United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-K

(Mark One)

For the fiscal year ended December 31, 2014

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: None

Securities registered under Section 12(g) of the Exchange Act: Common Stock, Par Value $0.001

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post 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, or a smaller reporting company.  See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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, 2014, the aggregate market value of the common voting stock held by non-affiliates of the issuer, based upon the closing stock price of $17.45 per share, was approximately $360,171,071.

As of March 10, 2015, the issuer had outstanding 25,747,582 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,” refer to Ring Energy, Inc. and references to “the Company,” “we,” “us,” “our” or “ours” refer to Ring Energy, Inc.

PART I

General

Ring was incorporated in the State of Nevada in 2004 as “Blanca Corp.” The name of the corporation was changed to “Trandglobal Mining Corp.” in 2007 before being changed to “Ring Energy, Inc.” in 2008. We are a Midland-based exploration and production company that is engaged in oil and natural gas acquisition, exploration, development and production activities. Our exploration and production interests are currently focused in Texas and Kansas. The Company takes a conventional approach to its drilling program and seeks to develop its traditional core areas, as well as look for new growth opportunities.

The Company’s primary drilling operations target the Central Basin Platform in Andrews County and Gaines County, Texas. As of December 31, 2014, Ring had 29,738 gross (17,270 net) acres in those counties. The Company also has 18,277 gross (17,017 net) acres in Kansas. The acreage is located in Gray, Finney and Haskell counties. On October 16, 2013, Ring entered into a joint development agreement with Torchlight Energy Resources, Inc., to develop its Kansas leasehold. The Company will continue to operate the acreage and Torchlight Energy Resources, Inc., will earn an equal share in the leasehold after fulfilling the agreed upon drilling carry obligation of $6 million (the “Development Agreement”). All drilling activity has temporarily stopped while the Company completes an extensive 3-D seismic evaluation.

As of December 31, 2014, Ring’s proved reserves were 10.4 million BOE (barrel of oil equivalent). Effectively 100% of its reserves (based on the estimates above) relate to properties located in Texas. The Company’s proved reserves are oil-weighted with 98% of proved reserves consisting of oil and 2% consisting of natural gas. Of those reserves, 35% of the proved reserves are classified as proved developed producing, or “PDP,” 8% are classified as proved developed non-producing, or “PDNP,” and approximately 57% are classified as proved undeveloped, or “PUD.”

Production for the year ended December, 2014, was approximately 463,495 BOE, as compared to production of 115,681 BOE for the year ended December 2013, a 300% increase in BOE. The stated production amount reflects only the oil and gas that was produced and shipped prior to the end of the fourth quarter. Any oil and gas produced in the fourth quarter but still held on site after December 31, 2014, will be credited in the first quarter of 2015.

Ring believes that there is significant value to be created by drilling the identified undeveloped opportunities on its Texas properties. As of December 31, 2014, Ring owned interests in a total of 5,835 gross (5,129 net) developed acres and 23,903 gross (12,141 net) undeveloped acres in Texas. The Company has 239 identified proven vertical drilling locations based on the reserve report as of December 31, 2014, and an additional 2,480 identified potential vertical drilling locations based on 10-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 has identified 24 wells that are suitable candidates for re-stimulation, providing attractive returns with lower upfront costs. Ring has temporarily stopped drilling activity in Kansas pending the completion of an extensive 3-D evaluation.

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

Ring Energy’s Business Strategy and Development

Ring Energy’s Strengths

Competitive Business Conditions

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

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 gas prices comparable to other producers. 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 This commitment 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). We are not subject to third party gathering systems for our oil production. Some of our oil production is sold through a third party pipeline which has no regional competition. 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. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For the fiscal year 2014, sales to two customers, HollyFrontier Refining and Marketing (“HollyFrontier”) and Plains Marketing LP (“Plains”) represented 75% and 18%, respectively, of oil and gas revenues. At December 31, 2014, HollyFrontier represented 45% of our accounts receivable and Plains represented 37%. However, we believe that the loss of these customers would not materially impact our business, because we could readily find other purchasers for our oil and gas produced.

Delivery Commitments

As of December 31, 2014, 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, affects 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. All of the states in which we own and operate properties have 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, each state generally 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. Nevertheless, 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 and Kansas, 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 and Kansas specific oil and 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 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 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 incur legal defense costs and 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.

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, 2014, we had twenty-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.

Financial Information

Financial information regarding the geographic area in which we operate is incorporated herein by reference to Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8, “Financial Statements and Supplementary Data.” We conduct our oil and natural gas activities entirely in the United States.

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 57%) or proved developed non-producing (approximately 8%), 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:

If our assessments of recently purchased properties are materially inaccurate, it could have 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 (57%) 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 from 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 a $40 million borrowing base borrowings and letters of credit. As of December 31, 2014, no amount was outstanding on our credit facility. If in the future we 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.

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 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 gas industry.

We operate in a highly competitive environment for acquiring properties and marketing oil and natural gas. Our competitors include multinational oil and gas companies, major oil and gas companies, independent oil and 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 gas reserves or in our marketing of production, then our financial condition and operation results may be adversely affected.

