United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-K

(Mark One)

For the fiscal year ended December 31, 2018

Or

For the transition period from ___________to ___________

Commission file number 001-36057

Ring Energy, Inc.

(Exact name of registrant as specified in its charter)

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

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 x

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 x

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the 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 x 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 x No ¨

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

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.

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 x

As of June 30, 2018, 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 $12.62 per share, was approximately $715,824,081.

As of February 26, 2019, the issuer had outstanding 63,229,710 shares of common stock ($0.001 par value).

TABLE OF CONTENTS

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

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 in Andrews County and Gaines County, Texas and the Delaware Basin in Reeves County and Culberson County, Texas, all of which are part of the Permian Basin.

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, as well as to continue to evaluate potential transactions to acquire attractive acreage positions within our core areas of interest. In 2018, we increased our acreage positions to 127,422 gross (96,026 net) acres with 107,203 gross (76,028 net) acres in Andrews and Gaines counties and 20,219 gross (19,998 net) acres in Reeves and Culberson counties.

As of December 31, 2018, Ring increased its proved reserves to approximately 36.6 million BOE (barrel of oil equivalent), all of which relate to its properties located in the Permian Basin in Texas. 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 76% of proved reserves consisting of oil and 24% consisting of natural gas. Of those reserves, 61% of the proved reserves are classified as proved developed producing, or “PDP,” 6% are classified as proved developed non-producing, or “PDNP,” and 33% are classified as proved undeveloped, or “PUD.”

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, 2018, increased 55% to 2,232,658 BOE, as compared to sales of 1,438,647 BOE for the year ended December 31, 2017. 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, 2018, will be credited in the first quarter of 2019.

Ring believes that there is significant value to be created by drilling the identified undeveloped opportunities on its Texas properties. As of December 31, 2018, Ring owned interests in a total of 19,432 gross (17,408 net) developed acres and 87,771 gross (58,620 net) undeveloped acres in Andrews and Gaines Counties, Texas. In these counties, the Company has 62 identified proven vertical drilling locations and 19 identified proven horizontal locations based on the reserve reports as of December 31, 2018, and an additional 563 potential vertical drilling locations based on 10-acre downspacing and 769 potential horizontal drilling locations based on 6 wells per section or 106 acres per well. Also as of December 31, 2018, 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 39 identified proven vertical drilling locations and identified proven horizontal locations based on the reserve reports as of December 31, 2018 and an additional 430 potential vertical drilling locations based on 20-acre downspacing. 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

Ring Energy’s Strengths

Competitive Business Conditions

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

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 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 our primary pricing risk to be related to a potential decline in prices to a level which could render our current production uneconomical.

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, because 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). With respect to our oil production, we are not subject to third party gathering systems. Some of our oil production is sold through a third party pipeline which has no regional competition and all other oil production is transported by the oil purchaser by trucks with competitive trucking costs in the area.

Major Customers

We principally sell our oil and natural gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities. In areas where there is no practical access to pipelines, oil is trucked to storage facilities.

For the fiscal year ended December 31, 2018, sales to two customers, Occidental Energy Marketing (“Oxy”) and Plains Marketing, L.P. (“Plains”) represented 85% and 11%, respectively, of our oil and natural gas revenues. At December 31, 2018, Oxy represented 90% of our accounts receivable and Plains represented 5%. 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, 2018, 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 Texas has regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, 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, Texas imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

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

Regulation of Transportation of Oil

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

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

Regulation of Transportation and Sale of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.

Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct 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 gas and oil production, with limited direct regulation by such federal agencies as the Environmental Protection Agency. However, while we believe this generally to be the case for our production activities in Texas, there are various regulations issued by the Environmental Protection Agency (“EPA”) and other governmental agencies that would govern significant spills, blow-outs, or uncontrolled emissions.

In Texas specific oil and natural gas regulations apply to 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 breach 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.

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, 2018, we had forty two 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.

