424B1

We are offering 5,000,000 shares of common stock, $.001 par value (“Common Stock”), of Ring Energy, Inc., a Nevada corporation (the “Company”). Our Common Stock is traded on the NYSE MKT under the symbol “REI”. On December 5, 2013, the last reported sales price of our Common Stock was $11.17 per share.

The securities offered in this prospectus involve a high degree of risk. You should carefully consider the matters set forth in “Risk Factors” on page 7 of this prospectus in determining whether to purchase our securities.

We have granted an over-allotment option to the underwriters set forth below. Under this option, the underwriters may elect to purchase a maximum of 750,000 additional shares from us within 30 days following the date of this prospectus to cover over-allotments. If the underwriters exercise the option in full, the total underwriting discounts and commissions payable by us will be $2,875,000, and the total proceeds to us, before expenses, will be $54,625,000.

Delivery of the shares of Common Stock is expected to be made on or about December 11, 2013, subject to customary market closing conditions.

Neither the Securities and Exchange Commission nor any regulatory body has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.

You should rely only on the information contained in this prospectus. Neither we nor the underwriters have authorized anyone to provide you with information that is different from that contained in this prospectus. We do not, and the underwriters do not, take any responsibility for, and can provide no assurances as to, the reliability of any information that others provide to you. We are offering to sell, and seeking offers to buy, shares of our Common Stock only in jurisdictions where offers and sales are permitted. The information contained in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or of any sale of our Common Stock.

PROSPECTUS SUMMARY

This summary contains basic information about us and our Common Stock. You should read this entire prospectus carefully, including the section entitled “Risk Factors” and our financial statements and the notes to the financial statements, before making an investment decision with respect to our Common Stock. You should rely only on the information contained in this prospectus. We have not authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on such information.

Unless the context requires otherwise, all references in this prospectus to “Ring,” “Ring Energy,” the “Company,” “we,” “our” and “us” refers to Ring Energy, Inc. and its subsidiary.

Ring Energy, Inc.

Overview

Ring Energy 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. 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 and Gaines Counties, Texas. Since December 31, 2012, Ring has acquired 8,602 gross acres (4,546 net) in those counties, which brought its acreage position in those counties to 13,495 gross acres (8,400 net) as of November 6, 2013. Ring operates 98% of the Andrews and Gaines County acreage and holds an average working interest of 62.24% and average net revenue interest of 47.31%. The Company currently operates one vertical rig in Andrews County, Texas and believes its acreage position provides substantial drilling opportunities in a play with significant production history, established type curves and attractive returns. The Company also has 16,997 gross acres (14,232 net) in Kansas targeting the Mississippi Lime play. 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 the 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. Ring plans to drill ten vertical wells pursuant to the joint development agreement.

As of December 31, 2012, Ring’s proved reserves were 3.9 million BOE (barrel of oil equivalent). Approximately 97% of its reserves (based on the estimates above) relate to properties located in Texas and approximately 3% from its properties in Kansas. The Company’s proved reserves are oil-weighted with 93% of proved reserves consisting of oil and 7% consisting of natural gas. Of those reserves, 10% of the proved reserves are classified as proved developed producing, or “PDP,” 12% are classified as proved developed non-producing, or “PDNP,” and approximately 78% are classified as proved undeveloped, or “PUD.”

Production for the quarter ended September 30, 2013 was approximately 39,000 BOE, as compared to production of 7,400 BOE for the same quarter of 2012, a 427% increase, and a 100% increase over the 19,000 BOE produced in the second quarter of 2013. The average net daily production for the last five days of September was approximately 750 BOE per day. The stated production amount reflects only the oil and gas that was produced and shipped prior to the end of the quarter. Any oil and gas produced in the third quarter but still held on site after September 30, 2013, will be credited in the fourth quarter.

Ring believes that there is significant value to be created by drilling the identified undeveloped opportunities on its Texas properties. As of November 6, 2013, Ring owns interests in a total of 2,320 gross

(2,127 net) developed acres and 11,175 gross (6,273 net) undeveloped acres in Texas. The Company has 109 identified potential vertical drilling locations based on the reserve report as of December 31, 2012 and an additional 160 identified potential vertical drilling locations based on 20-acre downspacing. Ring believes there is further downspacing opportunity based on results of neighboring operators which would add additional drilling locations to existing acreage. 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 16 wells that are suitable candidates for re-stimulation, providing attractive returns with lower upfront costs. Ring will develop the Kansas acreage through the joint development agreement with Torchlight Energy Resources, Inc. The drilling carry will cover the drilling expenses for approximately the first ten wells.

Ring Energy’s Business Strategy

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Growing production and reserves by developing our oil-rich resource base. Ring intends to actively drill and develop its acreage base in an effort to maximize its value and resource potential. Its portfolio of proved oil and natural gas reserves consists of 93% oil and 7% natural gas. Of those reserves, 10% of the proved reserves are classified as proved developed producing, or “PDP,” 12% are classified as proved developed non-producing, or “PDNP,” and approximately 78% are classified as proved undeveloped, or “PUD.” Through the conversion of undeveloped reserves to developed reserves, Ring will seek to increase production, reserves and cash flow while gaining favorable returns on invested capital. As of December 31, 2012, proved reserves were 3.9 million BOE (barrel of oil equivalent). Approximately 97% of the reserves (based on the estimates above) relate to properties located in Texas and approximately 3% from its properties in Kansas. Ring plans to increase value to its stockholders through the further development of these properties.

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Employ industry leading drilling and completion techniques. Ring’s executive team, which has over 100 years combined experience in the oil and gas industry, intends to utilize new and innovative technological advancements and careful geological evaluation in reservoir engineering to generate value for its stockholders and to build development opportunities for years to come. Improved efficiency through employing technological advancements can provide a significant benefit in a continuous drilling program such as the one Ring contemplates for its current inventory of drilling locations. Additionally, the Company believes that the experience of its executive team will help reduce the time and cost associated with drilling and completing both conventional and horizontal wells, while potentially increasing recovery.

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

Ring Energy’s Strengths

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High quality asset base in one of North America’s leading resource plays. Ring’s acreage in the Permian Basin is all located in Andrews and Gaines Counties, which is located in the heart of the Central Basin Platform. The Central Basin Platform is a NW-trending uplifted basement block that separates the Midland Basin (to the east) from the Delaware Basin (to the west). The area has been de-risked by other operators and currently as of September 2013, there were 9,007 producing oil wells in Andrews County and 3,837 producing oil wells in Gaines County, based on information from the Texas Railroad Commission. Ring has drilled 30 wells on its acreage since late-May 2013 and re-stimulated 7 existing wells. Production for the three months ended September 30, 2013 was 94% oil and 6% natural gas. As of December 31, 2012, estimated net proved reserves were comprised of approximately 93% oil and 7% natural gas, which allow the Company to benefit from the currently more favorable pricing of oil as compared to natural gas.

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De-risked Permian acreage position with multi-year vertical drilling inventory. Since the management team commenced drilling operations in May 2013, Ring has drilled 30 gross operated wells across its leasehold position with a 100% success rate. The Company has also re-stimulated 7 existing wells with attractive well economics. Ring has identified a multi-year inventory of potential drilling locations that will drive reserves and production growth and provide attractive return opportunities. As of December 31, 2012, Ring has 109 identified potential vertical drilling locations in its proved undeveloped reserves. It believes it has an additional 160 additional locations based on 20-acre downspacing with the potential to drill down to 10-acre spacing. The Company views this drilling inventory as de-risked because of the significant production history in the area and well-established industry activity surrounding the acreage.

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Experienced and proven management team focused on the Permian Basin. The executive team has an average of approximately 22 years of industry experience per person, most of which has been focused in the Permian Basin. The Company believes its management and technical team is one of the principal competitive strengths due to the team’s proven ability to identify and integrate acquisitions, focus on cost efficiencies while managing a large-scale development program and disciplined allocation of capital to high-returning projects. Chief Executive Officer Kelly Hoffman has had a successful career in the Permian Basin since 1975 when he started with Amoco Production Company and found further success in West Texas when he co-founded AOCO. In addition, Chairman of the Board Tim Rochford and Director Stan McCabe formed Arena Resources, Inc. (“Arena”) in 2001, which operated in the same proximate area as Ring’s Andrews and Gaines County acreage. Arena eventually sold to SandRidge Energy, Inc. in July 2010. Ring’s management team aims to execute a similar growth strategy and development plan by leveraging its industry relationships and significant operational experience in these regions.

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Concentrated acreage position with high degree of operational control. Ring operates approximately 98% of its Permian Basin and Kansas acreage positions. The operating control allows Ring to implement and benefit from its strategy of enhancing returns through operational and cost efficiencies. Additionally, as the operator of substantially all of acreage, Ring retains the ability to adjust its capital expenditures based on well performance and commodity price forecasts.

Recent Developments

On October 16, 2013, the Company entered into a Development Agreement (the “Development Agreement”) with Torchlight Energy Resources, Inc. to develop the lands described in Exhibit “A” of that certain Letter of Intent dated September 27, 2013 (“Subject Acreage”) by and between the Company and Torchlight Energy Resources, Inc. Prior to commencement of operations, Ring will enter into a Joint Operating Agreement (“JOA”) with Torchlight Energy, whereby the Company will (i) be designated as “Operator” under the JOA and (ii) remain Operator as long as it owns or controls any interest in the Subject Acreage.

The Company has a $10 million revolving line of credit in place with F&M Bank & Trust Company for borrowings and letters of credit. Since September 30, 2013, the Company has drawn $3.5 million under its line of credit. The maturity date on the facility is April 10, 2014.

History

Ring was originally organized under the name of Blanca Corp. in the State of Nevada on July 30, 2004. The name of the corporation was changed of record to Transglobal Mining Corp. on April 8, 2007. The initial purpose of the corporation was to engage in mining development operations within the United States and Canada.

On March 21, 2008, the corporation was acquired by a new majority group of stockholders. At the time of the closing of the majority share acquisition, the corporation divested itself of all mining-related assets and liabilities. On or about March 20, 2008, the corporation changed its name of record in Nevada to Ring Energy, Inc., and the purpose of the corporation changed to focus on the acquisition and development of oil and gas properties and the marketing of oil and gas products derived from those properties. In connection with the closing, the corporation approved, by majority stockholder consent resolution, a reverse split of eighteen-to-one (18:1) of its issued shares, decreasing the issued and outstanding shares.

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.

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 significant 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 Ring.

On June 28, 2013, we completed our offering of 3,528,580 shares of our Common Stock (referred to herein as the “Resale Shares”), aggregating $19,407,190 in a private placement transaction (the “Private Placement”). The Company has filed a registration statement with the Securities and Exchange Commission (the “SEC”) with respect to the Resale Shares and is currently compiling information from such holders so as to address certain comments from the SEC.

Corporate Information

Our principal executive offices are located at 200 N. Loraine Street, Suite 1245, Midland, Texas 79701, 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 prospectus and should not be considered part of this prospectus.

The Offering

The following is a summary of the shares being offered:

Issuer

Ring Energy, Inc.

Common Stock Offered by Us

5,000,000 shares.

Option to purchase additional shares of Common Stock

The underwriters have a 30-day option to purchase up to an additional 750,000 shares of our Common Stock at the public offering price less the underwriting discount and commission.

Common Stock to be Outstanding After the Offering

22,811,313 shares of Common Stock.

The number of shares of Common Stock to be outstanding following this offering is based on 17,811,313 shares of Common Stock outstanding as of November 26, 2013. The outstanding share information in the table above excludes as of November 26, 2013:

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2,562,500 shares of Common Stock issuable upon the exercise of options outstanding, at a weighted-average exercise price of $3.78 per share; and

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2,427,500 shares of our Common Stock reserved for future issuance pursuant to our Long-Term Incentive Plan.

Except as otherwise noted, all information in this prospectus assumes:

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no exercise of the underwriters’ over-allotment option;

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an offering price of $10.00 per share; and

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that no options, warrants, or restricted shares were issued after November 26, 2013 and that no shares underlying options outstanding as of November 26, 2013 were issued.

Use of Proceeds

We estimate that the net proceeds from this offering, after deducting underwriting discount and commissions and estimated offering expenses payable by us, will be approximately $47,237,829 based on a public offering price of $10.00 per share. We plan to use the net proceeds from the sale of Common Stock for the following during the first and second fiscal quarters of 2014:

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To pay for drilling and completing approximately 36 wells and re-working 12 wells, currently budgeted at approximately $22,700,000, on certain oil and gas properties located in Andrews and Gaines Counties, Texas.

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To pay for the construction of tank batteries, flow lines and other infrastructure to support such new wells with an estimated cost of approximately $1,300,000.

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To pay for additional leases of oil and gas properties estimated to cost approximately $8,300,000, including associated title costs.

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To pay down approximately $3,500,000 of borrowings under our credit facility outstanding as of the date of this prospectus.

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To pay for acquisitions of oil and gas properties in and around existing properties in the approximate amount of $11,400,000.

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And with respect to any remainder of funds, to pay for any cost overruns associated with any of the foregoing or other business expenses of the Company.

The foregoing sets forth our current intentions with respect to the net proceeds from this offering. We may reallocate such proceeds for other working capital and general corporate purposes that we deem to be in our best interests or due to unforeseen changes in circumstances or events, including without limitation, well results, economic conditions, and other acquisition opportunities. We expect for these proceeds to constitute only a portion of our capital expenditure budget for 2014, to be announced in early 2014.

NYSE MKT Trading Symbol

REI

Dividend Policy

Ring does not anticipate paying dividends on the Common Stock in the foreseeable future.

Risk Factors

Investing in the Common Stock involves a high degree of risk. You should carefully read and consider the information set forth under the heading “Risk Factors” beginning page 7 of this prospectus.

You should carefully consider each of the risks described below, together with all of the other information contained in this prospectus, before investing in our Common Stock. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected, the trading prices of the Common Stock could decline and you may lose all or part of your investment.

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 78%) or proved developed behind pipe (approximately 12%), 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. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves” (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 facilities, a write-down in the carrying values of our properties could require us to repay 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 facilities.

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 (78%) 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 cannot control the development of the properties we do not operate, which may adversely affect our production, revenues and results of operations.

We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of our drilling and development activities on those properties depend upon a number of factors outside of our control, including:

As a result of any of the above or an operator’s failure to act in ways that are in our best interest, our allocated production revenues and results of operations could be adversely affected.

We could suffer the loss of all or part of the expenses that we prepay to the operators of our properties.

We may be required prepay to the operators of our properties our contractual share of acreage, geophysical and geological costs and other up-front expenses, and drilling and completion costs, on a well-by-well basis. Once a prepayment is made, the operator is under no requirement to keep such funds segregated from funds received by other working interest owners. As a result of any prepayment, we would become a general unsecured creditor of the operator and, therefore, could suffer the loss of all or part of the amount prepaid in the event that an operator has financial difficulties, liens are placed against the operator’s assets or the operator files for bankruptcy.

We are not insured against all risks and 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 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.

Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance.

The oil and natural gas business generally, and our operations specifically, are subject to certain operating hazards such as:

In addition, our operations are susceptible to damage from natural disasters such as flooding or tornados, which involve increased risks of personal injury, property damage and marketing interruptions. The occurrence of one of these operating hazards may result in injury, loss of life, suspension of operations, environmental damage and remediation and/or governmental investigations and penalties. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration and development, or could result in a loss of our properties. 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, it could materially adversely affect our financial condition, results of operations and cash flows.

Our insurance might be inadequate to cover our liabilities. Insurance costs are expected to continue to increase over the next few years, and we may decrease coverage and retain more risk to mitigate future cost increases. If we incur substantial liability, and the damages are not covered by insurance or are in excess of policy limits, then our business, results of operations and financial condition may be materially adversely affected.

We have a $10 million revolving line of credit in place for borrowings and letters of credit. As of the date of this prospectus, approximately $3.5 million was outstanding on our credit facility. If in the future we utilize additional amounts under 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 semi-annual redeterminations. 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.

Our credit facility contains various covenants that limit our management’s discretion in the operation of our business and can lead to an event of default that may adversely affect our business, financial condition and results of operations.

The operating and financial restrictions and covenants in our credit facility, to the extent drawn upon, may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.