Risks Relating to Our Common Stock

We have no plans to pay dividends on our common stock. Shareholders 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 shareholder 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 currently in Texas and Kansas. Our focus will be on developing our existing properties, while continuing to pursue acquisitions of oil and gas properties with upside potential.

Management’s Business Strategy Related to Properties

Our goal is to increase shareholder value by investing in oil and 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 acquisitions of additional properties. Specifically, we have focused, and plan to continue to focus, on the following:

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, 2014, we owned interests in a total of 5,835 gross (5,129 net) developed acres and operate essentially all of the net pre-tax PV10 value of our proved undeveloped reserves. In addition, as of December 31, 2014, we owned interests in approximately 23,903 gross undeveloped acres (12,141 net). While our focus will be toward growth through additional acquisitions and leasing, we plan on 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 County leases – Andrews County, Texas. In 2011, we acquired a 100% working interest and a 75% net revenue interest in the initial leases. 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 leases. The working interests range from 2-100% and the net revenue interests range from 2-80%. In total, we now own 29,738 gross acres, with 5,835 acres developed and held by production and the remaining 23,903 acres being undeveloped. We believe the Andrews County leases contain a considerable number of remaining potential drilling locations. Our reserve estimate includes 239 PUD wells. Our reserve estimates include the capital costs required to develop these wells.

Significant Kansas Operations

Kansas Properties – Gray, Finney Haskell Counties, Kansas. We acquired a 100% working interest and an 80% net revenue interest in 9,541.5 net mineral acres and a 95% working interest and a 76% net revenue interest in 1,600 net mineral acres, along with all production. We acquired a 100% working interest and an 80% net revenue interest in 4,698 net mineral acres in addition to our existing acreage acquired in 2012. We have subsequently leased additional acreage in Kansas, bringing our total acreage position to 18,277 gross acres. There was no production associated with the acquisition. In October 2013, we entered into the Joint Development Agreement, whereby Torchlight Energy Resources, Inc. agreed to pay approximately $6.2 million in development costs in return for a 50% working interest in this acreage. There are 17 total wells on the acreage, of which five (5) are currently producing. However, we believe this acreage has significant potential.

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 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, 2014, our estimated proved reserves had a pre-tax PV10 value of approximately $281.7 million and a Standardized Measure of Discounted Future Cash Flows of approximately $196.3 million, essentially 100% of which relate to our properties in Texas. We spent approximately $143.0 million on acquisitions and capital projects during 2013 and 2014. We expect to further develop these properties through additional drilling. We will closely manage our capital expenditures to our cash flow. As commodity prices change we will consider the resulting impact on our cash flow and adjust our capital expenditures up or down accordingly. We have maintained a strong current cash position with no long-term debt; we will continue to seek acquisition opportunities that complement our core assets.

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, 2014.

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.

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

Our 10,407,009 BOE of proved reserves, which consist of approximately 98% oil and 2% natural gas, are summarized below as of December 31, 2014, 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, 2014, our Texas proved reserves had a net pre-tax PV10 value of $280.8 million and Standardized Measure of Discounted Future Net Cash Flows of $195.5 million and our proved reserves in Kansas had a net pre-tax PV10 value of $0.9 million and Standardized Measure of Discounted Future Net Cash Flows of $0.9 million.

As of December 31, 2014, approximately 35% of the proved reserves have been classified as proved developed producing, or “PDP”. Proved developed non-producing, or “PDNP” reserves constitute approximately 8% and proved undeveloped, or “PUD”, reserves constitute approximately 57%, of the proved reserves as of December 31, 2014.

Total proved reserves had a net pre-tax PV10 value as of December 31, 2014 of approximately $281.7 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $196.3 million. Approximately $115.5 million and $80.6 million, respectively, of total proved reserves are associated with the PDP reserves, which is approximately 41.1% of total proved reserves’ pre-tax PV10 value. An additional $33.1 million and $23.0 million, respectively, are associated with the PDNP reserves, which is approximately 11.7% of total proved reserves’ pre-tax PV10 value. The remaining $133.1 million and $92.7 million, respectively, are associated with PUD reserves.

Proved Undeveloped Reserves

Our reserve estimates as of December 31, 2014 include 5.9 million BOE as proved undeveloped reserves. As of December 31, 2013, our reserve estimates included 5.2 million BOE as proved undeveloped reserves. Following is a description of the changes in our PUD reserves from December 31, 2013 to December 31, 2014.

Conversion of approximately 964,720 BOE of reserves from PUD to PDP or PDNP through development.

Net downward revision of approximately 511,503 BOE primarily as a result of performance.

Purchase of minerals in place through leasing of new acreage and acquisitions resulted in the addition of approximately 2,172,974 BOE.