Business Segments

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

Principal Executive Office

Our principal executive offices are located at 901 West Wall St., 3^rd Floor, Midland, TX 79702, and our telephone number is (432) 682-7464.

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.

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

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:

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 will also negatively impact the value of our proved reserves. A substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

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

Because a substantial percentage of our proven properties are proved undeveloped (approximately 33%) or proved developed non-producing (approximately 6%), we will require significant additional capital to develop such properties before they may become productive. Further, because of the inherent uncertainties associated with drilling for oil and gas, some of these properties may never be developed to the extent that they result in positive cash flow. Even if we are successful in our development efforts, it could take several years for a significant portion of our undeveloped properties to be converted to positive cash flow.

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

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

Our future success will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. 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:

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:

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

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

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

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

Decreases in oil and natural gas prices may require us to take write-downs of the carrying values of our oil and natural gas properties, potentially requiring earlier than anticipated debt repayment 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 existing credit facility, a write-down in the carrying values of our properties could require us to repay any outstanding debt earlier than we would otherwise be required. A write-down could also constitute a non-cash charge to earnings. It is likely the cumulative effect of a write-down could also negatively impact the trading price of our securities.

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.

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 (45%) 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:

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:

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

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

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition as well as the industry in general. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed.

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

We have a credit facility in place with $175 million in commitments for borrowings and letters of credit. As of December 31, 2018, $39.5 million was outstanding on our credit facility. If in the future we further utilize this facility, the level of our indebtedness could affect our operations in several ways, including the following:

In addition, our bank borrowing base is subject to quarterly redeterminations. If we use our credit facility, we could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flows and income.

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 ultimately 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.

Currently, the majority of our production is sold to marketers and other purchasers that have access to nearby pipeline facilities. However, as we begin to 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.

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. While intended to reduce the effects of volatile crude oil and natural gas prices, such transactions may limit our potential gains if crude oil and natural gas prices rise over the price established by the arrangements. As of December 31, 2018, we have no hedging arrangements in place with respect to our expected production.

We rely on computer and telecommunications systems, and failures in our systems or cyber security attacks could materially disrupt our business operations.

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, 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, computer viruses or malware. We believe that we have positive relations with our vendors and maintain satisfactory anti-virus and malware software and controls. 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, stiff competition for acquisitions may significantly increase the cost of available properties. We compete for the personnel and equipment required to explore, develop and operate properties. Our competitors also may have established long-term strategic positions and relationships in areas in which we may seek to enter. Consequently, our competitors may be able to address these competitive factors more effectively than we can. If we are not successful in our competition for oil and natural gas reserves or in our marketing of production, then our financial condition and operation results may be adversely affected.

If oil and natural gas prices decrease, we may be required to record additional write-downs of the carrying value of our oil and natural gas properties in the future.

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. During the year ended December 31, 2018, we recorded a non-cash write down of $14.2 million. We did not record a write down during 2017. 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.

Risks Relating to Our Common Stock

We have no plans to pay dividends on our common stock. Stockholders may not receive funds without selling their shares.

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 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.

None.

General Background

Ring is currently engaged in oil and natural gas acquisition, exploration, development and production, with activities and operations currently in Texas. Our strategy and plan is to focus on the development of our existing properties, while continuing to pursue acquisitions of oil and natural gas properties with significant upside potential.

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, 2018, we owned interests in a total of 38,755 gross (36,545 net) developed acres and operate nearly 100% of our acreage position. In addition, as of December 31, 2018, we owned interests in approximately 88,667 gross (59,481 net) undeveloped acres. While our focus will be toward growth through additional acquisitions and leasing, our long term plans include drilling wells on our existing acreage to develop the potential contained therein.