Our credit facility contains various covenants that restrict our ability to, among other things, incur liens, incur additional indebtedness, enter into mergers, sell assets, make investments and pay dividends. Various risks, uncertainties and events beyond our control could affect our ability to comply with the covenants required by the credit facility.

We are presently a small company with limited resources and personnel making it difficult to establish a comprehensive system of internal controls without more personnel or external assistance.

Effective internal controls, particularly those related to revenue recognition, are necessary for us to produce reliable financial reports and are important to help prevent financial fraud. If we cannot provide reliable financial reports or prevent financial fraud, our brand and operating results could be harmed. We may in the future discover areas of our internal controls that need improvement. For example, because of size and limited resources, our external auditors have determined that we lack the personnel and infrastructure necessary to properly carry out an independent audit function. We cannot be certain that the measures that we have in place will ensure that we implement and maintain adequate controls over our financial processes and reporting in the future. Any failure to implement required new or improved controls, or difficulties encountered in their implementation, could harm our operating results or cause us to fail to meet our reporting obligations. Inferior internal controls could also lead to misinformation being disseminated to the public, which could have a negative effect on our company and the trading price of our stock.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with U.S. generally accepted accounting principles. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of annual or interim financial statements will not be prevented or detected on a timely basis.

If we are unable to successfully implement and maintain effective internal controls over financial reporting we risk being unable to produce accurate and timely financial statements, and our stock price may be adversely affected as a result.

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 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.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute exploration plans on a timely basis and within budget.

We are highly dependent upon third-party services. The cost of oilfield services typically fluctuates based on demand for those services. There is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploration operations, which could have a material adverse effect on our business, financial condition or results of operations.

In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we may enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. 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 may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.

Growth in accordance with our business plan, if achieved, could place a significant strain on our financial, technical, operational and management resources. As we expand our activities, increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

We could lose leases on certain of our properties unless production is established and maintained on units containing the acreage or the leases are extended.

Oil and natural gas leases generally must be drilled before the end of the lease term or the leaseholder will lose the lease and any capital invested therein. In addition, leases may also be lost due to legal issues relating to the ownership of leases. Any delays in drilling or legal issues causing us to lose leases on properties could have a material adverse effect on our results of operations and reserve growth. If our leases expire, we will lose our right to develop such properties.

Our drilling plans are subject to change based upon various factors, including factors that are beyond our control. Such factors include drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.

Our operations could be impacted by burdens and encumbrances on title to our properties.

Our leasehold acreage may be subject to existing oil and natural gas leases, liens for current taxes and other burdens, including other mineral encumbrances and restrictions customary in the oil and natural gas industry. Such liens and burdens could materially interfere with the use or otherwise affect the value of such properties. Additionally, any cloud on the title of the working interests, leases and other rights owned by us could have a material adverse effect on our operations.

Our operations are subject to hazards inherent in the oil and natural gas industry.

Risks inherent to our industry include the potential for significant losses associated with damage to the environment. Equipment design or operational failures, or vehicle operator error can result in explosions and discharges of toxic gases, chemicals and hazardous substances, and, in rare cases, uncontrollable flows of natural gas or well fluids into environmental media, as well as personal injury, loss of life, long-term suspension or cessation of operations and interruption of our business and/or the business or livelihood of third parties, damage to geologic formations, environmental media and natural resources, equipment and/or facilities and property. We may implement hydraulic fracturing in our operations, a process involving the injection of fluids – usually consisting mostly of water but typically including small amounts of several chemical additives – as well as sand in order to create fractures extending from the wellbore through the rock formation to enable oil or natural gas to move more easily through the rock pores to a production well. In addition, we use and generate hazardous substances and wastes in our operations and may become subject to claims relating to the release of such substances into the environment. In addition, some of our current properties are, or have been, used for industrial purposes, which could contain currently unknown contamination that could expose us to governmental requirements or claims relating to environmental remediation, personal injury and/or property damage. These conditions could expose us to liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages and could materially impair our profitability, competitive position or viability. Depending on the frequency and severity of such liabilities or losses, it is possible that our operating costs, insurability and relationships with employees and regulators could be materially impaired.

Federal and state legislative and regulatory initiatives as well as governmental reviews relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect our level of production.

Hydraulic fracturing is a common and important practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the Environmental Protection Agency (“EPA”) has asserted federal regulatory authority over certain hydraulic fracturing practices. Also, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Certain states, including Texas, and municipalities have adopted, or are considering adopting, regulations that have imposed, or that could impose, more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. For example, in December 2011, the Railroad Commission of Texas finalized regulations requiring public disclosure of all the chemicals in fluids used in the hydraulic fracturing process. Local ordinances or other regulations may regulate or prohibit the performance of well drilling in general and hydraulic fracturing in particular. If new laws or regulations that significantly restrict or regulate hydraulic fracturing are adopted, such legal requirements could cause project delays and make it more difficult or costly for us to perform fracturing to stimulate production from a formation. These delays or additional costs could adversely affect the determination of whether a well is commercially viable. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities.

In addition, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with final results expected to be available by 2014. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. On August 16, 2012, the EPA published final rules under the CAA that, among other things, imposed new source performance standards (“NSPS”) for completions of hydraulically fractured natural gas wells, requiring the use of reduced emission completion techniques.

In addition, the U.S. Department of Energy is conducting an investigation into hydraulic fracturing practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing; and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act (“SDWA”) or other regulatory mechanisms. Any additional regulations of hydraulic fracturing could result in increased operation costs, which could have a material adverse effect on our cash flows and financial condition.

We depend to a large extent on the services of our officers, including Kelly Hoffman, our Chief Executive Officer; David Fowler; our President; Daniel Wilson, our Vice President of Operations; and William Broaddrick, our Chief Financial Officer. These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties and developing and executing financing strategies. The loss of any of these individuals could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any management personnel. Our success will be dependent on our ability to continue to retain and utilize skilled technical personnel.

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

We do not anticipate paying any cash dividends on our Common Stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities.

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 prospectus. Also, our board of directors, without stockholder approval, may determine the price, rights, preferences, privileges and restrictions, including voting rights, of those shares. If the board causes shares of preferred stock to be issued, the rights of the

holders of our Common Stock could be adversely affected. The board’s ability to determine the terms of preferred stock and to cause its issuance, while providing desirable flexibility in connection with possible acquisitions and other corporate purposes, could have the effect of making it more difficult for a third party to acquire a majority of our outstanding voting stock. Preferred shares issued by the board of directors could include voting rights, or even super voting rights, which could shift the ability to control the company to the holders of the preferred stock. Preferred shares could also have conversion rights into shares of Common Stock at a discount to the market price of the Common Stock which could negatively affect the market for our Common Stock. In addition, preferred shares would have preference in the event of liquidation of the corporation, which means that the holders of preferred shares would be entitled to receive the net assets of the corporation 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 Ring, 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 Ring, 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.

The price of our Common Stock may fluctuate significantly, which could negatively affect us and holders of our Common Stock.

The trading price of our Common Stock may fluctuate significantly in response to a number of factors, many of which are beyond our control. For instance, if our financial results are below the expectations of securities analysts and investors, the market price of our Common Stock could decrease, perhaps significantly. Other factors that may affect the market price of our Common Stock include:

In addition, the U.S. securities markets have experienced significant price and volume fluctuations. These fluctuations often have been unrelated to the operating performance of companies in these markets. Market fluctuations and broad market, economic and industry factors may negatively affect the price of our Common Stock, regardless of our operating performance. Any volatility or a significant decrease in the market price of our Common Stock could also negatively affect our ability to make acquisitions using Common Stock. Further, if we were to be the object of securities class action litigation as a result of volatility in our Common Stock price or for other reasons, it could result in substantial costs and diversion of our management’s attention and resources, which could negatively affect our financial results.

We have broad discretion in the use the net proceeds that we will receive from this offering and may not use them in a manner in which our stockholders would consider appropriate.

Our management will have broad discretion in the application of the net proceeds that we will receive from this offering. Our stockholders may not agree with the manner in which our management chooses to allocate and spend these funds. The failure by our management to apply these funds effectively could have a material adverse effect on our business.

Investors in this offering will experience immediate and substantial dilution and additional stock offerings may further dilute stockholders.

The public offering price of the securities offered pursuant to this prospectus is substantially higher than the net tangible book value per share of our Common Stock. Therefore, if you purchase shares of Common Stock in this offering, you will incur immediate and substantial dilution in the pro forma net tangible book value per share of Common Stock from the price per share that you pay for the Common Stock. If the holders of outstanding options exercise those options at prices below the public offering price, you will incur further dilution.

Given our plans and our expectation that we may need additional capital and personnel, we may need to issue additional shares of Common Stock or securities convertible into or exercisable for shares of Common Stock, including preferred stock, options or warrants. The issuance of additional Common Stock may further dilute the ownership of our stockholders.

All statements, other than statements of historical fact included in this prospectus 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 prospectus, 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 prospectus. 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 prospectus 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 prospectus. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Forward-looking statements also involve risks and uncertainties. Many of these risks and uncertainties are beyond our ability to control or predict and could cause results to differ materially from the results discussed in such forward-looking statements. Such risks and uncertainties include, but are not limited to, the following:

Forward-looking statements speak only as of the date of this prospectus. All such forward-looking statements and any subsequent written and oral forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this section and any other cautionary statements that may accompany such forward-looking statements. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements.

We estimate that the net proceeds from this offering will be approximately $47,237,829 (or $54,362,829 if the underwriters fully exercise the over-allotment option, based on public offering price of $10.00 per share. “Net proceeds” is what we expect to receive after deducting the underwriting discount and commission and estimated offering expenses payable by us.

We plan to use the net proceeds from the sale of Common Stock for the following during the first and second fiscal quarters of 2014:

In connection with our $10,000,000 credit facility referenced above, the interest rate charged by the bank on outstanding indebtedness is the bank’s prime rate plus 0.75%. There is approximately $3.5 million outstanding under this credit facility as the result of our recent drawdowns subsequent to September 30, 2013. The proceeds from these recent drawdowns was used to fund drilling costs. We will use a portion of the net proceeds from this offering to pay down our outstanding borrowings under this credit facility. The maturity date of the credit facility is April 10, 2014.

If you invest in our Common Stock, you will experience dilution to the extent of the difference between the public offering price of our Common Stock in this offering and the as adjusted net tangible book value per share of our Common Stock immediately after the offering.

Prior to this offering, our net tangible book value on September 30, 2013, 2013, was $45,789,473, or $2.57 per share. “Net tangible book value” is total assets minus the sum of liabilities and intangible assets. “Net tangible book value per share” is net tangible book value divided by the total number of shares outstanding on September 30, 2013.

After giving effect to adjustments relating to the offering, our pro forma net tangible book value on September 30, 2013, would have been $93,027,302, or $4.08 per share. The adjustments made to determine pro forma net tangible book value per share are the following:

The following table illustrates the pro forma increase in net tangible book value of $1.51 per share and the dilution (the difference between the offering price per share and net tangible book value per share) to new investors:

If the underwriters exercise in full their option to purchase up to 750,000 additional shares of common stock at the public offering price of $10.00 per share, the as adjusted net tangible book value after this offering would be $4.25 per share, representing an increase in net tangible book value of $0.17 per share to existing stockholders and immediate dilution in net tangible book value of $5.75 per share to investors purchasing our Common Stock in this offering at the public offering price.

The number of shares of Common Stock to be outstanding following this offering is based on 17,801,313 shares of Common Stock outstanding as of September 30, 2013. The outstanding share information in the table above excludes as of September 30, 2013:

To the extent that options or warrants are exercised, new options are issued under our equity incentive plans, or we issue additional shares of Common Stock in the future, there will be further dilution to investors participating in this offering. In addition, we may choose to raise additional capital because of market conditions or strategic considerations, even if we believe that we have sufficient funds for our current or future operating plans. If we raise additional capital through the sale of equity or convertible debt securities, the issuance of these securities could result in further dilution to our stockholders.

We are authorized to issue up to 150,000,000 shares of Common Stock, par value $0.001 per share. As of November 26, 2013, there were 17,811,313 shares of our Common Stock issued and outstanding, and no shares of preferred stock outstanding. All outstanding shares of Common Stock are fully paid and nonassessable.

Holders of our Common Stock are entitled to one vote for each share on all matters submitted to a stockholder vote, except as matters that relate only to a series of our preferred stock. Holders of Common Stock do not have cumulative voting rights.

Each outstanding share of voting capital stock of the Company shall be entitled to one vote on each matter submitted to a vote at a meeting of stockholders, except as otherwise provided in the Articles of Incorporation of the Company. Except as otherwise provided by the general corporation laws of the State of Nevada, the Articles of Incorporation of the Company or the Bylaws of the Company, if a quorum is present: (a) directors shall be elected by a plurality of the votes of the shares of capital stock of the Company present in person or represented by proxy at the meeting and entitled to vote on the election of directors; and (b) action on any matter other than the election of directors shall be approved if the votes cast by the holders of shares represented at the meeting and entitled to vote on the subject matter favoring the action exceed the votes cast opposing such action.

Our board of directors is elected annually at the meeting of our stockholders. Each director holds office until the next annual meeting of our stockholders at which his term expires and until his successor is elected and qualified, or until his earlier death, resignation or removal.

Any action that the stockholders could take at a meeting may be taken without a meeting if one or more written consents, setting forth the action taken, shall be signed and dated, before or after such action, by the holders of outstanding stock of each voting group entitled to vote thereon having not less than the minimum number of votes with respect to each voting group that would be necessary to authorize or take such action at a meeting at which all voting groups and shares entitled to vote thereon were present and voted. The consent shall be delivered to us for inclusion in the minutes or filing with the corporate records. We will give notice of any action so taken within ten (10) days of the date of such action to those stockholders entitled to vote thereon who did not give their written consent and to those stockholders not entitled to vote thereon.

According to the Company’s Articles of Incorporation, the authority to adopt, amend or repeal bylaws is reserved exclusively to the Board of Directors.

In the event of a liquidation, dissolution or winding up, each outstanding share of Common Stock entitles its holder to participate pro rata in all assets that remain after payment of liabilities and after providing for any class of stock, if any, having preference over the Common Stock.

The board of directors may from time to time declare, and we may pay, dividends on our outstanding shares in the manner and upon the terms and conditions provided by the general corporation laws of the State of Nevada.

We have not declared or paid any cash dividends on our Common Stock during the last three years. We currently intend to retain future earnings, if any, to finance the expansion of our business. As a result, we do not anticipate paying any cash dividends in the foreseeable future.

The transfer agent and registrar for our Common Stock is Standard Registrar and Transfer Company.

Our Common Stock is listed on the NYSE MKT under the 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”.

This section is a summary and may not describe every aspect of our Common Stock that may be important to you. We urge you to read applicable Nevada law, our articles of incorporation and bylaws, as amended, because they, and not this description, define your rights as a holder our Common Stock. See “Where You Can Find More Information” for information on how to obtain copies of these documents.

Sections 78.378 to 78.3793 of the Nevada Revised Statutes (“NRS”) contain provisions that may prevent any person acquiring a controlling interest in a Nevada company from exercising voting rights. Under NRS Sections 78.378 to 78.3793, an acquiring person who acquires a controlling interest in a company’s common shares may not exercise voting rights on any of these shares unless these voting rights are granted by a majority vote of our disinterested stockholders at a special stockholders’ meeting held upon the request and at the expense of the acquiring person. We have expressly opted-out of, or elect not to be governed by, the “Acquisition of Controlling Interest” provisions contained in NRS Sections 78.378 through 78.3793, inclusive, or any successor statutes.

Board Vacancies are Generally Filled by Remaining Directors and Not Stockholders.

Our bylaws provide that any vacancies on the board of directors may be filled by the vote of the majority of the remaining directors, although less than a quorum. Notwithstanding the immediately preceding sentence, the board of directors may by resolution determine that any such vacancies or newly created directorships shall be filled by our stockholders representing at least one-third (1/3) of the issued and outstanding shares of our capital stock that would be entitled to vote at a meeting of stockholders.

The bylaws provide that a special meeting of stockholders, other than those required by Nevada law, may be called only by the chairperson of the board of directors or our chief executive officer.

The ability to authorize undesignated preferred stock makes it possible for our board of directors to issue one or more series of preferred stock with voting or other rights or preferences that could make it more difficult or prevent a change of control of our company or the removal of our management.