Our proved reserves as of December 31, 2014 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

Our reserves data and estimates were compiled, prepared and audited by third party independent consultants, Cawley, Gillespie & Associates, Inc., as described in more detail herein, in compliance with SEC definitions and guidance and in accordance with generally accepted petroleum engineering principles. The technical persons employed by Cawley, Gillespie & Associates, Inc., met the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our reserves estimates are prepared by examination and evaluation of production data, production decline curves, reservoir pressure data, logs, geological data, and offset analogies. The third party independent consultants are provided 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 its Vice President of Operations, Daniel D. Wilson, a petroleum engineer, and 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 30 years of experience in operating, evaluating and exploiting oil and gas properties. Mr. Kelly Hoffman has 39 years of well-rounded experience in the oil and 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. 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 2014, is summarized below. The following table indicates the percentage of our estimated December 2014 average daily production of 1,935 BOE/d attributable to each state and to oil versus natural gas production.

Acreage

The following table summarizes gross and net developed and undeveloped acreage at December 31, 2013 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.

Production History

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

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 gas sales price amounts above are calculated by dividing revenue from gas sales by the volume of 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, 2014, in productive oil and natural gas wells by region (a net well is our percentage ownership of a gross well).

Drilling Activity

During 2014, we drilled one hundred thirty five (135) development wells in Texas with one hundred twenty five (125) wells being completed and producing at December 31, 2014. All wells drilled in Texas during 2014 were successful. Also during 2014, we drilled seven (7) wells in Kansas. Six (6) of these wells were successful and one (1) was a dry hole. During 2013, we drilled forty (40) development wells in Texas with thirty eight (38) wells being completed and producing at December 31, 2013. All of the wells drilled in 2013 were successful. During 2012, we drilled five (5) development wells in Texas and all five (5) were completed and in production at December 31, 2012.

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 $36.37, $10.44 and $10.77 during the years ended December 31, 2012, 2013 and 2014, respectively, and our average production taxes, per BOE, were $3.84, $4.12 and $3.80 for the years ended Decemeber 31, 2012, 2013 and 2014, 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, 2012, 2013 and 2014 are shown below.

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 still have a lease for our previous office space in Midland, Texas, consisting of approximately 3,700 square feet. We vacated this space as of February 28, 2015 and have begun efforts to sublet this space. Additionally, we lease office space in Tulsa, Oklahoma which serves as our primary accounting office. The leased office space consists of approximately 3,700 square feet. We also lease office space in Andrews, Texas which is currently our only field office. The leased office space consists 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

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

Market for our Common Stock

Our common stock is listed on the NYSE MKT under the trading symbol “REI.” Prior to September 1, 2013, our Common stock was quoted on the OTCQB and the OTC Bulletin Board under the trading symbol “RNGE”. We have only one class of common stock, and we have 50,000,000 authorized but unissued shares of preferred stock. The table below sets forth for the periods indicated the quarterly high and low bid prices of our common stock, based on information provided to us by OTC Markets, and the high and low sale prices of our common stock as reported on the NYSE MKT. All over-the-counter quotations reflect inter-dealer prices, without retail mark-up, mark-down, or commission and may not necessarily represent actual transactions. At the time of the over-the-counter quotations below, we were not listed on an established trading market and the transactions in our common stock were limited and the bid prices provided below may not be indicative of prices if our common stock was trading in an established public trading market.

The following graph compares the cumulative 5-year total return attained by stockholders on Ring Energy, Inc.’s common stock relative to the cumulative total retruns 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, 2009, and reinvestment of dividends on the date of payment without commission. This table is not intended to forecast future performance of our common stock.

* The peer group consists of Callon Petroleum Company, Rex Energy Corporation, Approach Resources, Inc., Resolute Energy Corporation and Clayton William Energy, Inc., all of which are in the oil and gas production industry.

Record Holders

As of March 10, 2015, there are approximately 3,431 holders of record of our common stock. As of March 10, 2015, 5,055,338 shares, or approximately 19.6%, of the 25,747,582 shares issued and outstanding as of such date are held by management or affiliated parties.

Dividend Policy

We have not paid any dividends on our common stock during the last three years, and 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, 2014.

Description of Our 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 of Directors 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 shareholders on January 22, 2013. The following is a summary of the material terms of the Plan.

Shares Available

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

Administration

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

Eligibility

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

Stock Options

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

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

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

Restricted Stock

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

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

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

Fair Market Value

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

Transferability Restrictions

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

Termination and Amendments to the Plan

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

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

Recent Sales of Unregistered Securities

On June 18, 2014, we completed our offering of 2,000,001 shares of common stock at $15.00 in the Private Placement. The shares were sold without registration under the Securities Act by reason of the exemption from the registration afforded by the provisions of Section 4(a)(2) and/or Section 4(a)(5) of the Securities Act of 1933, as amended, and Rule 506 promulgated thereunder for sales of unregistered securities. Commissions in the amount of $1,227,000 were paid to the placement agents. The Company has filed a registration statement with the SEC with respect to the Resale Shares.

On July 25, 2014, September 26, 2014 and December 9, 2014, we issued 5,000, 8,873 and 5,823, respectively, shares of common stock to a total of seven individuals or entities as consideration in asset acquistiions. The issuances of common stock described above were (i) made in reliance of the exemption from the registration requirements of the Securities Act of 1933, as amended, provided by Section 4(a)(2) thereof and (ii) conducted without general solicitation or general advertising. All seven entities were accredited investors at the time of the issuance.

