2018, 187,136 and 64,620 shares of restricted stock vested, respectively. At the dates of vesting those shares had an aggregate intrinsic value of $494,605 and $304,360, respectively.  No restricted stock vested during 2017.

401(k) Plan- In 2019, the Company initiated a sponsored 401(k) plan that is a defined contribution plan for the benefit of all eligible employees. The plan allows eligible employees to make pre-tax or after-tax contributions of up to 100% of their annual eligible compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6% of any employee's compensation. Employees are 100% vested in the employer contribution upon receipt.

The following table presents the matching contributions expense recognized for the Company's 401(k) plan for the year ended December 31, 2019. There were no matching contributions prior to 2019.

	2019
Employer safe harbor match	59,716

NOTE 14 – RELATED PARTY TRANSACTIONS

The Company is leasing office space from Arenaco, LLC, a company that is owned by two stockholders’ of the Company, Mr. Rochford, Chairman of the Board of the Company, and Mr. McCabe, a Director of the Company. During the years ended December 31, 2019, 2018 and 2017, the Company paid $60,000, $60,000 and $60,000, respectively, to this company.

NOTE 15 – COMMITMENTS AND CONTINGENT LIABILITIES

Standby Letters of Credit – A commercial bank issued standby letters of credit on behalf of the Company totaling $260,000 to state and federal agencies and $741,000 to an electric utility company.  The standby letters of credit are valid until cancelled or matured and is collateralized by the revolving credit facility with the bank.  The terms of the letters of credit to the state and federal agencies are extended for a term of one year at a time.  The Company intends to renew the standby letters of credit to the state and federal agencies for as long as the Company does business in the States of Texas and New Mexico. The letters of credit to the utility company should not require renewal after the initial one year term. NaN amounts have been drawn under the standby letters of credit.

Surety Bonds – An insurance company issued surety bonds on behalf of the Company totaling $500,438 to various State of New Mexico agencies in order for the Company to do business in the State of New Mexico.  The surety bonds are valid until canceled or matured.  The terms of the surety bonds are extended for a term of one year at a time.  The Company intends to renew the surety bonds on $400,000 as long as the Company does business in the State of New Mexico.  The remaining $100,438 should not require renewal after the initial one year term.

NOTE 16 – INCOME TAXES

For the years ended December 31, 2019, 2018 and 2017, components of our provision for income taxes are as follows:

Provision for Income Taxes	2019		2018		2017
Deferred taxes	$	13,787,654	$	3,445,721	$	10,416,171
Provision for Income Taxes	$	13,787,654	$	3,445,721	$	10,416,171

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The following is a reconciliation of income taxes computed using the U.S. federal statutory rate to the provision for income taxes:

Rate Reconciliation	2019		2018		2017
Tax at federal statutory rate	$	9,089,683	$	2,613,551	$	4,194,556
Non-deductible expenses		2,399		3,197		6,158
Excess tax benefit from stock option exercises and restricted stock vesting		4,055,418		828,973		(453,217)
Adjust prior estimates to tax return		19		—		(58,766)
States taxes, net of Federal benefit		160,913		—		124,200
Effect of departure from State of Kansas		—		—		(350,059)
Adjustment for change in future effective tax rate (1) (2)		479,222		—		6,953,299
Provision for Income Taxes	$	13,787,654	$	3,445,721	$	10,416,171

(1) The enactment of the Tax Cuts and Jobs Act provided for a decrease in the corporate tax rate to 21% from 35%, resulting in a net $6.95 million reduction to our net deferred tax asset as of December 31, 2017. The Wishbone Acquisition referenced in Note 6 added properties in the State of New Mexico and thereby adjusted our effective tax rate for 2019.

(2) The acquisition of the Northwest Shelf assets from Wishbone included properties in the State of New Mexico. The tax rates associated with the State of New Mexico adjusted our overall tax rate from 21% to 21.29%. This resulted in an additional tax expense during the year ended December 31, 2019 of $479,222.