Requirements for Advance Notification of Stockholder Nominations and Proposals.

Our bylaws establish advance notice procedures with respect to stockholder proposals and the nomination of candidates for election as directors.

We have never declared or paid any cash dividends on our Common Stock and we do not anticipate paying cash dividends in the foreseeable future. We currently intend to retain our earnings for use in our business. Future dividends on our Common Stock, if any, will be at the discretion of our board of directors and will depend on, among other things, our operations, capital requirements and surplus, general financial condition, contractual restrictions and such other factors as our board of directors may deem relevant.

Ring is a Midland, Texas based energy 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 primarily drill conventional wells on our properties and look for new properties capable of being developed in a conventional manner.

The corporation was originally organized under the name of Blanca Corp. in the State of Nevada on July 30, 2004. The name of the corporation was changed of record to Transglobal Mining Corp. on April 8, 2007. The initial purpose of the corporation was to engage in mining development operations within the United States and Canada.

On June 28, 2013, we completed our offering of 3,528,580 shares of our Common Stock (referred to herein as the “Resale Shares”), aggregating $19,407,190 in the Private Placement. The Company has filed a registration statement with the SEC with respect to the Resale Shares and is currently compiling information from such holders so as to address comments from the SEC.

On October 16, 2013, we entered into a Development Agreement (the “Development Agreement”) with Torchlight Energy Resources, Inc. to develop the lands described in Exhibit “A” of that certain Letter of Intent dated September 27, 2013 (“Subject Acreage”) by and between the Company and Torchlight Energy Resources, Inc. Prior to commencement of operations we will enter into a Joint Operating Agreement (“JOA”) with Torchlight Energy whereby we will be designated as “Operator” under the JOA, and will remain Operator as long as we own or control any interest in the Subject Acreage.

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:

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.

We principally sell our oil and natural gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities. In areas where there is no practical access to pipelines, oil is trucked to storage facilities. For the past three (3) fiscal years, all revenues from our clients were attributed to the United States. 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 2012, sales to three customers, HollyFrontier Refining and Marketing, ConocoPhillips, and BML, Inc. represented 50%, 25% and 23% of oil and gas revenues, respectively. As of December 31, 2012, HollyFrontier represented 94% of our accounts receivable. 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.

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.

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.

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.

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.

The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business is subject and for which compliance may have a material adverse impact on our capital expenditures, financial condition or results of operations.

Comprehensive Environmental Response, Compensation and Liability Act. Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state statutes impose joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so-called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance found at the site. CERCLA also authorizes the Environmental Protection Agency (the “EPA”) and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.

Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we will generate, transport and dispose or arrange for the disposal of wastes that may fall within CERCLA’s definition of hazardous substances. Comparable state statutes may not contain a similar exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released.

Solid and Hazardous Waste Handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of solid and hazardous waste. Although oil and natural gas waste generally is exempt from regulations as hazardous waste under RCRA, we will generate waste as a routine part of our operations that may be subject to RCRA and not all state and local laws contain a comparable exemption. Further, there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous waste or categorize some non-hazardous waste as hazardous in the future. Any such change could result in an increase in our costs to manage and dispose of waste, which could have a material adverse effect on our financial condition and results of operations.

It is also possible that our oil and natural gas operations may require us to manage naturally occurring radioactive materials, or NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contract with crude oil and natural gas production and processing streams. Some states have enacted regulations governing the handling, treatment, storage and disposal of NORM.

Clean Water Act. The Clean Water Act and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, and fill materials into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of certain permits issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure (“SPCC”) requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the United States Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non–compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, we may be liable for penalties and costs of remediation.

The Oil Pollution Act of 1990 (“OPA 90”) and its regulations impose requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA 90. We believe that compliance with applicable requirements under the OPA 90 will not have a material and adverse effect on us.

Safe Drinking Water Act. The SDWA regulates, among other things, underground injection operations. Hydraulic fracturing continues to be under intense regulatory scrutiny both at the federal level and at the state level. In past legislative sessions, the United States Congress considered two companion bills that if passed would have imposed on our hydraulic fracturing operations significantly more stringent requirements. In addition to subjecting the injection of hydraulic fracturing to the SDWA regulatory and permitting requirements, the proposed legislation would require the disclosure of the chemicals within the hydraulic fluids, which could make it easier for our competition to copy our operations and for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the process could adversely affect ground water. If this or similar legislation is enacted, we could incur substantial compliance costs and the requirements could negatively impact our ability to conduct fracturing activities on our assets.

Many states have considered or adopted legislation or regulations requiring the disclosure of the chemicals used in hydraulic fracturing. Texas has adopted such a program, which is administered by the Railroad Commission of Texas. The Wyoming Oil and Gas Conservation Commission also passed a rule requiring disclosure of hydraulic fracturing fluid. In addition, a number of states in which we plan to conduct, are currently conducting, or may in the future conduct, hydraulic fracturing operations regulatory reviews hydraulic fracturing and new regulations from such reviews could restrict or limit our access to shale formations or could delay our operations or make them more costly.

The BLM has proposed a comprehensive rule regulating hydraulic fracturing on federal and certain tribal lands. The rules impose disclosure requirements on the use of hydraulic fracturing chemicals. These proposed rules also require BLM approval prior to hydraulic fracturing. BLM also would require operators to meet other substantive requirements relating to well integrity and recordkeeping.

The EPA recently issued draft guidance under the SDWA, providing direction about how it will address the use of diesel in hydraulic fracturing activities. The draft guidance provides a definition of diesel fuels and discusses how the EPA’s Underground Injection Control rules will be applied to hydraulic fracturing. Further, in

March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. Final results of the study are expected in 2014. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This additional regulatory scrutiny could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

Air Emissions. Our operations are subject to federal, state and local regulations for the control of emissions from sources of air pollution under the CAA and analogous state and local programs. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction and also impose various monitoring and reporting requirements. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous or toxic air pollutants may require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require us to forego construction, modification or operation of certain air emission sources.

On April 17, 2012, the EPA signed final rules under the CAA regarding emissions from oil and natural gas operations. The EPA rule subjects oil and natural gas operations to regulation under the NSPS and NESHAPS programs under the CAA, and imposes new and amended requirements under both programs. The new rules, among other things, amend standards applicable to natural gas processing plants and would expand the NSPS to include all oil and natural gas operations, imposing requirements on those operations. The EPA also imposed NSPS standards for completions of hydraulically fractured natural gas wells, requiring the use of reduced emission completion techniques. The adopted rules allow in most circumstances, until January 1, 2015, facilities to combust natural gas that would escape during completion activities as an alternative to the reduced emission completion techniques. The NESHAPS proposal includes maximum achievable control technology standards for certain glycol dehydrators and storage vessels, and revises applicability provisions, alternative test protocols and the availability of the startup, shutdown and maintenance exemption. These new requirements may result in increased operating and compliance costs, increased regulatory burdens and delays in our operations. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

Climate Change Legislation. In response to certain scientific studies suggesting that emissions of carbon dioxide, methane and other GHGs are contributing to the warming of the Earth’s atmosphere and other climatic changes, the United States Congress has considered legislation to reduce such emissions. To date, the United States Congress has failed to enact a comprehensive GHG program. Some states, either individually or on a regional level, have considered or enacted legal measures to reduce GHG emissions. Although most of the state-level initiatives have to date focused on large sources of GHG emissions, it is possible that smaller sources of emissions could become subject to GHG emission limitations. The cost of complying with these programs could be significant.

The EPA published finding that emissions of GHGs presented an endangerment to public health and the environment. These findings by the EPA allowed the agency to proceed through a rule-making process with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the CAA. Consequently, the EPA adopted two sets of regulations that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. On June 3, 2010, the EPA published its final rule to address permitting of GHG emissions from stationary sources under the prevention of significant deterioration (“PSD”) and Title V permitting programs. The final rule tailors the PSD and Title V permitting programs to apply to qualifying stationary sources of GHG emissions in a multi-step process, beginning January 2, 2011, with the largest sources first subject to permitting. In addition, the EPA has adopted a rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States. On November 8, 2010, the EPA finalized its regulations to expand its final rule on GHG

emissions reporting to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. Reporting of GHG emissions from such facilities has been required on an annual basis since 2012. While we believe that we will be able to substantially comply with such reporting requirements without any material adverse effect to our financial condition, since such reporting requirements with respect to GHG emissions are new in the oil and natural gas industry, there can be no assurance that our reports will initially be in substantial compliance or that such requirements will not develop into more stringent and costly obligations that may have a significant impact on our operating costs. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our business and results of operations.

OSHA and Other Laws and Regulations on Employee Health and Safety. To the extent not preempted by other applicable laws, we are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes, where applicable. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes, where applicable, require us to organize and maintain information about hazardous materials used or, as applicable, produced in our operations and that this information be provided to employees, state and local government authorities and, where applicable, citizens. OSHA may enforce workplace safety regulations through issuance of citations for violations of its standards, which include, but are not limited to, those regarding hazard communication, personal protective equipment, general environmental controls, and materials handling and storage. We believe that we are in substantial compliance with these requirements where applicable and with other applicable OSHA and comparable requirements.

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act (“NEPA”) which requires federal agencies, including the U.S. Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

Endangered Species Act. The Endangered Species Act, as amended (the “ESA”), and analogous state statutes restrict activities that may affect endangered and threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

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.

As of November 26, 2013, we have thirteen employees, all of whom were 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 retain certain engineers, geologists, landmen, pumpers and other personnel on a contract or fee basis as necessary for our operations.

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.

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, we have focused, and plan to continue to focus, on the following:

We believe that there is significant value to be created by drilling the identified undeveloped opportunities on our properties. We own interests in a total of 2,840 gross (2,541 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, 2012, we owned interests in approximately 13,195 gross undeveloped acres (10,363 net). While our focus will be toward growth through additional acquisitions and leasing, we do plan on drilling wells on our existing acreage to develop the potential contained therein.

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.

Andrews and Gaines County leases – Andrews and Gaines County, Texas. In 2011 we acquired a 100% working interest and a 75% net revenue interest in the initial leases. Throughout 2011 and 2012, we 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 33-100% and the net revenue interests range from 21-75%. As of December 31, 2012, we owned 4,893 acres, with 1,560 acres developed and held by production and the remaining 3,333 acres being undeveloped. We believe the Andrews County leases contain considerable remaining potential drilling. Our reserve estimate includes 109 PUD wells. Our reserve estimates include potential development expenditures.

Kansas Properties – Gray, Finney and 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. There are 12 total wells on the acreage but production is minimal. We believe this acreage has significant potential. However, at this time we have only included three locations in our PUD reserve estimates.

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.

As of December 31, 2012, our estimated proved reserves had a pre-tax PV10 value of approximately $106.0 million and a Standardized Measure of Discounted Future Cash Flows of approximately $71.4 million, approximately 97% of which relate to our properties in Texas and approximately 3% of which relate to our properties located in Kansas. We spent approximately $23.1 million on acquisitions and capital projects during 2011 and 2012. 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, 2012.

Our estimates of proved reserves and related valuations as of December 31, 2012, were based on an independent third party report prepared by W. Craig Gaines, consulting petroleum engineer, as to our Kansas properties, and reserve data compiled by Michael Arguijo, a consulting petroleum engineer contracted by the Company during 2012 and 2013, which was audited by Williamson Petroleum Consultants, Inc., as to our Texas properties. Mr. Gaines compiled the reserve data and prepared a report for our Kansas properties. Mr. Arguijo

compiled the reserve data for our Texas properties. Williamson Petroleum Consultants, Inc., independent petroleum engineers, audited the reserve data compiled by Mr. Arguijo and prepared a report relating to our Texas properties. Mr. Arguijo did not prepare a formal report and is not engaged by the Company to provide any additional services to the Company.

The Company’s reserve estimates and process for developing such estimates are reviewed and approved by our Vice President of Operations, Daniel Wilson, a petroleum engineer, and the Chief Executive Officer, Kelly Hoffman. Mr. Daniel Wilson has 29 years of experience in operating, evaluating and exploiting oil and gas properties. Mr. Kelly Hoffman has 38 years of well-rounded experience in the oil and gas industry.

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 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.

Our 3,935,706 BOE of proved reserves, which consist of approximately 93% oil and 7% natural gas, are summarized below as of December 31, 2012, 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, 2012, our Texas proved reserves had a net pre-tax PV10 value of $103.8 million and Standardized Measure of Discounted Future Net Cash Flows of $67.7 million, and our proved reserves in Kansas had a net pre-tax PV10 value of $2.2 million and Standardized Measure of Discounted Future Net Cash Flows of $1.7 million.

As of December 31, 2012, approximately 10% of the proved reserves have been classified as proved developed producing, or “PDP”. Proved developed non-producing, or “PDNP” reserves constitute approximately 12% and proved undeveloped, or “PUD”, reserves constitute approximately 78%, of the proved reserves as of December 31, 2012.

Total proved reserves had a net pre-tax PV10 value as of December 31, 2012 of approximately $106.0 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $71.4 million. Approximately $11.5 million and $7.7 million, respectively, of total proved reserves, are associated with the PDP reserves, which is approximately 10.9% of total proved reserves’ pre-tax PV10 value. An additional $18.3 million and $12.2 million, respectively, are associated with the PDNP reserves, which is approximately 17.2% of total proved reserves’ pre-tax PV10 value. The remaining $76.2 million and $51.3 million, respectively, are associated with PUD reserves.

Our reserve estimates as of December 31, 2012 include 3.1 million BOE as proved undeveloped reserves. As of December 31, 2011, our reserve estimates included 2.4 million BOE as proved undeveloped reserves. Following is a description of the changes in our PUD reserves from December 31, 2011 to December 31, 2012.

Conversion of approximately 205,806 BOE of reserves from PUD to PDP or PDNP through capital expenditures of approximately $6.6 million.

Upward revision of approximately 183,856 BOE primarily as a result of performance.

Recording of approximately 772,813 BOE in new PUD reserves as a result of acquisitions.

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.

Our reserves data and estimates were compiled, prepared and audited by third party independent consultants, W. Craig Gaines, Michael Arguijo and Williamson Petroleum Consultants, 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 referred to above and those persons employed by Williamson Petroleum Consultants, 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 29 years of experience in operating, evaluating and exploiting oil and gas properties. Mr. Kelly Hoffman has 38 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.

Our estimated average daily production for the month of December, 2012, is summarized below. These tables indicate the percentage of our estimated December 2012 average daily production of 134 BOE/d attributable to each state and to oil versus natural gas production.

The following table summarizes gross and net developed and undeveloped acreage at December 31, 2012 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.

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.

The following table presents our ownership at December 31, 2012, in productive oil and natural gas wells by region (a net well is our percentage ownership of a gross well).

During 2012 we drilled five developmental oil wells and one salt water disposal well. There were no wells being drilled as of December 31, 2012. All five developmental wells were successful and were completed and placed on production. We did not drill any exploratory wells during 2012. We did not drill any wells during 2011 or 2010

In July 2013, Ring entered into its second, ten well renewable drilling contract with Capstar Drilling Company and is currently drilling their twelfth new developmental well on its west Texas leases. Company management estimates it will drill at least 35 new wells by year end 2013. In addition to the new wells, Ring continues to upgrade and improve infrastructure and evaluate its inventory of existing wells for re-stimulation opportunities. Current daily production is expected to increase as the new wells are completed and put into service.

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 $43.04 in 2011 and $36.37 in 2012 and our average production taxes, per BOE, were $4.02 in 2011 and $3.84 in 2012. 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, 2011 and 2012 are shown below.

As of December 31, 2012, we are not committed to providing a fixed quantity of oil or gas under any existing contracts.

Our principal executive offices are in leased office space in Midland, Texas. The leased office space consists of approximately 3,000 square feet. We have approximately 3,700 square feet of additional office space leased in Midland, Texas that we will be relocating to once it is ready for use. 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 anticipate leasing or purchasing additional office space in Midland and Andrews, Texas in the near future.

The following table sets forth information regarding our executive officers, certain other officers and directors as of November 26, 2013. 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’ individual biographies below contain information about their experience, qualifications and skills that led the Board to nominate them.

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.

Messrs. Rochford and McCabe joined the Board in June 2012 as a part of the merger between Ring and Stanford Energy, Inc. Messrs. Hoffman, Fowler, Woodrum and Petrelli joined the Board in January 2013.