Use of Proceeds from Registered Securities

On December 11, 2013, the Company closed an underwritten public offering of 5,000,000 shares of its common stock, as well as the exercise of the full over-allotment option by the underwriters of an additional 750,000 shares of its common stock, pursuant to a prospectus filed as part of an effective registration statement on Form S-1, as amended (effective as of December 5, 2013). The shares were sold at the public offering price of $10.00 per share. SunTrust Robinson Humphrey, Inc. acted as sole book-running manager, and Capital One Securities, Inc., Global Hunter Securities, LLC, Euro Pacific Capital Inc., IBERIA Capital Partners L.L.C., Noble Financial Capital Markets, Northland Capital Markets, and Roth Capital Partners, LLC, were co-managers for the offering.

The gross proceeds from the Offering were $57.5 million, and the Company net proceeds from the offering were $54.2 million, after deducting underwriting commissions and offering expenses payable by the Company of $3.3 million. The $3.3 million in offering costs included $2.9 million in underwriting discounts with the remaind being various legal, accounting, travel and other costs. No amounts were paid, directly or indirectly, to any director, officer or 10% owner. Of the net proceeds $3.5 million was used to pay down the outstanding amount on our credit facility and the remainder of the proceeds were used to fund our development.

Issuer Repurchases

We did not make any repurchases of our equity securities during the year ending December 31, 2014.

Item 6:       Selected Financial Data

The selected consolidated financial information set forth below is derived from our consolidated balance sheets and statements of operations as of and for the years ended December 31, 2014, 2013, 2012 and 2011. 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 consolidated financial statements and related notes thereto included in this Annual Report.

Reorganization into Ring – On June 28, 2012, Ring completed the acquisition of Stanford Energy, Inc. (“Stanford”) through the closing of a stock-for-stock exchange agreement dated May 3, 2012.  As a result, Stanford’s stockholders obtained control of Ring under current accounting guidance. Since the Stanford stockholders obtained a controlling interest in Ring’s Common Stock and stock options, Stanford was determined to be the accounting acquirer and its historical financial statements have been adjusted to reflect its reorganization in a manner equivalent to a 2,500-for-1 stock split. The accompanying historical financial statements prior to the reorganization into Ring are Stanford’s financial statements, adjusted to reflect the authorized capital and par value of Ring and to reflect the effects of the stock split for all periods presented.

Predecessor Carve-Out Financial Statements – On May 23, 2011, prior to Ring’s acquisition of Stanford, Stanford acquired developed and undeveloped properties referred to as the “Fisher I Property.” The Fisher I Property represents Stanford’s predecessor under Rule 405 of Regulation C of the Securities Act of 1933, as amended, as the Fisher I Property was Stanford’s first interest in producing oil and natural gas properties and Stanford’s own operations before the acquisition were insignificant relative to the operations acquired. In that regard, upon consummation of the acquisition, the historical financial statements of the Fisher I Property became the historical financial statements of the Company. The accompanying predecessor financial statements present the full carve-out revenues earned, the costs and expenses incurred and the cash flows of the predecessor owners relative to the Fisher I Property.

Subsequent to the acquisition of the Fisher I Property, the successor financial statements present the financial position, operations and cash flows of the assets acquired, the liabilities assumed and operations of the Fisher I Property as well as those of other properties acquired subsequently and are reflected at their purchase-date fair values. Those fair values are reflected as the cost of the assets acquired and the carrying amounts of the liabilities assumed, and are the basis of the resulting operations of the successor.

Prior to the acquisition of the Fisher I Property, Stanford had little activity and was a development stage company. Its planned operations were to acquire, develop and operate oil and natural gas properties. Stanford had no revenue, expenses or income during the four months ended April 30, 2011.

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

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

Overview

Ring is a Midland-based exploration and production company that is engaged in oil and natural gas acquisition, exploration, development and production activities. Our exploration and production interests are currently focused in Texas and Kansas. We take a conventional approach to our drilling program and seek to develop our traditional core areas, as well as look for new growth opportunities.

Our goal is to increase stockholder value by investing in oil and 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 acquisitions of additional properties.

Business Description and Plan of Operation

Ring is currently engaged in oil and natural gas acquisition, exploration, development and production, with activities currently in Texas and Kansas. 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 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 acquisitions of additional properties. Specifically, our business strategy is to increase our stockholders value through the following:

Results of Operations

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

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Oil and natural gas sales. Oil and natural gas sales revenue increased approximately $27.8 million to $38.1 million in 2014. Oil sales increased approximately $27.8 million while natural gas sales remained effectively the same. The oil sales increase was the result of an increase in sales volume from 109,673 barrels of oil in 2013 to 457,039 barrels of oil in 2014 offset by a decrease of 10% in the average realized per barrel oil price from $92.81 in 2013 to $83.04 in 2014. 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 36,047 Mcf in 2013 to 38,735 Mcf in 2014 but was offset by an 8% decrease in the average realized per Mcf gas price from $3.82 in 2013 to $3.53 in 2014. These per Mcf amounts are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf. The volume increases for both oil and natural gas are the result of both the acquisitions we made during the year and the result of our development of existing properties.