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 Texas Operations

Andrews and Gaines County leases – In 2011, we acquired a 100% working interest and a 75% net revenue interest in the 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, 2018, we own 107,203 gross (76,028 net), acres with 19,432 gross (17,408 net) acres developed and held by production and the remaining 87,771 gross acres (58,620 net) being undeveloped. We believe the Andrews and Gaines County leases contain a considerable number of remaining potential drilling locations. Our reserve estimates include 62 proven vertical and 19 horizontal PUD wells. Our reserve estimates include the capital costs required to develop these wells.

Culberson and Reeves County leases – In 2015, we acquired properties consisting of 19,983 gross acres (19,679 net) 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, 2018, 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 Culberson and Reeves County leases contain a considerable number of remaining potential drilling locations. Our reserve estimates include 39 proved vertical and 2 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 will usually be conducted and any significant defects will be 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 instead 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, 2018, our estimated proved reserves had a pre-tax PV10 value of approximately $541.6 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. We spent approximately $368.1 million on acquisitions and capital projects during 2017 and 2018. 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, 2018. All of our reserves are in the Permian Basin in the State of Texas.

Reserve Quantity Information

Our estimates of proved reserves and related valuations were 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.

Our proved oil and natural gas reserves are shown below.

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, 2018 are based on an average price of $58.74 for oil and $3.26 for natural gas compared to $47.93 for oil and $3.61 for natural gas as of December 31, 2017.

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

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

Proved Reserves

We have approximately 36.6 million BOE of proved reserves, which consist of approximately 76% oil and 24% natural gas, which are summarized below as of December 31, 2018, 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, 2018, approximately 61% of the proved reserves have been classified as proved developed producing, or “PDP”. Proved developed non-producing, or “PDNP” reserves constitute approximately 6% and proved undeveloped, or “PUD”, reserves constitute approximately 33%, of the proved reserves.

As of December 31, 2018, our total proved reserves had a net pre-tax PV10 value of approximately $541.6 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $455.9 million. Approximately $362.9 million and $305.5 million, respectively, of total proved reserves are associated with the PDP reserves, which is approximately 67% of the total proved reserves’ pre-tax PV10 value. An additional $41.8 million and $35.2 million, respectively, are associated with the PDNP reserves, which is approximately 8% of total proved reserves’ pre-tax PV10 value. The remaining $136.9 million and $115.3 million, respectively, are associated with PUD reserves.

Proved Undeveloped Reserves

Our reserve estimates as of December 31, 2018 include 12.0 million BOE as proved undeveloped reserves. As of December 31, 2017, our reserve estimates included approximately 14.5 million BOE as proved undeveloped reserves. Following is a description of the changes in our PUD reserves from December 31, 2017 to December 31, 2018.

During the year ended December 31, 2018, we incurred costs of approximately $21.8 million to convert 1,580,604 BOE of reserves from PUD to PDP through development.

Other changes to our PUD reserves included:

Our proved reserves as of December 31, 2018 are summarized in the table below.

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.

Internal Controls Over Reserves Estimates

All of our proved reserves estimates shown in the Annual Report on Form 10-K at December 31, 2018, 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 31, 2019, 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 29 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

The 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. Daniel Wilson, a petroleum engineer and businessman, has over 30 years of experience in operating, evaluating and exploiting oil and natural gas properties. Mr. Kelly 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 2018 is summarized below. The following table indicates the percentage of our estimated December 2018 average daily production of 5,903 BOE/d attributable to oil versus natural gas production. All production was within the State of Texas.

Acreage

The following table summarizes gross and net developed and undeveloped acreage at December 31, 2018 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.

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

The following table sets forth the gross and net undeveloped acreage, as of December 31, 2018, 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:

Production History

The following table presents the historical information about our produced natural gas and oil volumes.

The following tables provides historical pricing and costs statistics for the years ended December 31, 2016, 2017 and 2018.

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, 2018, 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.

Drilling Activity

During 2018, we drilled 57 gross (56.25 net) wells in the Delaware Basin and Central Platform Basin in the Permian Basin. We completed and placed on production 55 of these gross (54.28 net) wells, leaving 2 gross (1.97 net) horizontal wells drilled but not completed as of December 31, 2018. 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 Central Basin Platform or Delaware Basin in the Permian Basin.