Kelly Hoffman – Chief Executive Officer and Director. Mr. Hoffman, 55, 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, 54, 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 – Vice President of Operations. Mr. Wilson, 51, has 29 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, 35, 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 Energy, Inc., as Chief Financial Officer. Subsequent to and as a result of the merger transaction between Stanford and Ring Energy, Inc., 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, 66, 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 the position of CEO 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, 80, 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 Resources, Inc. (“Arena”), serving as Chairman of the Board until 2008 and then as a director of Arena until 2010.

Anthony B. Petrelli – Director. Mr. Petrelli, 60, 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, 72, 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.

There are no family relationships between any director, executive officer, or person nominated or chose by us to become a director or executive officer.

During the past ten years, there have been no events under any bankruptcy act, no criminal proceedings (excluding traffic violations and other minor offenses), and no judgments, injunctions, orders or decrees material to the evaluation of the ability and integrity of any of our directors or executive officers. None of our executive officers or directors have 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.

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 for such committees are available on our website at www.ringenergy.com. The information on, or that can be accessed through our website, is not incorporated by reference into this prospectus and should not be considered part of this prospectus. Requests may also 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.

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 and Petrelli, 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 SEC (see the biographical information for Mr. Woodrum, infra, in this discussion of “Executive Officers and Directors”). Each of Messrs. Woodrum and Petrelli 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 “Executive Officers and Directors”).

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.

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.

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.

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. We will provide such codes to any person without charge, upon request, a copy of the Code of Ethics or Code of Conduct. Such codes are available on our website at www.ringenergy.com. The information on, or that can be accessed through our website, is not incorporated by reference into this prospectus and should not be considered part of this prospectus. Requests may also 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.

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.

Roles of our Compensation Committee and Chief Executive Officer in Compensation Decisions, Use of Compensation Consultants and Compensation Philosophy and Objectives

Ring strives to attract, motivate and retain high-quality executives by providing total compensation that is performance-based and competitive within the labor market in which it competes for executive talent as a public company. Our compensation program is intended to align the interests of management with the interests of stockholders by linking pay with performance, thereby incentivizing performance and furthering the ultimate goal of stockholder value.

This section contains a discussion of the material elements of compensation awarded to, earned by or paid to all individuals serving as the smaller reporting company’s principal executive officer or acting in a similar capacity during the last completed fiscal year (“PEO”), regardless of compensation level, and our company’s two most highly compensated executive officers or employees whose total 2012 compensation exceeded $100,000. These individuals are referred to herein as the (“Named Executive Officers”).

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 New York Stock Exchange) 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, stockholder value. The second objective is to attract, motivate, reward and retain employees, including executive personnel, who contribute to the long-term success of the Company. As described in more detail below, the material elements of our current executive compensation program for Named Executive Officers include a base salary, discretionary annual bonuses and discretionary stock options grants.

We believe 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 Ring’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 stockholder value, and therefore, the value of these benefits is based on performance. The Company’s discretionary annual bonus plan is primarily intended to motivate and reward Named Executive Officers’ performance to achieve specific strategies and operating objectives, as well as improved financial performance.

The Compensation Committee considers the salaries of comparable executives of peer companies for which such information is publicly available. The Compensation Committee believes that bonuses and equity compensation should fluctuate with our success in achieving financial, operating and strategic goals. The Committee’s philosophy is that we should continue to use long-term compensation such as stock options to align stockholder and executives’ interests and should allocate a portion of long-term compensation to the entire executive compensation package.

The Compensation Committee has the authority to retain and terminate compensation consultants and other experts to assist the committee in its evaluation of compensation of any of the executive officers. To date, the Compensation Committee has not retained an outside consultant in establishing its compensation program or in establishing any specific compensation for an executive officer.

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. In approving this salary increase, the Committee took into account factors including, peer group comparisons available to the Committee, each executive’s individual experience and increased responsibilities and improved performance for the Company.

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 2012. The annual discretionary bonus is reported in the “Bonus” column of the “Summary Compensation Table” for each Named Executive Officer.

It is our policy that the Named Executive Officers’ long-term compensation should be directly linked to enhancing profitability and value provided to stockholders 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 stockholder value to compensation. Mr. Broaddrick was granted non-qualified stock options in 2011 and 2012. 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 is 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.

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, 2012.

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. No other executive officer’s salary and bonus exceeded $100,000 during the fiscal year ended December 31, 2012.

The Company awards stock options to key employees and the Named Executive Officers either on the initial date of employment or due to performance incentives throughout the year. The following table reflects the stock options granted during 2012.

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, 2012.

The Company uses the Black-Scholes option pricing model to calculate the fair-value of each option grant. The expected volatility for the 2012 option grants is based on the historical price volatility of the Company’s Common Stock. The expected volatility for the 2011 option grants is based on the historical price volatility of a stock index comprised of similar sized companies in the same industry. We elected to use the simplified method for estimating the expected term as allowed by generally accepted accounting principles for options granted through December 31, 2012 and 2011. Under the simplified method, the expected term is equal to the midpoint between the vesting period and the contractual term of the stock option. The risk-free interest rate represents the U.S. Treasury bill rate for the expected life of the related stock options. The dividend yield represents the Company’s anticipated cash dividend over the expected life of the stock options. The following are the Black-Scholes weighted-average assumptions used for options granted during the periods ended December 31, 2012 and 2011:

No director receives a salary as a director. During 2012, Mr. Denny Nestripke was compensated with a stipend of $1,000 per month. The following table provides certain information regarding the compensation of our directors.

Our directors are reimbursed for their out-of-pocket expenses incurred in connection with their attendance at board meetings.

The following table sets forth information concerning our executive stock compensation plans as of December 31, 2012.

On January 22, 2013, our stockholders acted by way of majority written consent action (pursuant to a solicitation of consents commenced on January 16, 2013, and in lieu of a special meeting of stockholders) to approve the Ring Energy, Inc. 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 stockholders on January 22, 2013. The following is a summary of the material terms of the Plan.

Our Plan currently authorizes 5,000,000 shares of our Common Stock for issuance under the Plan. If any shares of Stock subject to an Award are forfeited or if any Award based on shares of Stock is otherwise terminated without issuance of such shares of Stock or other consideration in lieu of such shares of Stock, the

shares of 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.

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.

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).

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.

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.

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.

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

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 increase materially the aggregate number of shares of stock that may be issued under the Plan except for certain adjustments.

Beginning September 1, 2013, our Common Stock has been 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.

As of December 5, 2013, the last reported sales price of our Common Stock was $11.17 per share.

As of November 26, 2013, there are approximately 334 holders of record of our Common Stock. As of November 26, 2013, 5,086,150 shares, or approximately 29%, of the 17,811,313 shares issued and outstanding as of such date are held by management or affiliated parties.

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 December 2011, our board of directors adopted a long term incentive plan which has been subsequently approved and amended by votes of our stockholders in January 2013. 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 following discussion of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to our financial statements. In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Our actual results and timing of selected events may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors”.

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.

On June 28, 2013, we completed an offering of 3,528,580 shares of Common Stock at $5.50 per share, aggregating $19,407,190 (referred to herein, as the “Resale Shares”). These shares were issued without registration under the Securities Act, by reason of the exemption from registration afforded by the provisions of Section 4(a)(5) and/or Section 4(a)(2) thereof, and Rule 506 promulgated thereunder, as a transaction by an issuer not involving any public offering (constituting a “Private Placement”). Each of the 187 investors in this offering was an accredited investor as defined in Regulation D. Each investor delivered appropriate investment representations with respect to their investment, including their status as “accredited investors”. The Company has filed a registration statement with the SEC with respect to the Resale Shares and is currently compiling information from such holders so as to address comments from the SEC.

During the third quarter of fiscal year 2013, Ring drilled 18 wells on its Permian Basin properties in Andrews County, Texas, making a total of 23 new wells drilled since securing a rig in late-May, and re-stimulated 5 existing wells. 20 of the wells were completed and placed in production, and the remaining 3 wells are in various stages of completion. Production for the quarter ended September 30, 2013, was approximately 39,000 BOE (Barrels of Oil Equivalent), as compared to production of 7,400 BOE for the same quarter of 2012, a 427% increase, and a 105% increase over the 19,000 BOE produced in the second quarter of 2013. The average net daily production for the last five days of September was approximately 750 BOE per day. The stated production amount reflects only the oil and gas that was produced and shipped prior to the end of the quarter. Any oil and gas produced in the third quarter but still held on site after September 30, 2013, will be credited in the fourth quarter.

Results of Operations – For the Three Months Ended September 30, 2013 and 2012

Oil and natural gas sales. For the three months ended September 30, 2013, oil and natural gas sales revenue increased $2,445,992 to $2,820,731, compared to $374,739 for the same period during 2012. Oil sales increased

$2,410,781 and natural gas sales increased $35,211. The increases were the result of higher production, which occurred primarily as a result of drilling completed during late 2012 and during the second and third quarters of 2013. For the three months ended September 30, 2013, oil sales volume increased 22,224 barrels to 26,609 barrels, compared to 4,386 barrels for the same period in 2012. The average realized per barrel oil price increased 23% from $85.25 for the three months ended September 30, 2012, to $104.65 for the three months ended September 30, 2013. For the three months ended September 30, 2013, gas sales volume increased 9,422 thousand cubic feet (MCF) to 9,591 MCF, compared to 169 MCF for the same period in 2012. The average realized natural gas price per MCF decreased 17% from $4.50 for the three months ended September 30, 2012 to $3.75 for the three months ended September 30, 2013.

Oil and gas production costs. Our lease operating expenses (LOE) increased from $216,908 or $49.14 per barrel of oil equivalent (BOE) for the three months ended September 30, 2012 to $291,182 or $10.32 per BOE for the three months ended September 30, 2013. In total, lease operating expenses increased as a result of drilling additional wells during late 2012 and during the second and third quarters of 2013. On a per BOE basis lease, operating expenses were dramatically lower as a result of significantly higher production resulting from development.

Production taxes. Production taxes as a percentage of oil and natural gas sales were 5% during the three months ended September 30, 2012, and remained steady at 5% for the three months ended September 30, 2013. These rates are expected to stay relatively steady unless we make acquisitions in other states with differing production tax rates or the state of Texas or Kansas change their production tax rates.

Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased by $808,992 to $931,022 for the three months ended September 30, 2013, compared to $122,030 during the same period in 2012. The increase was the result of higher production volume and an increase in the average depletion rate from $21.43 per BOE during the three months ended September 30, 2012 to $27.43 per BOE during the three months ended September 30, 2013.

General and administrative expenses. General and administrative expenses increased by $939,880 to $1,611,318 for the three months ended September 30, 2013, compared to $671,438 during the same period in 2012. The increase was primarily the result of an increase in stock-based compensation expenses from $261,856 for the three months ended September 30, 2012, to $896,325 for the three months ended September 30, 2013, and employee and contract staff compensation.

Interest expense. Interest expense decreased by $33,992 to $0 for the three months ended September 30, 2013, compared to the same period in 2012. The decrease was due outstanding debt during the period in 2012, and no debt outstanding during the same period in 2013.

Net loss. For the three months ended September 30, 2013, there was a net loss of $131,493, as compared to a net loss of $631,453 for the three months ended September 30, 2012. The primary reasons for this change were increased revenues partially offset by stock-based and cash-based compensation expenses.

Results of Operations – For the Nine Months Ended September 30, 2013 and 2012

Oil and natural gas sales. For the nine months ended September 30, 2013, oil and natural gas sales revenue increased $4,219,003 to $5,264,267, compared to $1,045,264 for the same period during 2012. Oil sales increased $4,158,161, and natural gas sales increased $60,842. The increases were the result of higher production, which occurred primarily as a result of drilling completed during late 2012 and during the second and third quarters of 2013. For the nine months ended September 30, 2013, oil sales volume increased 43,462 barrels to 55,116 barrels, compared to 11,653 barrels for the same period in 2012. The average realized per barrel oil price increased 6% from $88.62 for the nine months ended September 30, 2012 to $94.18 for the nine months ended September 30, 2013. For the nine months ended September 30, 2013, gas sales volume increased

19,121 thousand cubic feet (MCF) to 22,440 MCF, compared to 3,319 MCF for the same period in 2012. The average realized natural gas price per MCF decreased 13% from $3.77 for the nine months ended September 30, 2012 to $3.27 for the nine months ended September 30, 2013.

Oil and gas production costs. Our lease operating expenses (LOE) increased from $592,163 or $48.51 per barrel of oil equivalent (BOE) for the nine months ended September 30, 2012 to $646,905 or $10.99 per BOE for the nine months ended September 30, 2013. In total, lease operating expenses increased as a result of drilling additional wells in late 2012 and in the second and third quarters of 2013. On a per BOE basis lease, operating expenses were dramatically lower as a result of significantly higher production resulting from development.

Production taxes. Production taxes as a percentage of oil and natural gas sales were 5% during the nine months ended September 30, 2012 and remained steady at 5% for the nine months ended September 30, 2013. These rates are expected to stay relatively steady unless we make acquisitions in other states with differing production tax rates or the state of Texas or Kansas change their production tax rates.

Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased by $1,387,180 to $1,694,659 for the nine months ended September 30, 2013, compared to $307,389 during the same period in 2012. The increase was the result of higher production volume and an increase in the average depletion rate from $21.43 per BOE during the nine months ended September 30, 2012 to $27.43 per BOE during the nine months ended September 30, 2013.

General and administrative expenses. General and administrative expenses increased by $2,852,644 to $4,678,581 for the nine months ended September 30, 2013, compared to $1,825,937 during the same period in 2012. The increase was primarily the result of an increase in stock-based compensation expenses from $707,090 for the nine months ended September 30, 2012 to $2,598,046 for the nine months ended September 30, 2013, and employee and contract staff compensation.

Interest expense. Interest expense decreased by $221,838 to $0 for the nine months ended September 30, 2013, compared to the same period in 2012. The decrease was due outstanding debt during the period in 2012, and no debt outstanding during the same period in 2013.

Net loss. For the nine months ended September 30, 2013, there was a net loss of $1,987,166, as compared to net loss of $1,803,104 for the nine months ended September 30, 2012. The primary reasons for this increase were increased stock-based and cash-based compensation expenses, partially offset by increased revenues.

As shown in the financial statements for the nine months ended September 30, 2013, the Company had cash on hand of $7,867,616, compared to $5,404,167 as of December 31, 2012. The Company had net cash from operating activities for the nine months ended September 30, 2013, of $5,049,526, compared to cash from operating activities of $510,642 for the same period of 2012. Another significant source of cash inflow during the nine months ended September 30, 2013, was $18,987,272 proceeds from issuance of common stock. During the same period in 2012, other significant cash inflows were proceeds from borrowings by the Company of $1,150,000, proceeds from issuance of common stock of $11,545,983, and proceeds from the issuance of common stock to Ring Energy, Inc. stockholders of $10,887,561. The most significant cash outflows during the nine months ended September 30, 2013 and 2012 were capital expenditures of $21,564,959 and $5,014,880, respectively, and payments on credit line of $9,244,428 during 2012.

assets, distributions or dividends and merger or consolidation activity. The facility has 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 April 10, 2014. Two of the Company’s stockholders are jointly and severally obligated for outstanding borrowings under the credit facility.

To the extent possible, we intend to acquire producing properties and/or developed undrilled properties rather than exploratory properties. We do not intend to limit our evaluation to any one state. We presently have no intention to evaluate off-shore properties or properties located outside of the United States of America.

The pursuit of and acquisition of additional oil and gas properties may again require substantially greater capital than we currently have available, and obtaining additional capital would require that we enter into the sale of either short-term or long-term notes payable or the sale of our Common Stock. Furthermore, it may be necessary for us to retain outside consultants and others in our endeavors to locate desirable oil and gas properties. The cost to retain one or more consultants or a firm specializing in the purchase/sale of oil and gas properties will have an impact on our financial position and will impact our future cash flows.

The process of acquiring one or more additional oil and gas properties will impact our financial position and reduce our cash position. The types of costs that we may incur include travel costs relating to meeting with individuals instrumental to our acquisition of one or more oil and gas properties, obtaining petroleum engineer reports relative to the oil and gas properties that we are investigating, legal fees associated with any such acquisitions including title reports, and accounting fees relative to obtaining historical information regarding such oil and gas properties. Even though we may incur such costs, there is no assurance that we will ultimately be able to consummate a transaction resulting in our acquisition of an oil and/or gas property.