Oil and gas production costs. Our aggregate oil and gas production costs increased from $1,207,500 in 2013 to $4,993,166 in 2014, and increased on a BOE basis from $10.44 in 2013 to $10.77 in 2014. These per BOE amounts are calculated by dividing our total production costs by our total volume sold, in BOE. This increase in the aggregate production costs is the result of additional acquisitions and development.

Oil and gas production taxes. Oil and gas production taxes as a percentage of oil and natural gas sales were 4.62% during 2013 and remained the same in 2014. 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 $9,523,703 to $11,807,794 in 2014. The increase was a result of increased production volumes and an increase in the average depreciation, depletion and amortization rate from $19.74 per BOE during 2013 to $25.48 per BOE during 2014. These per BOE amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total volume sold, in BOE.

General and administrative expenses. General and administrative expenses remained relatively flat, increasing by $120,269 to $6,803,029 during 2014.

Interest income. Interest income was $85,964 in 2014 as compared to $24,706 in 2013. The increase was the result of higher cash on hand during 2014.

Interest expense. Interest expense decreased by $9,890 in 2013 to no expense in 2014. The decrease was the results of having no amounts amounts borrowed on our credit facility during 2014.

Provision for income taxes. The provision for income taxes increased from $77,701 in 2013 to $4,235,739 in 2014. The increase is due to higher net income before taxes in 2014. The effective tax rate in 2014 was 33.5%, which is less than the Company’s federal statutory rate due to the favorable tax impact of stock option exercises, partially offset by adjustments of the prior year’s tax estimate made in 2014.

Net income (loss). During 2014, the Company had net income of $8,420,500 as compared to a net loss of $452,209 during 2013. The primary reason for this change was increased revenues partially offset by an increase in costs of production, depreciation, depletion and amortization and provision for income taxes.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Oil and natural gas sales. Oil and natural gas sales revenue increased approximately $8.6 million to $10.3 million in 2013. Oil sales increased approximately $8.5 million while natural gas sales increased by $0.1 million. The oil sales increase was the result of an increase in sales volume from 20,531 barrels of oil in 2012 to 109,673 barrels of oil in 2013 and an increase of 10% in the average realized per barrel oil price from $84.50 in 2012 to $92.81 in 2013. These per barrel amounts are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels. The natural gas sales increase was the result of an increase in sales volume from 6,480 Mcf in 2012 to 36,047 Mcf in 2013 and a 9% increase in the average realized per Mcf gas price from $3.50 in 2012 to $3.82 in 2013. These per Mcf amounts are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf. The volume increases for both oil and natural gas are the result of both the acquisitions we made during the year and the result of our development of existing properties.

Oil and gas production costs. Our aggregate oil and gas production costs increased from $785,959 in 2012 to $1,207,529 in 2013, and decreased on a BOE basis from $36.37 in 2012 to $10.44 in 2013. These per BOE amounts are calculated by dividing our total production costs by our total volume sold, in BOE. This increase in the aggregate production costs is the result of additional acquisitions and development while the decrease on a per BOE basis was the result of increasing production and the results of work done previously to get wells into proper working order.

Oil and gas production taxes. Oil and gas production taxes as a percentage of oil and natural gas sales were 4.72% during 2012 and decreased slightly to 4.62% in 2013. 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 $1,777,305 to $2,284,091 in 2013. The increase was a result of increased production volumes partially offset by a decrease in the average depreciation, depletion and amortization rate from $23.45 per BOE during 2012 to $19.74 per BOE during 2013. These per BOE amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total volume sold, in BOE. The decreased depreciation, depletion and amortization rate was the result of development throughout the year and adding additional reserves.

General and administrative expenses. General and administrative expenses increased by $4,290,115 to $6,682,760 during 2013. This increase was primarily related to an increase in stock based compensation expense of $2,544,341 and an increase in salaries and wages of $1,228,778, partially offset by a decrease in contract labor of $526,125.

Interest income. Interest income was $24,706 in 2013 as compared to $4,309 in 2012. The increase was the result of higher cash on hand during 2013.

Interest expense. Interest expense decreased by $208,915 to $9,890 in 2013. The decrease was the result of having smaller amounts borrowed on our credit facility for a portion of 2013.

Provision for income taxes. The provision for income taxes increased from $(300,024) in 2012 to $77,701 in 2013. The increase was primarily the result of a reduced loss before taxes in 2013 as compared to 2012. The combined federal and state effective tax rate differed from the Company’s federal statutory rate primarily due to state income taxes, non-deductible expenses, and adjustments of the prior year’s tax estimate made in the current year.

Net loss. Net loss decreased from $1,669,283 in 2012 to net loss of $452,209 during 2013. The primary reason for this change was increased revenues partially offset by an increase in general and administrative expenses and depreciation, depletion and amortization.

Liquidity and Capital Resources

Historical Financing. We have historically funded our operations through cash available from operations and from equity offerings of our stock.