(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.

Present Activities

As of December 31, 2018, we had 3 gross (3 net) wells awaiting completion. There were no wells in the process of being drilled or completed.

Cost Information

We conduct our oil and natural gas activities entirely in the United States. As noted previously in the table appearing under “Production History”, our average production costs, per BOE, were $11.24, $11.11 and $12.45 during the years ended December 31, 2016, 2017 and 2018, respectively, and our average production taxes, per BOE, were $1.71, $2.19 and $2.52 for the years ended December 31, 2016, 2017 and 2018, 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, 2017 and 2018 are shown below.

(1) 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.

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.

Not applicable.

PART II

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, 2013, 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 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 19, 2019, there are approximately 7,783 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.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table sets forth information concerning our executive stock compensation plans as of December 31, 2018.

For additional information regarding the Company’s benefit plans and share-based compensation expense, see Notes 9 and 10 in the Notes to the Financial Statements.

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

On December 21, 2018, the Company issued 2,623,948 shares of its common stock to Tessara Petroleum Resources, LLC (“Tessara”), pursuant to a Purchase and Sale Agreement dated December 14, 2018 wherein the Company agreed to acquire certain oil and natural gas properties and interests in the Permian Basin from Tessara in exchange for stock consideration. The shares were issued without registration under the Securities Act by reason of the exemption from the registration afforded by the provisions of Section 4(a)(2) of the Securities Act of 1933, as amended, and Rule 506(b) promulgated thereunder for sales of unregistered securities. We filed a registration statement on Form S-3 covering these securities on February 4, 2019, SEC File No. 333-229515, which has not yet been declared effective by the SEC.

Issuer Repurchases

We did not make any repurchases of our equity securities during the year ending December 31, 2018.

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, 2018, 2017, 2016, 2015 and 2014. 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.

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. 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, as well as acquire attractive acreage positions within its 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. 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:

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. We expect oil and natural gas to remain volatile. Additionally, 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.

Results of Operations

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

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.

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 $0 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 for 2017 to $3,445,721 for 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 (loss). 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 by 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.

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

Oil and natural gas sales. Oil and natural gas sales revenue increased approximately $35.8 million to $66.7 million in 2017. Oil sales increased approximately $35.6 million while natural gas sales increased approximately $0.2 million. The oil sales increase was the result of an increase in sales volume from 728,051 barrels of oil in 2016 to 1,311,727 barrels of oil in 2017 and an increase in the average realized per barrel oil price from $39.28 in 2016 to $48.97 in 2017. These per barrel amounts are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels. Natural gas sales volume decreased from 900,089 Mcf in 2016 to 761,517 Mcf in 2017 and the average realized per Mcf gas price increased from $2.50 in 2016 to $3.23 in 2017. These per Mcf amounts are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf. The oil volume increase is 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 $9,867,800 in 2016 to $15,978,362 in 2017 and decreased on a BOE basis from $11.24 in 2016 to $11.11 in 2017. These per BOE amounts are calculated by dividing our total production costs by our total volume sold, in BOE. The decrease in the cost per BOE is the result of increased production.

Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.88% during 2016 and decreased to 4.73% in 2017. 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.

Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased by $9,034,566 to $20,517,780 in 2017. 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 $13.08 per BOE during 2016 to $14.15 per BOE during 2017. 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 did not have any write-downs for the period ended December 31, 2017. The Company recorded a non-cash write-downs of the carrying value of its proved oil and natural gas properties of $56,513,016 for the period ended December 31, 2016 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, 2016, 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.

General and administrative expenses. General and administrative expenses increased from $8,027,077 in 2016 to $10,515,887 in 2017. The increase was primarily related to compensation and employee benefits.

Interest income. Interest income was $291,083 in 2017 as compared to $56,498 in 2016. The increase was the result of higher average cash on hand during 2017.