We have increased our reserves significantly by investing approximately $16.5 million in acquisitions and development in 2012, following total capital expenditures of approximately $6.6 million in 2011.

Our business plan is to increase our base of proven reserves primarily through acquisition until we have acquired a sufficient core to enable us to utilize cash from existing production to fund further development activities. We believe this allows us to lessen our risks, including risks associated with borrowing funds to undertake exploration activities at an earlier time. Our focus has been on acquiring operated properties (i.e. properties with respect to which we serve as the operator on behalf of all joint interest owners) so that we can better control the timing and implementation of capital spending. However, we do plan on exploiting our existing properties and also growing reserves through development.

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

In a worst case scenario, future drilling operations could be largely unsuccessful, oil and gas prices could further decline and/or other factors beyond our control could cause us to greatly modify or substantially curtail our development plans, which could negatively impact our earnings, cash flow and most likely the trading price of our securities, as well as the acceleration of debt repayment and a reduction in our borrowing base under our credit facilities.

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

Oil and natural gas sales. Oil and natural gas sales revenue increased approximately $1.3 million to $1.8 million in 2012. Oil sales increased approximately $1.3 million while the increased natural gas sales were negligible. The oil sales increase was the result of an increase in sales volume from 5,297 barrels of oil in 2011 to 20,531 barrels of oil in 2012, despite a 5% decrease in the average realized per barrel oil price from $88.50 in 2011 to $84.50 in 2012. 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 2,369 Mcf in 2011 to 6,480 Mcf in 2012, despite a 51% decrease in the average realized per Mcf gas price from $7.11 in 2011 to $3.50 in 2012. 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 $244,966 in 2011 to $785,959 in 2012, and decreased on a BOE basis from $43.04 in 2011 to $36.37 in 2012. 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. We expect further reductions in our production costs per BOE as we move forward.

Oil and gas production taxes. Oil and gas production taxes as a percentage of oil and natural gas sales were 4.71% during 2011 and increased slightly to 4.72% in 2012. 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 $417,271 to $506,786 in 2012. The increase was a result of increased production volumes and an increase in the average depreciation, depletion and amortization rate from $19.19 per BOE during 2011 to $21.94 per BOE during 2012. These per BOE amounts are calculated by dividing our total depreciation, depletion and

amortization expense by our total volume sold, in BOE. The increased depreciation, depletion and amortization rate was the result of acquisitions throughout the year.

General and administrative expenses. General and administrative expenses increased by $1,955,431 to $2,392,645 during 2012. This increase was primarily related to an increase in stock based compensation expense of $848,784 and increases in other compensation expense to both company employees and contract employees.

Interest income. Interest income was $4,309 in 2012 with no interest income recorded during 2011. The increase was the result of higher cash on hand during 2012.

Interest expense. Interest expense increased by $124,586 to $218,805 in 2012. The increase was the results of having larger amounts borrowed on our credit facility for a portion of 2012.

Net income (loss). Net loss was $1,669,283 in 2012 compared to net income of $71,487 during 2011. The primary reason for this change was the increase in general and administrative expenses and depreciation, depletion and amortization.

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

Credit Facility. In May 2011, the Company entered into a credit agreement with a bank that provides for a revolving line of credit of up to $10 million for borrowings and letters of credit. As of December 31, 2012, $9,950,000 was available to be drawn on the line of credit with the remainder being reserved by letters of credit to State regulatory agencies. The agreement includes a non-usage commitment fee of 0.20% per annum and covenants limiting other indebtedness, liens, transfer or sale of assets, distributions or dividends and merger or consolidation activity. The facility has 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%. As of December 31, 2012, the interest rate being charged was 4.00%. Subsequent to December 31, 2012, the note was extended to April 10, 2014. Two of the Company’s stockholders are jointly and severally obligated for outstanding borrowings under the credit facility.

Cash Flows. Our primary source of cash has been from equity offerings and borrowings either on our credit facility or from Ring Energy, Inc. prior to the merger. During the two years ended December 31, 2012, we financed $23,896,623 through proceeds from the sale of stock and $11,244,428 through borrowings. We primarily used this cash to fund our capital expenditures and development aggregating $15,850,289 over the two years ended December 31, 2012, reducing debt of $11,244,428 and redemption of Common Stock prior to the merger of $4,521,572. At December 31, 2012, we had cash on hand of $5,404,167 and working capital of $4,691,099, compared to December 31, 2011 when our cash was $11,372 and we had negative working capital of $253,362.

Schedule of Contractual Obligations. The following table summarizes our future estimated lease payments for periods subsequent to December 31, 2012. The leases pertain to approximately 3,000 square feet of space for our corporate headquarters in Midland, Texas, approximately 3,700 square feet of office space that we may relocate to in Midland, Texas, approximately 3,700 square feet of office space for our accounting offices in Tulsa, Oklahoma and approximately 2,000 square feet of office space for our field office in Andrews, Texas. The Company incurred lease expense of $208,091 and $0 for the years ended December 31, 2012 and 2011, respectively. The following table reflects the future minimum lease payments under the operating lease as of December 31, 2012.

As of September 30, 2013, we did not have any off-balance sheet arrangements, and it is not anticipated that we will enter into any off-balance sheet arrangements.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING METHODS AND FINANCIAL DISCLOSURE

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 and 2011 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 two fiscal years 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 Hansen, Barnett & Maxwell, P.C. with 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.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth certain information furnished by current management and others, concerning the ownership of our Common Stock as of November 26, 2013, of (i) each person who is known to us to be the beneficial owner of more than 5 percent of our Common Stock, without regard to any limitations on conversion or exercise of convertible securities or warrants; (ii) all directors and Named Executive Officers; and (iii) our directors and executive officers as a group. The mailing address for each of the persons indicated is our corporate headquarters. The percentage ownership is based on 17,811,313 shares outstanding at November 26, 2013.

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

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

In May 2011, the Company entered into a credit agreement with a bank that provides for a revolving line of credit of up to $10 million. The credit agreement was extended to mature April 10, 2014. Lloyd T. Rochford and Stanley M. McCabe, directors and stockholders of the Company, are jointly and severally obligated for outstanding borrowings under the credit facility.

The office space being leased by the Company in Tulsa, Oklahoma, is owned by Arenaco LLC, a company that is owned by Messrs. Rochford and McCabe. During the years ended December 31, 2012 and 2011, the Company paid $29,000 to Arenaco LLC.

The Board of Directors will review and approve all relationships and transactions in which it and its directors, director nominees and executive officers and their immediate family members, as well as holders of more than 5% of any class of its voting securities and their family members, have a direct or indirect material interest. In approving or rejecting such proposed relationships and transactions, the Board shall consider the relevant facts and circumstances available and deemed relevant to this determination.

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

Consistent with these standards, our Board of Directors has determined that Messrs. Rochford, Woodrum, Petrelli and McCabe are our independent directors.

Our Bylaws provide that we may indemnify our officers, directors, employees or agents. The general effect of the foregoing is to indemnify such persons from liability, thereby making us responsible for any expenses or damages incurred by such control person, officer or director in any action brought against them based on their conduct in such capacity, provided they did not engage in fraud or criminal activity.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to our directors, officers or control persons pursuant to the foregoing provisions, we have been informed that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

SunTrust Robinson Humphrey, Inc. is acting as the representative of the underwriters named below. Under the terms and subject to the conditions contained in an underwriting agreement, which will be filed as an exhibit to the registration statement of which this prospectus forms a part, we have agreed to sell to each of the underwriters named below the following respective number of shares of Common Stock shown opposite its name:

“Northland Capital Markets” is the trade name for certain capital markets and investment banking services of Northland Securities, Inc., member, FINRA/SIPC.

The underwriting agreement provides that the underwriters are obligated to purchase all of the shares of Common Stock in this offering if they are purchased, other than those shares covered by the underwriters’ option to purchase additional shares described below, subject to the satisfaction of the conditions contained in the underwriting agreement, including that:

The following table summarizes the underwriting discounts and commissions we will pay to the underwriters and the other estimated expenses we will pay in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares. The underwriting fee is the difference between the price to the public and the amount the underwriters pay to us for the shares.

The expenses of the offering, not including the underwriting discounts and commissions, payable by us are estimated to be $262,171.20, which amount includes up to $15,000 that we have agreed to reimburse the underwriters for fees and expenses of counsel relating to certain aspects of this offering.

The representative of the underwriters has advised us that the underwriters propose to offer the shares of Common Stock directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $0.30 per share. After the offering, the representative may change the offering price and other selling terms. Sales of shares made outside of the United States may be made by affiliates of the underwriters.

We have granted the underwriters an option exercisable for 30 days after the date of the underwriting agreement, to purchase up to 750,000 additional shares at the public offering price less underwriting discounts and commissions. This option may be exercised only to cover any overallotments of Common Stock. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional shares based on the underwriter’s underwriting commitment in the offering as indicated in the table at the beginning of this “Underwriting” section.

We and all of our directors and executive officers have agreed that, without the prior written consent of SunTrust Robinson Humphrey, Inc., we and they will not directly or indirectly, (1) offer for sale, sell, issue, contract to sell, pledge or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any shares of our Common Stock or securities convertible into or exchangeable for our Common Stock (other than shares sold in this offering), or with respect to us, sell or grant options, rights or warrants with respect to any shares of our Common Stock or securities convertible into or exchangeable for our Common Stock (other than the issuance of options pursuant to a registration statement on Form S-8 and securities we may issue in future acquisitions of oil and gas properties or companies, which shares will remain subject to these lock-up restrictions upon issuance and for the remainder of the lock-up period), (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic benefits or risks of ownership of such shares of our Common Stock, whether any such transaction described in clause (1) or (2) above is to be settled by delivery of our Common Stock or other securities, in cash or otherwise, (3) offer to purchase, purchase or contract to purchase or grant any option, right or warrant to purchase our Common Stock or securities convertible, exercisable or exchangeable into our Common Stock or any other securities of the Company, (4) file or cause to be filed a registration statement, including any amendments, with respect to the registration of any shares of our Common Stock or securities convertible, exercisable or exchangeable into our Common Stock or any other securities of the Company (other than with respect to the Company, any registration statement on Form S-8 or any amendment to any registration statement already filed with the Commission as of the date of this prospectus), (5) establish or increase a put equivalent position or liquidate or decrease a call equivalent position in securities of the Company or (6) publicly disclose the intention to do any of the foregoing for a period of 90 days after the date of this prospectus.

SunTrust Robinson Humphrey, Inc., in its sole discretion, may release the Common Stock and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release Common Stock and other securities from lock-up agreements, SunTrust Robinson Humphrey, Inc. will consider, among other factors, the holder’s reasons for requesting the release, the number of shares of Common Stock and other securities for which the release is being requested and market conditions at the time.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.

In connection with this offering, the underwriters may engage in stabilizing transactions, overallotment transactions, syndicate covering transactions and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the Common Stock, in accordance with Regulation M under the Exchange Act.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our Common Stock or preventing or retarding a decline in the market price of our Common Stock. As a result, the price of our Common Stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on or otherwise and, if commenced, may be discontinued at any time. Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the Common Stock. In addition, neither we nor any of the underwriters make any representation that the underwriters will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

A prospectus in electronic format may be made available on websites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. In addition, one or more of the underwriters participating in this offering may distribute prospectuses electronically. The underwriters may agree with us to allocate a specific number of shares for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representative on the same basis as other allocations. Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s website and any information contained in any other website maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

The underwriters have informed us that they do not expect sales to accounts over which the underwriters have discretionary authority to exceed 5% of the total number of shares offered by them.

Some of the underwriters and their affiliates have engaged in and may, from time to time in the future engage, in transactions with and perform services for us, such as other commercial banking services, investment banking and financial advisory services, fairness opinions and other similar services, including those that may be provided in connection with any acquisitions or investments we may make, for which they have received, or may in the future receive customary compensation. Additionally, in the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investment and securities activities may involve our securities and instruments.

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC and includes any relevant implementing measure in each relevant member state.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

This prospectus is only being distributed to, and is only directed at, persons in the United Kingdom that are qualified investors within the meaning of Article 2(1)(e) of the Prospectus Directive (“Qualified Investors”) that are also (i) investment professionals falling within Article 19(5) of the Financial Services and Markets Act

2000 (Financial Promotion) Order 2005 (the “Order”) or (ii) high net worth entities, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (all such persons together being referred to as “relevant persons”). This prospectus and its contents are confidential and should not be distributed, published or reproduced (in whole or in part) or disclosed by recipients to any other persons in the United Kingdom. Any person in the United Kingdom that is not a relevant person should not act or rely on this document or any of its contents.

Burleson LLP has provided its opinion regarding the validity of our Common Stock offered by this prospectus. Certain legal matters in connection with this offering will be passed upon for the underwriters by Goodwin Procter LLP, New York, New York.

The audited balance sheets as of December 31, 2012 and December 31, 2011, and the related consolidated statements of operations, statements of stockholders’ equity and cash flows for each of the two years in the period ended December 31, 2012, included in this prospectus and elsewhere in the registration statement, to which this prospectus forms a part, have been so included in reliance upon the report of Hansen, Barnett & Maxwell P.C., an independent registered public accounting firm, upon the authority of said firm as experts in accounting and auditing in giving said report.

The information regarding estimated quantities of oil and natural gas reserves and the discounted present value of future pre-tax cash flows therefrom is based upon estimates of such reserves and present values prepared by or derived from estimates included in this prospectus, prepared by independent third party engineers and audited by Williamson Petroleum Consultants, independent petroleum engineering consultants. The information contained in this prospectus regarding the estimated quantities of oil and natural gas reserves and the discounted present value of future pre-tax cash flows therefrom is based upon estimates of such reserves and present values as of December 31, 2012, prepared by or derived from the “Review of Estimates” dated December 31, 2012, prepared by Williamson Petroleum Consultants as to our Texas properties and were prepared by or derived from the “SEC reserve appraisal” dated January 23, 2013, prepared by W. Craig Gaines as to our Kansas properties. All such information in this prospectus has been included in reliance on the authority of said firm as experts in petroleum engineering.

We are subject to the information requirements of the Exchange Act and in accordance therewith, file reports and other information with the SEC. Such reports and other information filed by us can be inspected and copied at the public reference facilities of the SEC at 100 F Street N.E., Washington, D.C. 20549. Requests for copies should be directed to the SEC’s Public Reference Section, Judiciary Plaza, 100 F Street N.E., Washington, D.C. 20549. Please call the SEC at 1–800–SEC–0330 for more information on the public reference rooms. The SEC maintains a web site (www.sec.gov) that contains reports, proxy and information statements and other information regarding registrants, including us, that file electronically.

We have filed with the SEC a Registration Statement on Form S–1 (the “Registration Statement”) of which this prospectus constitutes a part, under the Securities Act. For further information pertaining to us, reference is made to the Registration Statement. Statements contained in this prospectus concerning the provisions of documents are necessarily summaries of such documents, and each such statement is qualified in its entirety by reference to the copy of the applicable document filed with the SEC. Copies of the Registration Statement are on file at the offices of the SEC and may be inspected without charge at the offices of the SEC, the addresses of which is set forth above, and copies may be obtained from the SEC at prescribed rates. The Registration Statement has been filed electronically through the SEC’s Electronic Data Gathering, Analysis and Retrieval System and may be obtained through the Commission’s web site (www.sec.gov).

“Bbl” – One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGLs.

“Boe” – Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

“Completion” – The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Condensate” – Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

“Developed acreage” – The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Developed reserves” – Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor when compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“Development well” – A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry hole” – A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production do not exceed production expenses and taxes.

“Economically producible” – A resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

“Exploratory well” – A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

“Field” – An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition.

“Formation” – A layer of rock which has distinct characteristics that differ from nearby rock.

“Gross acres or gross wells” – The total acres or well, as the case may be, in which a working interest is owned.

“Horizontal drilling” – A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“Net acres or net wells” – The sum of the fractional working interest owned in gross acres or gross wells. An owner who has 50% interest in 100 acres owns 50 net acres.

“Net revenue interest” – An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

“Productive well” – A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Prospect” – A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons.