Credit Facility. Throughout 2012, 2013 and 2014, the Company extended a credit agreement with a bank that provided for a revolving line of credit of up to $10 million for borrowings and letters of credit. The credit agreement included a non-usage commitment fee of 0.20% per annum and covenants limiting other indebtedness, liens, transfers or sales of assets, distributions or dividends and merger or consolidation activity. The facility had an interest rate of the bank’s prime rate plus 0.75% with the total interest rate to be charged being no less than 4.00%. The maturity date on the note was extended to October 30, 2015. This credit facility was terminated in July 2014 in connection with the Company entering into a new Credit Agreement.

In July 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”) (the “Credit Facility”).  The Credit Facility provides for a senior secured revolving credit facility with a maximum borrowing amount of $150 million. The Credit Facility matures on July 1, 2019, and is secured by substantially all of the Company’s assets.

The initial borrowing base under the Credit Facility is $40 million (the “Borrowing Base”).  The Borrowing Base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time.  The Borrowing Base will be redetermined (i) quarterly on each January 1, April 1, July 1 and October 1, beginning October 1, 2014 through October 1, 2015, and (ii) semi-annually on each October 1 and April 1 beginning on April 1, 2016.  In addition, the Company may elect to cause the Borrowing Base to be redetermined one time during each of the following periods (i) between the October 1, 2014 and April 1, 2015 redeterminations, (ii) between the April 1, 2015 and October 1, 2015 redeterminations and (iii) starting with the October 1, 2015 redetermination, during any six month period between redeterminations.  The Borrowing Base will also be reduced in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and cancellation of certain hedging positions.

The Credit Facility allows for Eurodollar Loans and Base Rate Loans (each as defined in the Credit Facility).  The interest rate on each Eurodollar Loan will be the adjusted LIBOR for the applicable interest period plus a margin between 1.75% and 5.00% (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 6.00% (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, 2014, no amounts are outstanding on our credit facility.

Cash Flows. Historically, our primary sources of cash have been from operationgs and equity offerings. During 2014 and 2013, we had cash inflow of $33,748,065 and $8,116,408, respectively, from operations. During the three years ended December 31, 2014, we financed $114,725,438 through proceeds from the sale of stock and $1,150,000 through borrowings. We primarily used this cash to fund our capital expenditures and development aggregating $149,728,290 over the three years ended December 31, 2014 and reducing debt of $9,244,428. At December 31, 2014, we had cash on hand of $8,622,235 with negative working capital of $1,179,753, as compared to cash on hand of $52,350,583 and working capital of $49,073,394 at December 31, 2013 and cash of $5,404,167 and working capital of $4,691,099 at December 31, 2012.

Schedule of Contractual Obligations. The following table summarizes our future estimated lease payments for periods subsequent to December 31, 2014. The leases 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, as we attempt to sublet the space, 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 $149,872, $141,593 and $208,091 for the years ended December 31, 2014, 2013 and 2012, respectively. The following table reflects the future minimum lease payments under the operating leases as of December 31, 2014.

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

Off-Balance Sheet Financing Arrangements

As of December 31, 2014 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. We predominantly derive our revenue from the sale of produced crude oil and natural gas. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received; however, differences have been insignificant.

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 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.

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 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.

Impairment of Oil and Natural Gas Properties. We review the value of our oil and natural gas properties whenever management judges that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. We provide for impairments on undeveloped property when we determine that the property will not be developed or a permanent impairment in value has occurred. Impairments of proved producing properties are calculated by comparing future net undiscounted cash flows using escalated prices to the net recorded book cost at the end of each period (“Ceiling test”). If the net capitalized cost exceeds net future cash flows, the cost of the property is written down to “fair value,” which is determined using net discounted future cash flows from the producing property. Current market conditions, in the form of low commodity prices, have had a dramatic effect on this calculation. The net discounted future cash flow from producing properties is directly impacted by commodity prices. Different pricing assumptions or discount rates could result in a different calculated impairment. We have never recorded property impairments as a result of the ceiling test.

Our reserve estimates as of December 31, 2014 are based on an average price of $85.097 for oil and $3.947 for gas. We have run an impairment test analysis to determine at approximately what price level impairment would result. Because our reserves are predominantly oil, at approximately 98% of total reserves, this analysis was based solely on the oil price while leaving gas prices at the levels used for preparing the reserve estimates as of December 31, 2014. Based on this analysis, our contracted oil price would have to drop below $69.99 per barrel for the Ceiling test to result in impairment to our producing properties.

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 actual in the period we file our tax returns.

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.

Item 7A     Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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

The prices we receive depend on many factors outside of our control. Oil prices we received during 2014 ranged from a low of $54.60 per barrel to a high of $96.72 per barrel. Natural gas prices we received during 2014 ranged from a low of $1.96 per Mcf to a high of $7.09 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.

Customer Credit Risk

Our principal exposures to credit risk is through receivables from the sale of our oil and natural gas production (approximately $3.6 million at December 31, 2014). 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 2014, sales to two customers, HollyFrontier and Plains Marketing, represented 74% and 18%, respectively, of oil and gas revenues. At December 31, 2014, HollyFrontier and Plains Marketing represented 45% and 37%, respectively, of our accounts receivable.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facility. Our current credit facility has a floating interest rate. Therefore, if we draw funds on this credit facility, interest rate changes will impact future results of operations and cash flows. As of December 31, 2014, the weighted average interest rate on our borrowings would be 2%.