Interest expense. Interest expense decreased from $649,009 in 2016 to $0 in 2017. This decrease was the result of not having any debt outstanding during 2017.

Provision for income taxes. The provision for income taxes changed from a negative provision of $19,987,585 in 2016 to a positive provision of $10,416,171 for 2017. The change is due to the Company having a pre-tax net income in 2017 versus a net loss in 2016 and an adjustment to the value of our deferred tax asset as a result of a change in our future effective tax rate that is reflected in our current period expense.

Net income (loss). The Company had net income of $1,753,869 in 2017 as compared to a net loss of $37,637,687 in 2016. The primary reasons were increased revenues and not having a ceiling test write down in 2017, partially offset by the additional provision for income taxes recorded for the change in tax rate.

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 2018 were from funds generated from the sale of oil and natural gas production, proceeds from the issuance of common stock 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 (“Administrative Agent”), which was amended on June 14, 2018, May 18, 2016, June 26, 2015 and July 24, 2014 (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.

In June 2018, the borrowing base (the “Borrowing Base”) was increased from the initial $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 is 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 natural 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 of not more than 4.0 to 1.0 and (ii) a minimum current ratio 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, 2018, the Company was in compliance with all covenants contained in the Credit Facility, and $39.5 million was outstanding on the Credit Facility.

Cash Flows. Historically, our primary sources of cash have been from operations, equity offerings and borrowings on our Credit Facility. During 2018, 2017 and 2016, we had cash inflow from operations of $70,357,321, $42,806,224 and $11,214,397, respectively. During the three years ended December 31, 2018, we financed $280,416,073 through proceeds from the sale of stock. During 2018, 2017 and 2016, we had proceeds from drawdowns on our Credit Facility of $39,500,000, $0 and $7,000,000, respectively. We primarily used this cash to fund our capital expenditures and development aggregating $393,637,715 over the three years ended December 31, 2018 and repayment of debt on our Credit Facility of $52,900,000 in 2016. At December 31, 2018, we had cash on hand of $3,363,726 and negative working capital of $35,066,175, as compared to cash on hand of $15,006,581 and negative working capital of $19,319,525 at December 31, 2016 and cash on hand of $71,086,381 and working capital of $66,121,524 at December 31, 2016.

Schedule of Contractual Obligations. The following table summarizes our contractual obligations for periods subsequent to December 31, 2018. The future estimated office lease payments pertain to approximately 15,000 square feet of space for our corporate headquarters in Midland, Texas, approximately 3,700 square feet for our previous office space in Midland, Texas, approximately 3,700 square feet of office space for our accounting offices in Tulsa, Oklahoma and approximately 2,000 square feet of office space for our field office in Andrews, Texas. The Company incurred lease expenses of $527,060, $537,582 and $526,658 for the years ended December 31, 2018, 2017 and 2016, respectively. The following table reflects the outstanding balance under our Credit Facility and future minimum lease payments under the operating leases as of December 31, 2018.

(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.

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

Subsequent Events

On February 25, 2019, Ring Energy, Inc. (the “Company” or “Buyer”) entered into a Purchase and Sale Agreement (the “Purchase Agreement”) with Wishbone Energy Partners, LLC (“WEP”), Wishbone Texas Operating Company LLC (“WTOC”) and WB WaterWorks, LLC (“WBWW,” and together with WEP and WTOC, “Sellers”), to acquire Sellers’ North Central Basin Platform assets consisting of approximately 37,206 net acres located primarily in southwest Yoakum County, Texas and eastern Lea County, New Mexico (the “Assets”) for aggregate consideration of $300 million, comprised of $270 million cash and $30 million of common stock of the Company (the “Acquisition”), subject to customary adjustments, including adjustments based on title and environmental due diligence, under the Purchase Agreement. The Acquisition is expected to close early in the second quarter of 2019 and will have an effective date of November 1, 2018.