“Proved developed non-producing” or “PDNP” – Proved oil and natural gas reserves that are developed behind pipe or shut-in or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion prior to the start of production. The hydrocarbons are classified as proved but non-producing reserves.

“Proved developed reserves” – Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.

“Proved reserves” – Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data.

“Proved undeveloped reserves (PUD)” – Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

“PV-10” When used with respect to natural gas and oil reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production, future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles, or GAAP, and generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor standardized measure represents an estimate of the fair market value of our natural gas and oil properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

“Reserves” – Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development projects to known accumulations.

“Reservoir” – A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

“Spacing” – The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Standardized measure of discounted future net cash flows” – The present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the regulations of the Securities and Exchange Commission, without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses or depreciation, depletion and amortization; discounted using an annual discount rate of 10%.

“Undeveloped acreage” – Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves.

“Working interest” – The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals and receive a share of the production. The working interest owners bear the exploration, development, and operating costs of the property.

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

Condensed Financial Statements – The accompanying condensed consolidated financial statements prepared by Ring Energy, Inc. and its subsidiary (the “Company” or “Ring”) have not been audited by an independent registered public accounting firm. In the opinion of the Company’s management, the accompanying unaudited financial statements contain all adjustments necessary for fair presentation of the results of operations for the periods presented, which adjustments were of a normal recurring nature, except as disclosed herein. The results of operations for the three and nine months ended September 30, 2013 are not necessarily indicative of the results to be expected for the full year ending December 31, 2013.

Certain notes and other disclosures have been omitted from these interim financial statements. Therefore, these financial statements should be read in conjunction with the Company’s 2012 Annual Report on Form 10-K.

Organization and Nature of Operations – The Company is a Nevada corporation that owns interests in oil and natural gas properties located in Texas and Kansas. The Company’s oil and natural gas sales, profitability and future growth are dependent upon prevailing and future prices for oil and natural gas and the successful acquisition, exploration and development of oil and natural gas properties. Oil and natural gas prices have historically been volatile and may be subject to wide fluctuations in the future. A substantial decline in oil and natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced.

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

Consolidation – The accompanying consolidated financial statements include the accounts, operations and cash flows of Stanford Energy, Inc. (“Stanford”) for all periods presented and the consolidated operations and cash flows of Ring Energy, Inc. from June 28, 2012. All significant intercompany balances and transactions have been eliminated in consolidation.

Concentration of Credit Risk and Major Customer – The Company had cash in excess of federally insured limits at September 30, 2013. During the nine months ended September 30, 2013, sales to one customer represented 95% of the Company’s oil and gas revenues. At September 30, 2013, this customer made up 91% of the Company’s accounts receivable.

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

All capitalized costs of oil and gas properties, plus estimated future costs to develop proved reserves, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent

NOTE 1 – BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES (continued)

engineers.The Company evaluates oil and gas properties for impairment at least annually. Amortization expense for the three and nine months ended September 30, 2013 was $917,116 and $1,657,386, respectively, based on depletion at the rate of $27.43 per barrel of oil equivalent compared to $117,267 and $293,102, respectively, for the three and nine months ended September 30, 2012, based on depletion at the rate of $21.43 per barrel of oil equivalent. These amounts include $17,584 and $42,990, respectively, of depreciation for the three and nine months ended September 30, 2013 compared to $10,501 and $31,502 of depreciation for the three and nine months ended September 30, 2012, respectively.

In addition, capitalized costs are subject to a ceiling test which limits such costs to the estimated present value of future net revenues from proved reserves, discounted at a 10% interest rate, based on current economic and operating conditions, plus the lower of cost or fair value of unproved properties. Consideration received from sales or transfers of oil and gas property is accounted for as a reduction of capitalized costs. Revenue is not recognized in connection with contractual services performed on properties in which the Company holds an ownership interest.

Office Equipment – Office equipment is valued at historical cost adjusted for impairment loss less accumulated depreciation. Historical costs include all direct costs associated with the acquisition of office equipment and placing it in service. Depreciation is calculated using the straight-line method based upon an estimated useful life of 5 to 7 years.

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

Revenue Recognition – The Company predominantly derives its revenues from the sale of produced oil and natural gas. Revenue is recorded in the month the product is delivered to the purchasers. At the end of each month, the Company recognizes oil and natural gas sales based on estimates of the amount of production delivered to purchasers and the price to be received. Variances between the Company’s estimated oil and natural gas sales and actual receipts are recorded in the month the payments are received.

Share-Based Employee Compensation – The Company has outstanding stock option grants to directors and employees, which are described more fully in Note 6. The Company recognizes the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award and recognizes the related compensation expense over the period during which an employee is required to provide service in exchange for the award, which is generally the vesting period.

Share-Based Compensation to Non-Employees – The Company accounts for share-based compensation issued to non-employees as either the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable. The measurement date for these issuances is the earlier of (i) the date at which a commitment for performance by the recipient to earn the equity instruments is reached or (ii) the date at which the recipient’s performance is complete.

Recent Accounting Pronouncements – The Company has reviewed all recently issued, but not yet effective, accounting pronouncements and does not believe the future adoptions of any such pronouncements are expected to cause a material impact on the Company’s financial condition or the results of operations.

NOTE 1 – BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES (continued)

Basic and Diluted Loss per Share – Basic loss per share is computed by dividing net loss by the weighted-average number of common shares outstanding during the period. Diluted loss per share reflects the potential dilution that could occur if all contracts to issue common stock were converted into common stock, except for those that are anti-dilutive. The dilutive effect of stock options and other share-based compensation is calculated using the treasury method with an offset from expected proceeds upon exercise of the stock options and unrecognized compensation expense.

Stock options to purchase 2,562,500 shares of common stock were excluded from the computation of diluted loss per share during the three and nine months ended September 30, 2013 as their effect would have been anti-dilutive. Stock options to purchase 1,125,000 shares of common stock were excluded from the computation of diluted loss per share during the three and nine months ended September 30, 2012 as their effect would have been anti-dilutive.

In August 2013, the Company extended a credit agreement with a bank that provides for a revolving line of credit of up to $10 million for borrowings and letters of credit. As of September 30, 2013, no amounts were outstanding and $9,855,000 was available to be drawn on the line of credit. The credit agreement includes 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 has 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 facility was extended to April 10, 2014. Two of the Company’s stockholders are jointly and severally obligated for outstanding borrowings under the credit facility.

The Company provides for the obligation to plug and abandon oil and gas wells at the dates properties are either acquired or the wells are drilled. The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The asset retirement obligation incurred upon each of the acquisitions or at the time of drilling was computed using the annual credit-adjusted risk-free discount rate at the applicable dates, which rates were from 6.12% to 7.62% per annum. Changes in the asset retirement obligation were as follows:

Common Stock Issued in Offerings – In January 2013, the Company issued 100,000 shares of common stock, for cash of $450,000, or $4.50 per share, in a private placement offering.

In June 2013, the Company completed a private placement offering of 3,528,580 shares of common stock, for gross proceeds of $19,407,190, or $5.50 per share. Net proceeds from the offering, after offering costs, totaled approximately $18,537,272.

Common Stock Issued in Option Exercise – In January 2013, the Company issued 6,722 shares of common stock pursuant to the cashless exercise of 10,000 options that had an exercise price of $2.00 per share.

Compensation expense charged against income for share-based awards during the three and nine months ended September 30, 2013 was $896,325 and $2,598,046, respectively, as compared to $261,856 and $707,090, respectively, for the three and nine months ended September 30, 2012. These amounts are included in general and administrative expense in the accompanying financial statements.

In 2011, Stanford’s Board of Directors and stockholders approved and adopted a long-term incentive plan which allows for the issuance of up to 2,500,000 shares of common stock through the grant of qualified stock options, non-qualified stock options and restricted stock. In 2013, the stockholders approved an amendment to the long-term incentive plan, increasing the number of shares eligible under the plan to 5,000,000 shares. As of September 30, 2013, there were 2,427,500 shares remaining eligible for issuance under the plan.

The fair value of each option award is estimated on the date of grant using the Black-Scholes option pricing model and using certain assumptions. The expected volatility is based on the historical price volatility of the Dow Jones U.S. Oil and Gas Index. The Company uses the simplified method for estimating the expected term for options granted. Under the simplified method, the expected term is equal to the midpoint between the vesting period and the contractual term of the stock option. The risk-free interest rate represents the U.S. Treasury bill rate for the expected life of the related stock options. The dividend yield represents the Company’s anticipated cash dividend over the expected life of the stock options. The following are the assumptions used to determine the fair value of options granted during the nine months ended September 30, 2013:

A summary of the stock option activity as of September 30, 2013 and changes during the nine months then ended is as follows:

The weighted-average grant-date fair value of options granted during 2013 was $4.20 per share. As of September 30, 2013, there was approximately $5,155,124 of unrecognized compensation cost related to stock options that is expected be recognized over a weighted-average period of 2.6 years. The aggregate intrinsic values were determined based on the $14.50 market value of the Company’s common stock on September 30, 2013.

The total intrinsic value of options exercised during the nine months ended September 30, 2013 was $41,000. No options were exercised during the nine months ended September 30, 2012.

Standby Letters of Credit – A commercial bank issued standby letters of credit on behalf of the Company to the states of Texas and Kansas totaling $145,000 to allow the Company to do business in those states. The standby letters of credit are valid until cancelled or matured and are collateralized by the revolving credit facility with the bank. The terms of these letters of credit are extended for a term of one year at a time. The Company intends to renew the standby letters of credit for as long as the Company does business in the states of Texas and Kansas. No amounts have been drawn under the standby letters of credit.

Subsequent to September 30, 2013, the Company entered into a Joint Development Agreement, effective immediately, with Torchlight Energy Resources, Inc., to develop the Company’s existing Kansas leasehold, consisting of approximately 17,000 acres in Gray, Haskell and Finney counties. Pursuant to the Agreement, Ring will operate the Kansas leasehold acreage. In consideration of entering into the Agreement, Torchlight will pay 100% of all drilling and completion costs until an amount equal to Ring’s total costs related to the Kansas leases has been met (approximately $6.2 million). After Torchlight has matched Ring’s total costs related to the Kansas leases, Ring and Torchlight will equally share all drilling and development costs related to the continued ongoing development of the leases. Ring and Torchlight will share equally in any production and revenue in connection with the development of the Kansas leasehold acreage from the commencement of the first well pursuant to the terms of the Agreement.

We have audited the accompanying consolidated balance sheets of Ring Energy, Inc. and subsidiary (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for the year ended December 31, 2012 and for the eight months ended December 31, 2011. We have also audited the accompanying predecessor carve-out statements of operations, owners’ net investment (deficit), and cash flows of the Fisher I Property for the four months ended April 30, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Ring Energy, Inc. and subsidiary as of December 31, 2012 and 2011, and the results of their operations and their cash flows for the year ended December 31, 2012 and for the eight months ended December 31, 2011, and the predecessor carve-out financial statements of the Fisher I Property referred to above present fairly, in all material respects, the results of operations and the cash flows of the Fisher I Property for the four months ended April 30, 2011, in conformity with accounting principles generally accepted in the United States of America.

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

FOR THE EIGHT MONTHS ENDED DECEMBER 31, 2011 AND FOR THE YEAR ENDED DECEMBER 31, 2012

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

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

Reorganization into Ring Energy, Inc. – On June 28, 2012, Ring Energy, Inc. (“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 became a wholly-owned subsidiary of Ring. At the closing, the Stanford stockholders exchanged their 1,376 shares of Stanford Common Stock for 3,440,000 shares of Ring Common Stock. In addition, Ring assumed and adopted Stanford’s equity compensation plan and its outstanding options to purchase 450 shares of Stanford Common Stock, which represented the right to purchase 1,125,000 shares of Ring Common Stock at $2.00 per share. On February 6, 2012, the date the terms of the exchange agreement were agreed to and announced, Ring has 5,786,884 shares of Common Stock outstanding, of which Stanford stockholders held 793,317 shares. In addition, Stanford’s stockholders obtained the right to appoint to a majority of the members of the Ring board of directors and senior management of the combined company.

Under current accounting guidance, as a result of the number of shares and stock options to acquire shares issued to the Stanford stockholders and option holders, 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 1, 2011, 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, 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. Changes in Stanford’s stockholders’ equity for the four months ended April 30, 2011, on a post-split basis, were as follows:

Stanford’s cash flows during the four months ended April 30, 2011 were as follows:

Consolidation – The basis of presentation of the predecessor carve-out financial statements is presented above. Except for the predecessor carve-out financial statements, the accompanying consolidated financial statements include the accounts, operations and cash flows of Stanford for all periods presented and the consolidated operations and cash flows of Ring from June 28, 2012. All significant intercompany balances and transactions have been eliminated in consolidation.

Fair Values of Financial Instruments – The carrying amounts reported for the revolving line of credit approximates fair value because the underlying instruments are at interest rates which approximate current market rates. The derivative put options are carried at fair value.

Concentration of Credit Risk and Accounts Receivable – Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and accounts receivable. The Company has cash in excess of federally insured limits of $5,202,580 at December 31, 2012. The Company places its cash with a high credit quality financial institution.

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

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

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

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

All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves and estimated future costs to plug and abandon wells and costs of site restoration, less the estimated salvage value of equipment associated with the oil and gas properties, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent engineers. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. The following table shows total depletion and depletion per barrel-of-oil-equivalent rate, for the years ended December 31, 2012 and 2011.

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

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

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

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

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

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

Depreciation expense was $35,369 and $2,778 for the years ended December 31, 2012 and 2011, respectively.

Revenue recognition – The Company predominantly derives its revenue from the sale of produced crude oil and natural gas. Revenue is recorded in the month the product is delivered to the purchaser. At the end of each month, the Company estimates the amount of production delivered to purchasers and the price received. Variances between the Company’s estimated revenue and actual payment are recorded in the month the payment is received; however, differences have been insignificant.

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

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

Major Customers – During the year ended December 31, 2012, sales to three customers represented 50% 25% and 23% of total sales, respectively. At December 31, 2012, one of these customers made up 94% of accounts receivable. During the year ended December 31, 2011, sales to two customers represented 52% and 42% of total sales, respectively. At December 31, 2011, these customers made up 71% of accounts receivable. The loss of any of the foregoing customers would not have a material adverse effect on the Company as there is an available market for its crude oil and natural gas production from other purchasers.

Stock-Based Employee and Non-Employee Compensation – The Company has outstanding stock options to directors, employees and contract employees, which are described more fully in Note 8. The Company accounts for its stock options grants in accordance with generally accepted accounting principles. Generally accepted accounting principles require the recognition of the cost of employee services received in exchange for an award of equity instruments in the financial statements and is measured based on the grant date fair value of the award. Generally accepted accounting principles also requires stock option compensation expense to be recognized over the period during which an employee is required to provide service in exchange for the award (the vesting period).

Stock-based employee compensation incurred for the years ended December 31, 2012 and 2011 was $944,681 and $95,897, respectively.

Recently Adopted Accounting Pronouncement – In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” (“ASU 2011-04”), which clarifies the FASB’s intent regarding the application of existing fair value measurements and requires additional disclosure of information regarding valuation processes and inputs used. The new disclosure requirements, which are effective for interim and annual reporting periods beginning after December 15, 2011, were implemented by the Company in the first quarter of 2012. The implementation of ASU 2011-04 had no impact on the Company’s financial position or results of operations. See Note 5 for the Company’s fair value disclosures.

Recent Accounting Pronouncement Not Yet Adopted – In December 2011, the FASB issued Accounting Standards Update 2011-11, “Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”), and in January 2013 issued Accounting Standards Update 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” (“ASU 2013-01”). These updates require disclosures about the nature of an entity’s rights of offset and related arrangements associated with its recognized derivatives contracts. The guidance is effective for interim and annual periods beginning on or after January 1, 2013. As the additional requirements under ASU 2011-11 and ASU 2013-01, which will be implemented January 1, 2013, pertain to disclosures of offsetting assets and liabilities, no effect on the Company’s financial position or results of operations is expected.

Stock options to purchase 1,125,000 and 1,125,000 shares of Common Stock were excluded from the computation of diluted earnings (loss) per share during the year ended December 31, 2012 and 2011, respectively, as their effect would have been anti-dilutive.