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

Item 8:       Financial Statements and Supplementary Data

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

On September 1, 2013, Hansen, Barnett & Maxwell, P.C. (“HBM”) resigned as the Company’s independent registered public accounting firm. HBM recently entered into an agreement with Eide Bailly LLP (“Eide Bailly”), pursuant to which Eide Bailly acquired the operations of HBM as of September 1, 2013. In connection with such acquisition, certain of the professional staff and stockholders of HBM joined Eide Bailly either as employees or partners of Eide Bailly and will continue to practice as members of Eide Bailly. Concurrent with the resignation of HBM, the Company, through and with the approval of its Audit Committee, engaged Eide Bailly as its independent registered public accounting firm.

The reports of HBM on the Company’s financial statements for the fiscal years ended December 31, 2012 did not contain an adverse opinion or a disclaimer of opinion, and was not qualified or modified as to uncertainty, audit scope, or accounting principles.

Prior to engaging Eide Bailly, the Company did not consult with Eide Bailly regarding the application of accounting principles to a specific completed or contemplated transaction or regarding the type of audit opinions that might be rendered by Eide Bailly on the Company’s financial statements, and Eide Bailly did not provide any written or oral advice that was an important factor considered by the Company in reaching a decision as to any such accounting, auditing or financial reporting issue.

In connection with the audit for the past fiscal year and through September 1, 2013, there were no disagreements with HBM on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of HBM, would have caused HBM to make reference to the subject matter of the disagreements in connection with its audit reports on the Company’s financial statements.

In accordance with Item 304(a)(3) of Regulation S-K, the Company provided to Hansen, Barnett & Maxwell, P.C. a copy of the foregoing disclosure and Hansen, Barnett & Maxwell, P.C. furnished the Company with a letter addressed to the SEC stating Hansen, Barnett & Maxwell, P.C.’s agreement with such disclosure. A copy of such letter, dated September 1, 2013, is attached as Exhibit 99.1 to the Company’s Current Report on Form 8-K filed with the SEC on September 5, 2013.

Item 9A: CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures.

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

Based on management’s evaluation, our chief executive officer and chief financial officer concluded that, as of December 31, 2014, 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 quarter ended December 31, 2014 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 (1992).  Based on our assessment, we believe that, as of December 31, 2014, 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 March 10, 2015. The 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 that led the Board to nominate them.

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 2014 annual shareholders’ meeting. There are no family relationships between any director or executive officer or person nominated or chosen to become andirector 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, 56, 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 he again 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 currently serves as a director of Joes Jeans Inc. (NASDAQ: JOEZ), a reporting company.

David A. Fowler – President and Director

Mr. Fowler, 56, 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 Range IPF in April of 2001, he 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.

Daniel D. Wilson – Executive Vice President

Mr. Wilson, 53, has 30 years of experience in operating, evaluating and exploiting oil and gas properties. He has experience in production, drilling and reservoir engineering. For the last 22 years he has served as the Vice President and Manager of Operations for Breck Operating Corporation (“Breck”). He has overseen 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 including engineers, foremen, pumpers and clerks. Mr. Wilson personally performed or oversaw all of the economic evaluations for both acquisition and banking purposes.

William R. Broaddrick – Chief Financial Officer.

Mr. Broaddrick, 37, was employed from 1997 to 2000 with Amoco Production Company, performing lease revenue accounting and state production tax regulatory reporting functions. 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 Resources, Inc. as Vice President and Chief Financial Officer. During 2011, Mr. Broaddrick joined Stanford as Chief Financial Officer. Subsequent to and as a result of the merger transaction between Stanford and Ring Mr. Broaddrick became Chief Financial Officer of Ring Energy as of July 2012.

Mr. Broaddrick received a Bachelor’s Degree in Accounting from Langston University, through Oklahoma State University – Tulsa, in 1999. Mr. Broaddrick is a Certified Public Accountant.

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

Mr. Rochford, 68, has been active as an individual consultant and entrepreneur in the oil and gas industry since 1973. During that time, 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 of 2008, Mr. Rochford served as President, Chief Executive Officer (“CEO”) 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 CEO at Arena and accepted the position of Chairman of the Board. In his role as Chairman, he 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.

Stanley M. McCabe – Director

Mr. McCabe, 82, 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 CEO 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 with Mr. Rochford, Magnum Petroleum, Inc., serving as an officer and director. In 2000, Mr. McCabe co-founded with Mr. Rochford, Arena , serving as Chairman of the Board until 2008 and then as a director of Arena until 2010.

Anthony B. Petrelli – Director

Mr. Petrelli, 62, is President, member of the Board of Directors, and Director of Investment Banking of Neidiger, Tucker, Bruner, Inc., a Denver, Colorado based financial services firm founded in 1977. Beginning his career in 1972, Mr. Petrelli has had 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. Mr. Petrelli received his BS 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.

Clayton E. Woodrum – Director

Mr. Woodrum, CPA, 74, 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, sale and liquidation of businesses, debt restructuring, debt discharge and CFO functions for private and public 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.