The Company intends to finance the Acquisition with borrowings under an Amended and Restated Senior Secured Revolving Credit Facility (“Amended and Restated Senior Credit Facility”) that amends and restates the Company’s existing Senior Secured Revolving Credit Facility (“Existing Senior Credit Facility”). Concurrent with the signing of the Purchase Agreement, the Company signed a commitment letter with SunTrust Bank and SunTrust Robinson Humphrey (the “Lead Arranger” and, together with SunTrust Bank, “SunTrust”) relating to the Amended and Restated Senior Credit Facility, pursuant to which SunTrust Bank has committed to increase the maximum facility amount to $1 billion, increase the borrowing base to $425 million, extend the maturity date and make other modifications to the terms of the Existing Senior Credit Facility (the “Commitment Letter”). The Commitment Letter provides that the financing would be funded at the closing of the Acquisition and secured by a first lien with substantially the same collateral requirements as the Existing Senior Credit Facility. Management expects the financing to have substantially the same covenants as the Existing Senior Credit Facility and a five-year term.

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, 2018 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.

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 2 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 and 2016, the Company recorded non-cash write-downs of the carrying value of the Company’s proved oil and natural gas properties as a result of ceiling test limitations of $14.2 million and $56.5 million, respectively, which are 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.

Our reserve estimates, as of December 31, 2018, are based on an average price of $58.74 for oil and $3.26 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:

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.

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, 2018, includes a deferred tax asset of approximately $7.8 million. We have not recorded a valuation against this asset as we believe

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 2018 ranged from a low of $40.55 per barrel to a high of $63.50 per barrel. Natural gas prices we received during 2018 ranged from a low of $2.04 per Mcf to a high of $6.13 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, 2018, all of our hedging arrangements have either expired or been terminated and the Company does not currently have any derivative contracts in place. See Note 6 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 $12.5 million at December 31, 2018). 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 2018, sales to two customers, Oxy and Plains represented 85% and 11%, respectively, of oil and natural gas revenues. At December 31, 2018, Oxy represented 90% of our accounts receivable and Plains represented 5%. 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.

As of December 31, 2018, we had $39.5 million outstanding on our Credit Facility with a weighted average interest rate of 4.17%. A 1% change in the interest rate on our Credit Facility would result in an estimated $459,000 change in our annual interest expense. See note 7 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.

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

None. 

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.

Based on management’s evaluation, our chief executive officer and chief financial officer concluded that, as of December 31, 2018, 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. There were no changes in our internal control over financial reporting that occurred during the fiscal year ended December 31, 2018 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.

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, 2018, our internal control over financial reporting is effective based on those criteria.

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.

None.

PART III

Executive Officers and Directors

The following table sets forth information regarding our executive officers, certain other officers and directors as of February 26, 2019. 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.

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. All of the Board members were re-elected at the Company’s 2018 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, 60, 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.

David A. Fowler – President and Director

Mr. Fowler, 60, 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, 57, 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, 41, 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, 72, 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.

Stanley M. McCabe – Director

Mr. McCabe, 86, 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, 66, 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, 78, 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.

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.

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 shall 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 Messrs. Woodrum, Petrelli and McCabe, 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 Messrs. Woodrum, Petrelli and McCabe 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. Rochford and McCabe, with Mr. Rochford 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. Rochford and McCabe, with Mr. Rochford 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.

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 shall 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.

Section 16(a) Beneficial Ownership Reporting Compliance

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.

Based solely upon a review of Section 16(a) reports furnished to us for our most recent fiscal year, we know of no director, officer or beneficial owner of more than ten percent of our common stock who failed to file on a timely basis reports of beneficial ownership of the our common stock as required by Section 16(a) of the Securities Exchange Act of 1934, as amended.

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).

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, 2018.

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 2018 was in the form of equity awards.

Our executive compensation program is designed to do the following:

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.

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.

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 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 2018 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:

The Compensation Committee reviewed the performance of our Named Executive Officers in conjunction with the Company’s performance objectives and goals for 2018. 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 2018 and tied the compensation (as discussed below) to the Company’s performance.