Fisher I Property – On May 23, 2011, Stanford purchased proved developed and undeveloped oil and natural gas reserves (the “Fisher I Property”) located in the Permian Basin, Andrews County, Texas. The Fisher I Property acquired consisted of 100% of the working interest (75% net revenue interest) in four producing leases, a 99.6% working interest (74.7% net revenue interest) in 640 undeveloped acres and a 92.0% working interest (69.0% net revenue interest) in 960 undeveloped acres. The Fisher I Property was acquired for $2,296,228 of total consideration consisting of cash of $2,183,306, the transfer of 20,000 shares of Ring Energy, Inc. (“Ring”) Common Stock, valued at $2.00 per share or $40,000, and the issuance of a put option relating to the Ring shares valued at $72,922, whereby the holders could put the Ring shares back to Stanford for $5.00 per share through November 24, 2011.

For purposes of acquisition accounting, the fair value of the Ring shares transferred was determined based on the price stockholders of the Company paid to purchase the shares in May 2011 (See Note 11) since there was not an active market for the Ring shares. The value of the put option was determined using the Black-Scholes option pricing model based on the following assumptions: risk-free interest rate of 0.11%; expected life of 0.5 years; dividend yield of 0% and volatility of 207%. Stanford incurred $30,673 of acquisition-related costs, which have been included in general and administrative expense in the accompanying statement of income.

The acquisition qualified as a business combination and as such, Stanford recognized the assets acquired and the liabilities assumed at their fair values as of the May 23, 2011 acquisition date, which is the date the Company obtained control of the properties. Oil and natural gas sales receivable and production costs payable at May 23, 2011 were not material. The estimated fair value of these properties approximated the consideration paid, which the Company concluded approximated the fair value that would be paid by a typical market participant. As a result, neither goodwill nor a bargain purchase gain was recognized related to the acquisition. The following table summarizes the assets acquired and the liabilities assumed:

Oil and natural gas sales and income from operations before general and administrative expense from the Fisher I Property, included in the accompanying statement of operations for the eight months ended December 31, 2011, were $166,250 and $49,116, respectively.

Miocene Property – On August 17, 2011, Stanford purchased additional proved developed and undeveloped oil and natural gas reserves (the “Miocene Property”) located in the Permian Basin, Andrews County, Texas. The

Miocene Property consisted of 100% of the working interest (75% to 77% net revenue interest) in three producing leases. The Miocene Property was acquired for cash totaling $1,791,165. The Company incurred $98,984 of acquisition-related costs, which have been included in general and administrative expense in the accompanying statement of income.

The acquisition was recognized as a business combination whereby Stanford recorded the assets acquired and the liabilities assumed at their fair values as of August 17, 2011, which is the date the Company obtained control of the properties and was the acquisition date for financial reporting purposes. The estimated fair value of Miocene Property approximated the consideration paid, which the Company concluded approximated the fair value that would be paid by a typical market participant. The following table summarizes the fair values of the assets acquired and the liabilities assumed:

Oil and natural gas sales and income from operations before general and administrative expense from the Miocene Property, included in the accompanying statement of operations for the eight months ended December 31, 2011, were $217,959 and $60,313, respectively.

Fisher II Property – On December 1, 2011, the Company purchased proved developed and undeveloped oil and natural gas reserves (the “Fisher II Property”) located in the Permian Basin, Andrews County, Texas. The Fisher II Property acquired consisted of 100% of the working interest (75% net revenue interest) in one lease. The Fisher II Property was acquired for $1,747,760 of total consideration consisting of cash of $1,150,000, the transfer of 80,000 shares of Ring Common Stock, valued at $4.00 per share or $320,000, and the issuance of a put option relating to the Ring shares valued at $277,760, whereby the holder can put the Ring shares back to Stanford at $5.00 per share through December 1, 2012.

Due to the lack of an active market for the Ring shares, the fair value of the Ring shares transferred was determined based on the price at which Ring shares were being sold in a private placement active during the time period that this acquisition occurred. The value of the put option was determined using the Black-Scholes option pricing model based on the following assumptions: risk-free interest rate of 0.11%; expected life of 1.0 years; dividend yield of 0% and volatility of 198%. The Company incurred $6,898 of acquisition-related costs, which have been included in general and administrative expense in the accompanying statement of income.

The acquisition of the Fisher II Property was recognized as a business combination. Stanford recorded the assets acquired and the liabilities assumed at their fair values. The estimated fair value of the Fisher II Property approximated the consideration paid, which the Company concluded approximated the fair value that would be paid by a typical market participant. The following table summarizes the fair values of the assets acquired and the liabilities assumed:

Oil and natural gas sales and loss from operations before general and administrative expense from the Fisher II Property, included in the accompanying statement of operations for the eight months ended December 31, 2011, were $4,465 and $(7,416), respectively.

Ring Energy, Inc. – On June 28, 2012, Ring Energy, Inc. (“Ring”) completed the acquisition of Stanford Energy, Inc. through the closing of a stock-for-stock exchange agreement dated May 3, 2012. As a result, Stanford became a wholly-owned subsidiary of Ring. As further described in Note 1, Stanford was determined to be the accounting acquirer. The acquisition of Ring was recognized as the issuance by Stanford of the 6,579,808 common shares of Ring that remained outstanding. The Company incurred $87,181 of acquisition-related costs, which have been included in general and administrative expense in the accompanying statement of operations. The fair value of Ring’s net assets was more clearly determinable than the fair value of the common shares deemed issued; therefore, the common shares were valued at the fair value of the net assets acquired as follows:

There were no oil and natural gas sales or costs of operations before general and administrative expense from the properties acquired in the Ring Energy, Inc. transaction included in our operations for the year ended December 31, 2012.

Kansas Property – On September 1, 2012, Ring signed a letter of intent regarding the acquisition of two companies who collectively owned the mineral leases referred to as the Kansas Property. On November 19, 2012, Ring completed the acquisition of CRH Mississippi South Fund, an Oklahoma corporation (“CRH”) and Pontious Mississippi South Fund, an Oklahoma corporation (“Pontious”), through the closing of the Agreement and Plan of Merger dated November 7, 2012, with CRH, and its sole stockholder, and Pontious, and its sole stockholder (the “Merger Agreement”). As a result, CRH and Pontious were merged with and into Ring. Ring issued 312,500 common shares to each of those stockholders and paid an aggregate of $2,277,112 to them. The cash amount paid at closing was reduced by $42,888 from the amount set forth in the Merger Agreement because one of the target companies was not able to deliver a full 100% working interest in one of the leases held by it. Due to the lack of an active market for the Ring shares, the fair value of the Ring shares issued were valued at $4.50 per share based on the price at which Ring shares were being sold in a private placement offering during the time period that this acquisition occurred. To the extent of the common shares issued, the transaction was intended to be a nontaxable reorganization to the selling stockholders of CRH and Pontious. The Company incurred $22,225 of acquisition-related costs, which have been included in general and administrative expense in the accompanying statement of operations.

The acquisition of the Kansas Property was recognized as a business combination. Ring recorded the assets acquired and the liabilities assumed at their fair values. The estimated fair value of the Kansas Property approximated the consideration paid, which the Company concluded approximated the fair value that would be paid by a typical market participant. The following table summarizes the fair values of the assets acquired and the liabilities assumed:

Oil and natural gas sales and loss from operations before general and administrative expense from the Kansas Property, included in the accompanying statement of operations for the year ended December 31, 2012, were $3,766 and $(4,934), respectively.

Ogden Property – On September 28, 2012, the Company purchased proved developed and undeveloped oil and natural gas reserves (the “Ogden Property”) located in the Permian Basin, Andrews County, Texas. The Ogden Property consists of a 91.67% working interest, 68.75% net revenue interest in one lease covering 80 acres which included one existing well with production. The Ogden Property was acquired for $687,501 through the issuance of 152,778 shares of Ring Common Stock, valued at $4.50 per share. Due to the lack of an active market for the Ring shares, the fair value of the Ring shares transferred was determined based on the price at which Ring shares were being sold in a private placement active during the time period that this acquisition occurred.

The acquisition of the Ogden Property was recognized as a business combination. Ring recorded the assets acquired and the liabilities assumed at their fair values. The estimated fair value of the Ogden Property approximated the consideration paid, which the Company concluded approximated the fair value that would be paid by a typical market participant. The following table summarizes the fair values of the assets acquired and the liabilities assumed:

An analysis of significance was performed regarding this acquisition, based on the pro forma financial information published in connection with the Kansas Property acquisition referenced above. The operations of this acquisition are insignificant and it was determined that this acquisition was not material and therefore no pro forma information has been provided in relation to this acquisition.

Sunray Property – On October 30, 2012, the Company purchased proved developed and undeveloped oil and natural gas reserves (the “Sunray Property”) located in the Permian Basin, Andrews County, Texas. The Sunray Property consists of a total of 1,360 gross acres with working interest ownership ranging from 37.5% to 100%, net revenue interests ranging from 28.15% to 75%, including six existing wells with production and two additional wells that have the possibility of being put back into production. The Sunray Property was acquired for $1,994,943 of total consideration, consisting of a cash payment of $1,000,000 and the issuance of 220,000 shares of Ring Common Stock, valued at $4.50 per share. Due to the lack of an active market for the Ring shares, the fair value of the Ring shares transferred was determined based on the price at which Ring shares were being sold in a private placement offering during the time period that this acquisition occurred.

The acquisition of the Sunray Property was recognized as a business combination. Ring recorded the assets acquired and the liabilities assumed at their fair values. The estimated fair value of the Sunray Property approximated the consideration paid, which the Company concluded approximated the fair value that would be paid by a typical market participant. The following table summarizes the fair values of the assets acquired and the liabilities assumed:

Subsequent to the initial acquisition, we have leased additional interest in the acquired acreage. As of December 31, 2012 our working interest ownership ranges from 33% to 100% and our net revenue interest ownership ranges from 21% to 75%.

Results from Operations – The amount of the acquired properties’ revenue and losses included in the Company’s consolidated statements of operations for the year ended December 31, 2012, and the revenue and losses of the combined entity had the acquisition dates been January 1, 2011 are as follows.

The supplemental pro forma net loss for the year ended December 31, 2011 includes a nonrecurring $250,000 nonrefundable transaction fee from Ring Energy, Inc.

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

Notes Payable – In May 2011, the Company entered into a credit agreement with a bank that provides for a revolving line of credit of up to $10 million for borrowings and letters of credit. As of December 31, 2012, $9,950,000 was available to be drawn on the line of credit with the remainder being reserved by letters of credit to State regulatory agencies. The agreement includes a non-usage commitment fee of 0.20% per annum and covenants limiting other indebtedness, liens, transfer or sale of assets, distributions or dividends and merger or consolidation activity. The facility has 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%. As of December 31, 2012 the interest rate being charged was 4.00%. Subsequent to December 31, 2012 the note was extended to April 10, 2014. Two of the Company’s stockholders are jointly and severally obligated for outstanding borrowings under the credit facility.

As of December 31, 2011, the Company had received unsecured advances from Ring Energy, Inc. totaling $850,000 and had accrued interest payable thereon of $3,122. The advances were pursuant to an agreement

allowing for unsecured advances totaling $1,000,000 with an interest rate of 5.00% per annum. Borrowings outstanding are payable on January 31, 2013. As noted in Note 9, the advances were documented in a January 2012 promissory note. These advances were settled as part of the merger transaction between Ring and Stanford.

A reconciliation of the asset retirement obligation for the years ended December 31, 2011 and 2012 is as follows:

The Company is authorized to issue 75,000,000 common shares, with a par value of $0.001 per share. Subsequent to December 31, 2012, via stockholder consent, a majority of the stockholders increased the number of authorized Common Stock from 75,000,000 to 150,000,000 and also authorized 50,000,000 shares of Preferred Stock.

Reorganization into Ring Energy, Inc. – On June 28, 2012 Ring completed the acquisition of Stanford Energy, Inc. 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. This treatment results in 3,440,000 shares held by Stanford stockholders. As a result of the Stanford being determined to be the accounting acquirer, the transaction was accounted for as the issuance by Stanford of the 6,579,808 common shares of Ring that remained outstanding.

Common Stock Issued in Offerings – From July through October 2012, the Company issued 3,148,425 shares of Common Stock, valued at $14,167,913, or $4.50 per share, in a private placement. Proceeds from the offering totaled $13,009,062, net of offering costs and expenses paid of $1,158,851.

Common Stock Issued in Acquisitions – In October and December 2012, the Company issued a total of 997,778 shares of Common Stock, valued at $4,490,001 or $4.50 per share, in three separate oil and gas property acquisitions, as described in Note 3 above.

In 2011, the Company’s Board of Directors approved and adopted a long term incentive plan, which was subsequently approved and amended by the stockholders. There are 1,375,000 shares eligible for grant, either as options or as restricted stock, at December 31, 2012.

Employee Stock Options – Following is a table reflecting the issuances during 2011 and 2012 and their related exercise prices:

All granted options vest at the rate of 20% each year over five years beginning one year from the date granted and expire ten years from the grant date. A summary of the status of the stock options as of December 31, 2012 and changes during the years ended December 31, 2012 and 2011 is as follows:

As of December 31, 2012, there was approximately $1,424,531 of unrecognized compensation cost related to stock options that will be recognized over a weighted average period of 2.6 years. The aggregate intrinsic value of options vested and expected to vest at December 31, 2012 was $3,397,940. The aggregate intrinsic value of options exercisable at December 31, 2012 was $772,000. The year end intrinsic values are based on a December 31, 2012 closing price of $5.86.

The following table summarizes information related to the Company’s stock options outstanding at December 31, 2012:

Any excess tax benefits from the exercise of stock options will not be recognized in paid-in capital until the Company is in a current tax paying position. Presently, the company has a net loss and therefore not yet subject to income taxes. Accordingly, no excess tax benefits have been recognized for the years ended December 31, 2012 or 2011.

In May 2011, the Company entered into a credit agreement with a bank that provides for a revolving line of credit of up to $10 million for borrowings and letters of credit. Two of the Company’s stockholders are jointly and severally obligated for outstanding borrowings under the credit facility.

The company is leasing office space from a company that is owned by two of stockholders’ of the company.

During 2011, the Company received a $250,000 nonrefundable transaction fee from Ring Energy, Inc. pursuant to a pending stock exchange transaction between the two companies.

During 2011, the Company received advances totaling $850,000 from Ring Energy, Inc. pursuant to the same pending stock exchange transaction between the two companies. As noted in Note 4, the Company entered into a promissory note for $1,000,000 in January 2012 to cover this amount and amounts drawn subsequent to December 31, 2011.

Standby Letters of Credit – A commercial bank has issued standby letters of credit on behalf of the Company to the states of Texas and Kansas totaling $145,000 to allow the Company to do business in those states. The Company intends to renew the standby letters of credit for as long as the Company does business in those states. No amounts have been drawn under the standby letters of credit.

Operating leases – The following table summarizes our future estimated lease payments for periods subsequent to December 31, 2012. The leases pertain to approximately 3,000 square feet of space for our corporate headquarters in Midland, Texas, approximately 3,700 square feet of office space that we may relocate to in Midland, Texas, approximately 3,700 square feet of office space for our accounting offices in Tulsa, Oklahoma and approximately 2,000 square feet of office space for our field office in Andrews, Texas. The Company incurred lease expense of $208,091 and $0 for the years ended December 31, 2012 and 2011, respectively. The following table reflects the future minimum lease payments under the operating leases as of December 31, 2012.

Through December 31, 2011, Stanford Energy, Inc. and the predecessor were not taxable entities for U.S. federal income tax purposes. Under Stanford Energy, Inc.’s S-corporation election and the predecessor’s tax status, income taxes were generally borne by the stockholders/owners and losses were generally deductible at the stockholder/owner level. Accordingly, as of December 31, 2011, no recognition has been given to federal income tax or benefit in the accompanying financial statements.

For the year ended December 31, 2012, the Company calculated a net tax benefit of $300,324. The benefit from income taxes consisted of the following:

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

As of December 31, 2012, the Company had net operating loss carry forwards for federal income tax reporting purposes of approximately $5.6 million which, if unused, will expire in 2032.