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 MKT, LLC definition of independent director set forth in the Company Guide, Part 8, Section 803(A). (see the biographical information for Messrs. Woodrum and Petrelli, infra, in this discussion of “Directors and Executive Officers”).

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 MKT, LLC, 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 (a) identify and recommend qualified candidates to the Board of Directors for nomination as members of the Board and its committees, and (b) 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.

Our Board may establish other committees from time to time to facilitate our management.

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. We have also adopted a Code of Conduct that applies to our officers, directors, and employees. 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 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

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

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. These individuals are collectively referred to herein as the (“Named 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.

Our current executive compensation programs are determined and approved by our Compensation Committee, after consideration of recommendations by our Chairman of the Board and our Chief Executive Officer, as to the other Named Executive Officers. 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 of Directors who qualify as “independent” directors under applicable guidelines adopted by the NYSE MKT, LLC) the compensation levels of the Named Executive Officers.

Our current executive compensation programs are intended to achieve two objectives. The primary objective is to enhance the profitability of the Company, and thus, shareholder 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. As described in more detail below, the material elements of our current executive compensation program for Named Executive Officers includes a base salary, discretionary annual bonuses and discretionary stock options grants.

The Company believes that each element of the executive compensation program helps to achieve one or both of the compensation objectives outlined above. 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. 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 being linked to performance by rewarding and/or motivating executives. Base salaries are reviewed annually and take into account: 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 shareholder 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 Compensation Committee does not currently benchmark executive compensation to any other companies. 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 to align shareholder and executives’ interests and should allocate a portion of long-term compensation to the entire executive compensation package.

The Company has never retained an outside consultant in establishing its compensation program or in establishing any specific compensation for an executive officer.

Current Executive Compensation Program Elements

Base Salaries

Similar to most companies within the industry, our policy is to pay Named Executive Officers’ base salaries in cash. Effective July 1, 2012, the Compensation Committee designated a salary of $100,000 for Mr. Broaddrick. Effective September 1, 2012 the Compensation Committee recommended an increase of $25,000 for Mr. Broaddrick. Mr. Hoffman joined the Company effective January 1, 2013 and the Compensation Committee designated a salary of $175,000. Mr. Fowler joined the Company effective January 1, 2013 and the Compensation Committee designated a salary of $150,000. Mr. Wilson joined the Company effective January 1, 2013 and the Compensation Committee designated a salary of $150,000.

Annual Bonuses

The Company has not had a formal policy regarding bonuses, and payment of bonuses has been purely discretionary and is largely based on the recommendations of the Compensation Committee. Cash bonuses are not expected to be a significant portion of the executive compensation package. Cash bonuses were granted to all employees in December 2013. The annual discretionary bonus is reported in the “Bonus” column of the “Summary Compensation Table” for each Named Executive Officer.

Equity-Based Compensation – Options and Restricted Stock Grants

It is our policy that the Named Executive Officers’ long-term compensation should be directly linked to enhancing profitability and value provided to shareholders of the Company’s common stock. Accordingly, the Compensation Committee grants equity awards under the Company’s long term incentive plan designed to link an increase in shareholder value to compensation. Mr. Broaddrick was granted non-qualified stock options in 2012, 2013 and 2014. Messrs. Hoffman, Fowler and Wilson were granted non-qualified stock options in 2013 and 2014. 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 requisite service period served. Non-qualified stock options for Named Executive Officers and other key employees generally vest ratably over five years. No restricted stock was granted to any of the Named Executive Officers.’ The Compensation Committee believes that these awards encourage 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 or her performance in the prior year, his or her 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 hire date. Other grant date determinations are made by the Compensation Committee, which are based upon the date the 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.

Compensation of Named Executive Officers

The “Summary Compensation Table” set forth below should be read in connection with the tables and narrative descriptions that follow. 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.

The Company does 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, 2014.

Summary Compensation Table

(1) Salary information for William R. Broaddrick during 2012 includes compensation received from Stanford Energy, Inc. prior to the merger between Stanford and Ring Energy, Inc. and compensation received from Ring subsequent to the merger.

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

(3) 2014 Other Compensation for Mssrs. Hoffman and Fowler consists of $24,000 in directors fees.

(4) 2013 Other Compensation to Mr. Hoffman includes a $100,000 signing bonus and $22,500 in director’s fees.

(5) 2012 Other Compensation to Mr. Hoffman consisted of consulting fees

(7) David Fowler received $22,500 in director’s fees during 2013.

The Company awards stock options 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 stock options granted during 2014.

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, 2014.

Outstanding Equity Awards at Fiscal Year End

The following table provides information regarding options exercised by Named Executive Officers during 2014.

No Named Executive Officer exercised options during 2013.

Director Compensation

Beginning in February 2013, all directors received a monthly stipend of $2,000. Additionally, each director received $500 for each meeting physically attended. Each outside director also received 40,000 stock options with an exercise price of $8.00 per share as an annual bonus. Director compensation to Messrs. Fowler and Hoffman is included here but is also included in the executive compensation schedule above. No director receives a salary as a director.

Director Compensation Table