ROLE OF STOCKHOLDER SAY-ON-PAY ADVISORY VOTE

In determining 2018 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 utilizes 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 2018

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 2018, we continued to grow our production and reserves by focusing on operational efficiency. We successfully raised additional capital through underwritten public offerings and continued to focus on safety in our operations.

Our Compensation Committee assessed each of our executive officers’ performance and contribution to the Company meeting its objectives for 2018. 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.”

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, 2016, Mr. Broaddrick received a salary of $125,000. Effective January 1, 2017, the Compensation Committee recommended an increase of $20,000 for Mr. Broaddrick, increasing his base salary to $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.

For the year ended December 31, 2016, Mr. Hoffman received a salary of $175,000. Effective January 1, 2017, the Compensation Committee recommended an increase of $30,000 for Mr. Hoffman, increasing his base salary to $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.

For the year ended December 31, 2016, Mr. Fowler received a salary of $150,000. Effective January 1, 2017, the Compensation Committee recommended an increase of $25,000 for Mr. Fowler, increasing his base salary to $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.

For the year ended December 31, 2016, Mr. Wilson received a salary of $150,000. Effective January 1, 2017, the Compensation Committee recommended an increase of $25,000 for Mr. Wilson, increasing his base salary to $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.

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 2016, 2017 or 2018. The annual discretionary bonus is reported in the “Bonus” column of the “Summary Compensation Table” for each Named Executive Officer.

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 and Broaddrick were granted non-qualified stock options in 2016 and were granted restricted stock in 2017 and 2018.

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 to retain Named Executive Officers for longer terms.

Grants are determined for Named Executive Officers based on his performance in the prior year, his 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, 2018.

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.

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.

COMPENSATION OF NAMED EXECUTIVE OFFICERS FROM 2016 THROUGH 2018

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. 

Summary Compensation Table

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

(2) On December 9, 2015, Ring issued option awards to its Named Executive Officers and directors. On January 13, 2016, the Board ratified the Compensation Committee decision to rescind the option awards granted to its employees and directors (other than Messrs. McCabe and Rochford, who are the members of the Compensation Committee) as the result of a significant decline in the stock price and re-issued the option awards as of that date to meet the goals and objectives of the Company’s equity based compensation program. The amounts shown as Equity Awards include the additional fair value of the new options over the original grant. On December 26, 2018, the Compensation Committee rescinded the options granted in 2016. No adjustment has been made to the 2016 compensation shown to account for the reduction in compensation.

(3) Other Compensation for Messrs. Hoffman and Fowler consists of $24,000 in director’s fees.

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 2018.

Grants of Plan-Based Awards

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, 2018.

Outstanding Option Awards

The following table provides certain information regarding unvested restricted stock outstanding for each Named Executive Officer as of December 31, 2018. 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.

Outstanding Unvested Restricted Stock Awards

The following table provides information regarding options exercised by Named Executive Officers during 2018.

Option Exercises and Stock Vesting

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 and 2016. 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 and 2016:

 No options were granted during 2018.

For the years ended December 31, 2018, 2017 and 2016, the Company incurred stock based compensation expense related to stock options of $1,853,913, $3,618,309 and $2,267,053, respectively. As of December 31, 2018, there was $1,650,573 of unrecognized compensation cost related to stock options that will be recognized over a weighted average period of 1.9 years. The aggregate intrinsic value of options vested and expected to vest at December 31, 2018 was $1,993,800. The aggregate intrinsic value of options exercisable at December 31, 2018 was $1,993,800. The year-end intrinsic values are based on a December 31, 2018 closing price of $5.08.

Options exercised of 193,000 in 2018, 165,400 in 2017 and 25,900 in 2016 had an aggregate intrinsic value on the date of exercise of $1,470,230, $1,744,047 and $65,089, respectively.

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, 2018.

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