The net deferred taxes consisted of the following at December 31, 2019 and 2018:

Deferred Taxes:	2019		2018
Deferred tax liabilities
Property and equipment	$	56,325,029	$	33,888,806
Deferred tax assets
Stock-based compensation		269,264		3,734,911
Operating loss and IDC carryforwards		50,054,589		37,940,374
Deferred tax assets		50,323,853		41,675,285
Net deferred income tax liability (asset)	$	6,001,176	$	(7,786,479)

As of December 31, 2019, the Company had net operating loss carry forwards for federal income tax reporting purposes of approximately $107.4 million which, if unused, will begin to expire in 2027 and fully expire in 2038 and an additional $129.9 million that will not expire.

NOTE 17 – QUARTERLY FINANCIAL DATA (UNAUDITED)

	2017
	Three Months Ended
	March 31		June 30		September 30		December 31
Revenues	$	12,243,793	$	14,503,309	$	16,643,930	$	23,308,668
Operating Income		2,502,852		2,621,612		4,292,081		6,550,596
Net Income (Loss)		1,279,281		1,910,763		3,073,760		(4,509,935)
Basic Net Income (Loss) Per Share	$	0.03	$	0.04	$	0.06	$	(0.08)
Diluted Net Income (Loss) Per Share		0.03		0.04		0.06		(0.08)

	2018
	Three Months Ended
	March 31		June 30		September 30		December 31
Revenues	$	29,891,391	$	29,924,883	$	32,687,179	$	27,561,908
Operating Income (Loss)		10,935,120		9,397,559		9,615,030		(9,986,770)
Net Income (Loss)		5,665,634		4,719,806		5,693,628		(7,079,308)
Basic Net Income (Loss) Per Share	$	0.10	$	0.08	$	0.09	$	(0.12)
Diluted Net Income (Loss) Per Share		0.10		0.08		0.09	$	(0.12)

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	2019
	Three Months Ended
	March 31		June 30		September 30		December 31
	(restated)		(restated)		(restated)
Revenues	$	41,798,315	$	51,334,225	$	50,339,105	$	52,231,186
Operating Income		10,235,485		17,636,415		14,342,410		17,922,018
Net Income		4,269,260		11,342,597		8,858,000		5,026,692
Basic Net Income Per Share	$	0.07	$	0.17	$	0.13	$	0.08
Diluted Net Income Per Share		0.07		0.17		0.13	$	0.08

NOTE 18 – SUBSEQUENT EVENTS

Subsequent to December 31, 2019, the Company entered into new derivative contracts covering 4,500 barrels of oil per day for the period of January 2021 through December 2021. All of the derivative contracts 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. Please see the below table for information related to the put prices and call prices for the derivative contracts in place for 2021.

Date entered into	Barrels per day	Put price		Call price
2021 contracts
02/25/20	1,000	$	45.00	$	54.72
02/25/20	1,000		45.00		52.71
02/27/20	1,000		40.00		55.08
03/02/20	1,500		40.00		55.35

Subsequent to December 31, 2019, there has been a significant decline in oil prices due to global circumstances that are out of our control. As a result, the value of our derivative contracts has changed significantly. As of December 31, 2019, our balance sheet reflected a $3,000,078 derivative liability. As of March 16, 2020, there has been an unrealized gain on derivativs and that liability has become an asset.

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RING ENERGY, INC.

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES

(Unaudited)

Results of Operations from Oil and Natural Gas Producing Activities – The Company’s results of operations from oil and natural gas producing activities exclude interest expense, gain from change in fair value of put options, and other financing expense. Income taxes are based on statutory tax rates, reflecting allowable deductions.

For the years ended December 31,	2019		2018		2017
Oil and natural gas sales	$	195,702,831	$	120,065,361	$	66,699,700
Production costs		(48,496,225)		(27,801,989)		(15,978,362)
Production taxes		(9,130,379)		(5,631,093)		(3,152,562)
Depreciation, depletion, amortization and accretion		(56,204,269)		(39,024,886)		(21,085,748)
Ceiling test impairment		—		(14,172,309)		—
General and administrative (exclusive of corporate overhead)		(5,696,189)		(1,404,635)		(995,265)
Results of Oil and Natural Gas Producing Operations	$	76,175,769	$	32,030,449	$	25,487,763

Reserve Quantities Information – The following estimates of proved and proved developed reserve quantities and related standardized measure of discounted net cash flow are estimates only, and do not purport to reflect realizable values or fair market values of the Company’s reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available. All of the Company’s reserves are located in the United States of America.

Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment and methods.

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The standardized measure of discounted future net cash flows is computed by applying the price according to the SEC guidelines for oil and natural gas to the estimated future production of proved oil and natural gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows.

For the Year Ended December 31,	2019		2018
	Oil (1)	Natural Gas (1)	Oil (1)	Natural Gas (1)
Proved Developed and Undeveloped Reserves
Beginning of year	27,809,748	52,765,698	28,943,742	18,037,489
Purchases of minerals in place	36,501,824	41,921,368	2,582,718	1,332,439
Improved recovery	4,732,449	2,530,636	1,142,222	4,197,487
Extensions and discoveries	13,295,301	5,501,627	7,425,387	32,867,798
Sale of minerals in place	(758,169)	(811,279)	—	—
Production	(3,536,126)	(2,476,472)	(2,047,295)	(1,112,177)
Upward revision of estimate	2,731,228	1,618,234	193,531	93,562
Downward revision of estimate due to well performance	(3,699,908)	(11,680,453)	(1,145,110)	(477,732)
Downward revision of estimate due to commodity prices	(3,655,679)	(28,789,545)	(1,498,282)	(1,636,515)
Downward revision of estimate due to removal of undeveloped locations	(2,061,654)	(2,307,932)	(492,388)	(209,168)
Downward revision of estimate due to removal of waterflood reserves	—	—	(7,294,777)	(327,485)
End of year	71,359,014	58,271,882	27,809,748	52,765,698
Proved Developed at beginning of year	19,206,048	32,413,447	15,321,600	12,647,200
Proved Undeveloped at beginning of year	8,603,700	20,352,251	13,622,142	5,390,289
Proved Developed at end of year	41,242,050	34,467,870	19,206,048	32,413,447
Proved Undeveloped at end of year	30,116,964	23,804,012	8,603,700	20,352,251

¹ Oil reserves are stated in barrels; natural gas reserves are stated in thousand cubic feet.

Standardized Measure of Discounted Cash Flows

December 31,	2019		2018
Future cash flows	$	3,825,773,515	$	1,805,419,612
Future production costs		(964,887,856)		(594,609,134)
Future development costs		(252,457,833)		(94,973,603)
Future income taxes		(424,715,966)		(176,430,782)
Future net cash flows		2,183,711,860		939,406,093
10% annual discount for estimated timing of cash flows		(1,260,536,809)		(483,461,452)
Standardized Measure of Discounted Cash Flows	$	923,175,051	$	455,944,641

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Changes in Standardized Measure of Discounted Future Net Cash Flows

	2019		2018
Beginning of the year	$	455,944,641	$	322,465,119
Purchase of minerals in place		598,489,190		50,094,951
Improved recovery, less related costs		86,989,301		145,717,969
Extensions and discoveries, less related costs		247,652,632		22,365,230
Development costs incurred during the year		152,125,320		198,870,366
Sales of oil and gas produced, net of production costs		(137,663,314)		(92,263,372)
Sales of minerals in place		(30,174,528)		—
Accretion of discount		47,463,292		38,426,781
Net changes in price and production costs		(219,608,128)		178,396,156
Net change in estimated future development costs		47,617,158		(56,282,127)
Upward revisions		44,034,636		4,975,263
Revision of previous quantity estimates as a result well performance		(64,553,979)		(39,785,033)
Revision of previous quantity estimates as a result of commodity prices		(71,545,320)		(29,332,880)
Revision of previous quantity estimates as a result removal of uneconomic proved undeveloped locations		(34,079,006)		(17,681,142)
Revision of previous quantity estimates as a result removal of proved undeveloped locations due to changes in previously adopted development plans		—		(178,024,754)
Revision of estimated timing of cash flows		(107,443,484)		(66,002,740)
Net change in income taxes		(92,073,360)		(25,995,146)
End of the Year	$	923,175,051	$	455,944,641

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