The net deferred tax liability consisted of the following at December 31, 2012 and 2011:

Accounting for Uncertainty in Income Taxes – In accordance with generally accepted accounting principles, the Company has analyzed its filing positions in all jurisdictions where it is required to file income tax returns for the open tax years in such jurisdictions. The Company has identified its federal income tax return and its state income tax returns in Texas and Kansas in which it operates as “major” tax jurisdictions. The Company’s federal income tax returns for the years ended December 31, 2010 through 2012 remain subject to examination. The Company’s income tax returns in Kansas remain subject to examination for years ended December 31, 2010

through 2012. The Company’s income tax returns in Texas remain subject to examination for years ended 2009 through 2012. The Company currently believes that all significant filing positions are highly certain and that all of its significant income tax filing positions and deductions would be sustained upon audit. Therefore, the Company has no significant reserves for uncertain tax positions and no adjustments to such reserves were required by generally accepted accounting principles. No interest or penalties have been levied against the Company and none are anticipated; therefore, no interest or penalty has been included in our provision for income taxes in the consolidated statements of operations.

Stockholders of the Company purchased 100,000 shares of Ring Common Stock in May 2011 at $2.00 per share and contributed the shares to the Company. The stockholders purchased the Ring shares on behalf of the Company and the capital contribution was recognized at $200,000 based on the $2.00 price per share paid by the stockholders. The Company used 20,000 of the Ring shares as part of the consideration paid to purchase the Fisher I Property in May 2011. The remaining 80,000 Ring shares appreciated to $4.00 per share at December 1, 2011 when they were used as part of the consideration paid to purchase the Fisher II property. As a result, the Company realized a $160,000 gain on the available-for-sale securities.

The Company granted put options on the Ring shares transferred in connection with the acquisitions of oil and natural gas properties in May and December 2011. In May 2011, the Company granted 20,000 options with terms allowing the property seller to require the Company to repurchase the Ring shares at $5.00 per share through November 24, 2011. At the date of issuance, the fair value of this liability was $72,922 and was capitalized as part of the acquisition cost. In December 2011, the Company granted 80,000 options with terms allowing the property seller to require the Company to repurchase the Ring shares at $5.00 per share through December 1, 2012. At the date of issuance, the fair value of this liability was $277,760 and was capitalized as part of the acquisition cost. The put options are contingent consideration classified as liabilities under FASB ASC 305-30 and are recognized at the acquisition date fair value as part of the consideration transferred. They are remeasured to fair value at each reporting date until the contingency is resolved with the change in fair value being recognized in earnings. The put option issued in May 2011 expired unexercised prior to December 31, 2011 and therefore the full liability related to these options was recognized as a gain on change in fair value of put options. As of December 31, 2011, the fair value of the remaining liability was $276,736. These remaining put options expired unexercised prior to December 31, 2012 and therefore the full liability related to these options was recognized as a gain on change in fair value of put options. The following table illustrates the assumptions used in the Black-Scholes option pricing model at the measurement dates:

Generally accepted accounting principles establish a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The Company’s fair value measurements are based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:

In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.

The Company’s derivative put option liabilities are remeasured to fair value at each reporting date until the contingency is resolved. The fair value of the non-financial liabilities as of December 31, 2011 and 2012, was $276,736 and $0, respectively, and was calculated using Level 2 inputs. See Note 13 above for more information about this liability and the inputs used for calculating fair value.

Subsequent to December 31, 2012, the Company issued 100,000 shares per a subscription agreement allowing for the purchase of the restricted Common Stock at $4.50 per share.

Subsequent to December 31, 2012, the Company issued 6,722 shares of restricted Common Stock as the result of the cashless exercise of 10,000 options with an exercise price of $2.00 per share.

Subsequent to December 31, 2012, the Company accepted the resignations of certain management and Board of Director members and appointed new members to the Board of Directors and new management. Outgoing directors includes Denny W. Nestripke, Michael Harland and Robert Morley. New appointees to the Board include Kelly Hoffman, David A. Fowler, Anthony B. Petrelli and Clayton E. Woodrum. Mr. Lloyd T. Rochford was appointed as the new Chairman of the Board. Outgoing management consisted of Denny W. Nestripke and incoming management included Kelly Hoffman as Chief Executive Officer, David A. Fowler as President, William R. Broaddrick as Chief Financial Officer, Corporate Secretary and Treasurer and Daniel D. Wilson as Vice President of Operations.

Subsequent to December 31, 2012, via stockholder consent, a majority of the stockholders increased the number of authorized shares of Common Stock from 75,000,000 to 150,000,000 and also authorized 50,000,000 shares of Preferred Stock, $0.001 par value.

Subsequent to December 31, 2012, via stockholder consent, a majority of the stockholders approved an increase in the number of authorized shares in the Company’s Long Term Incentive Plan from 2,500,000 to 5,000,000.

Subsequent to December 31, 2012, the Company granted 1,400,000 options with exercise prices of $4.50 per share and 150,000 options with exercise prices of $5.50 per share to contractors, employees and directors.

We have evaluated subsequent events after the balance sheet date of December 31, 2012 through the time of filing with the SEC on April 1, 2013, which is the date the financial statements were issued.

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

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

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

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


	Per Share		Total
Price to public	$	10.00	$	50,000,000
Discounts and commissions to underwriters⁽¹⁾		0.50		2,500,000
Net proceeds (before expenses) to us		9.50		47,500,000


Public offering price per share	$	10.00
Net tangible book value per share as of September 30, 2013	$	2.57
Increase in net tangible book value per share attributable to the offering	$	1.51
Pro forma net tangible book value per share as of September 30, 2013, after giving effect to the offering	$	4.08
Dilution per share to new investors in the offering	$	5.92


Geographic Area	Oil (Bbl)		Natural Gas (Mcf)		Total (Boe)		Pre-Tax PV10 Value		Standardized Measure of Discounted Future Net Cash Flows
Texas		3,544,810		1,710,690		3,829,925		103,806,020		69,670,682
Kansas		101,933		23,090		105,781		2,232,374		1,687,764

Total		3,646,743		1,733,780		3,935,706	$	106,038,394	$	71,358,446


	Oil (Bbls)			Natural Gas (Mcf)
Balance, December 31, 2010		68,036			—
Purchase of minerals in place		910,839			448,681
Improved recovery		1,143,998			360,453
Production		(5,297	)		(2,369	)
Revisions of estimates		375,984			942,335

Balance, December 31, 2011		2,493,560			1,749,100
Purchase of minerals in place		780,669			430,800
Improved recovery		149,149			30,250
Production		(20,531	)		(6,480	)
Revisions of estimates		243,896			(469,890	)

Balance, December 31, 2012		3,646,743			1,733,780


	For the Years Ended December 31,
	2011		2012
Oil (Bbls)
Developed		414,350		812,000
Undeveloped		2,079,210		2,834,743

Total		2,493,560		3,646,743

Natural Gas (Mcf)
Developed		75,330		94,090
Undeveloped		1,673,770		1,639,690

Total		1,749,100		1,733,780

Total (Boe)
Developed		426,905		827,682
Undeveloped		2,358,172		3,108,025

Total		2,785,077		3,935,707


PROSPECTUS SUMMARY			1
RISK FACTORS			7
CAUTIONARY STATEMENT REGARDING FORWARD–LOOKING STATEMENTS			19
USE OF PROCEEDS			21
DILUTION			22
DESCRIPTION OF CAPITAL STOCK			23
DIVIDEND POLICY			25
ABOUT THE COMPANY			26
PROPERTIES			35
MANAGEMENT			44
EXECUTIVE COMPENSATION			48
MARKET PRICE AND DIVIDENDS ON REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS			55
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			57
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING METHODS AND FINANCIAL DISCLOSURE			65
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS			66
TRANSACTIONS WITH RELATED PERSONS, PROMOTERS AND CERTAIN CONTROL PERSONS			67
DISCLOSURE OF COMMISSION POSITION ON INDEMNIFICATION OF SECURITIES ACT LIABILITIES			68
UNDERWRITING			69
LEGAL MATTERS			74
EXPERTS			74
WHERE YOU CAN FIND MORE INFORMATION			75
GLOSSARY OF OIL AND NATURAL GAS TERMS			A-1
FINANCIAL STATEMENTS			F-1


*December 31,*	2012			2011
Future cash flows	$	331,489,046		$	237,949,800
Future production costs		(73,667,753	)		(43,060,810	)
Future development costs		(66,835,270	)		(48,146,550	)
Future income taxes		(62,412,466	)		(49,835,277	)

Future net cash flows		128,573,557			96,907,163
10% annual discount for estimated timing of cash flows		(57,215,111	)		(36,151,588	)

Standardized Measure of Discounted Cash Flows	$	71,358,446		$	60,755,575


	2012			2011
Beginning of the year	$	60,755,575		$	939,994
Purchase of minerals in place		19,027,746			32,785,800
Extensions, discoveries and improved recovery, less related costs		6,279,507			38,981,734
Development costs incurred during the year		6,532,898			317,042
Sales of oil and gas produced, net of production costs		(972,881	)		(219,617	)
Accretion of discount		6,524,980			68,517
Net changes in price and production costs		(8,004,160	)		18,810,992
Net change in estimated future development costs		(2,968,626	)		(1,832,496	)
Revision of previous quantity estimates		6,364,907			7,376,116
Revision of estimated timing of cash flows		(19,303,858	)		(5,720,962	)
Net change in income taxes		(2,877,642	)		(30,751,545	)

End of the Year	$	71,358,446		$	60,755,575


	Oil (Bbl)		Gas (Mcf)		Total (Boe)		% of Total Proved			Pre-tax PV10 (In thousands)		Standardized Measure of Discounted Future Net Cash Flows (In thousands)		Future Capital Expenditures (In thousands)
Texas:
PDP		364,110		40,750		370,902		9	%	$	11,516	$	7,729	$	—
PDNP		447,890		30,250		452,932		12	%		18,273		12,264		2,948
PUD		2,732,810		1,639,690		3,006,092		76	%		74,017		49,677		61,892

Total Proved:		3,544,810		1,710,690		3,829,926		97	%	$	103,806	$	69,670	$	64,840

Kansas:
PDP		—		23,090		3,848		0	%	$	23	$	17	$	—
PUD		101,933		—		101,933		3	%		2,209		1,671		1,995

Total Proved:		101,933		23,090		105,781		3	%	$	2,232	$	1,688	$	1,995

Total:
PDP		364,110		63,840		374,750		10	%	$	11,539	$	7,746	$	—
PDNP		447,890		30,250		452,932		12	%		18,273		12,264		2,948
PUD		2,834,743		1,639,690		3,108,025		78	%		76,226		51,348		63,887

Total Proved:		3,646,743		1,733,780		3,935,707		100	%	$	106,038	$	71,358	$	66,835


Year	Estimated Oil Reserves Developed (Bbls)		Estimated Gas Reserves Developed (Mcf)		Total Boe		Estimated Development Costs
2013		1,563,303		638,340		1,669,693		22,642,810
2014		1,719,330		1,031,600		1,891,263		44,192,460

		3,282,633		1,669,940		3,560,956	$	66,835,270


State	Average Daily Production			Oil			Natural Gas
Texas		91.75	%		100.00	%		15.96	%
Kansas		8.25	%		0.00	%		84.04	%

Total		100.00	%		100.00	%		100.00	%


	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
Texas		1,560		1,517		3,333		2,333		4,893		3,851
Kansas		1,280		1,024		9,862		8,030		11,142		9,054

Total		2,840		2,541		13,195		10,363		16,035		12,904


	Year Ended December 31,
	2010		2011		2012
Oil production (Bbls)		3,695		5,297		20,531
Natural gas production (Mcf)		—		2,369		6,480
Total production (Boe)		3,695		5,692		21,611
Daily production (Boe/d)		10		16		59
Average sales price:
Oil (per Bbl)	$	75.24	$	88.50	$	84.50
Natural gas (per Mcf)		—		7.11		3.50
Total (per Boe)		75.24		85.32		81.39
Average production cost (per Boe)	$	34.13	$	43.04	$	36.37
Average production taxes (per Boe)		3.47		4.02		3.84


	Oil Wells				Gas wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Texas		43		32		—		—		43		32
Kansas		3		2		9		7		12		9

Total		46		34		9		7		55		41


	For the Year Ended December 31,
	2010		2011		2012
Acquisition of proved properties	$	—	$	6,280,391	$	9,873,128
Acquisition of unproved properties		—		—		—
Exploration costs		—		—		—
Development costs		—		317,042		6,581,343

Total Costs Incurred	$	—	$	6,597,433	$	16,454,471


Capital One Securities		Global Hunter Securities


Euro Pacific Capital


		IBERIA Capital Partners L.L.C.


				Noble Financial Capital Markets


Name	Age		Position
Kelly Hoffman		55	Chief Executive Officer, Director
David A. Fowler		54	President, Director
Daniel D. Wilson		51	Vice President of Operations
William R. Broaddrick		35	Chief Financial Officer
Lloyd T. Rochford		66	Chairman of the Board of Directors
Stanley M. McCabe		80	Director
Anthony B. Petrelli		60	Director
Clayton E. Woodrum		72	Director


Compensation Element		Compensation Objectives Attempted to be Achieved
Base Salary		Attract and retain qualified executives; Motivate and reward executives’ performance.

Bonus Compensation		Motivate and reward executive’s performance; Enhance profitability of Company and stockholder value.

Equity-Based Compensation – stock options and restricted stock grants		Enhance profitability of Company and stockholder value by aligning long-term incentives with stockholders’ long-term interests.


Name and Principal Position	Year		Salary⁽¹⁾ ($)		Bonus ($)		Option Awards⁽²⁾ ($)		All Other Compensation⁽³⁾ ($)		Total ($)
William R. Broaddrick,		2012		108,333		3,000		213,711		—		325,044
Chief Financial Officer and Interim Chief Executive Officer		2011		—		—		232,156		—		232,156

Robert S. Owens,		2012		—		—		—		2,000		2,000
Chief Executive Officer⁽⁴⁾ through August 31, 2012		2011		—		—		—		3,000		3,000


Name and Principal Position	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable		Options Exercise Price ($)		Option Expiration Date
William R. Broaddrick		20,000		80,000		2.00		12/01/21
		—		50,000		4.50		09/01/22


	October 1, 2012			September 1, 2012			July 1, 2012			December 1, 2011
Risk free interest rate		0.25	%		0.80	%		0.67	%		0.97	%
Expected life (years)		5.75			6.5			6.5			6.5
Dividend yield		—			—			—			—
Volatility		147	%		153	%		158	%		32	%


Name	Fees Earned or Paid in Cash ($)		Total ($)
Lloyd T. Rochford		—		—
Stanley M. McCabe		—		—
Denny Nestripke		12,000		12,000
Michael Harland		—		—
Robert Morley		—		—


	Number of securities to be issued upon exercise of outstanding options		Weighted- average exercise price of outstanding options		Number of securities remaining available for future issuance under compensation plans (excluding securities in column (a))
	(a)		(b)
Equity compensation plans approved by security holders		—		—		—
None
Equity compensation plans not approved by security holders		1,125,000	$	2.37		1,375,000
Ring Energy, Inc. Long Term Incentive Plan

Total		1,125,000	$	2.37		1,375,000


Period	High Bid		Low Bid
1st Quarter 2011	$	4.30	$	1.75
2nd Quarter 2011		12.20		4.51
3rd Quarter 2011		4.75		4.00
4th Quarter 2011		4.50		2.26

1st Quarter 2012	$	5.10	$	4.01
2nd Quarter 2012		7.50		4.25
3rd Quarter 2012		7.00		5.12
4th Quarter 2012		7.00		5.82

1st Quarter 2013	$	11.00	$	5.74
2nd Quarter 2013		8.76		6.60
3rd Quarter 2013 (through August 31)		15.75		8.65


Period	High Sale		Low Sale
3rd Quarter 2013 (September 1 – September 30)	$	14.85	$	13.50
4th Quarter 2013 (through December 5)	$	14.50		11.17


Year	Lease Obligation ($)
2013		138,897
2014		117,465
2015		71,325
2016		73,185
2017		55,935

	$	456,807


	Shares of Common Stock Beneficially Owned
Name	Number			Percent
Kelly Hoffman		204,546	⁽¹⁾		1	%
David A. Fowler		317,712	⁽²⁾		2	%
Daniel D. Wilson		170,000	⁽³⁾		1	%
William R. Broaddrick		100,000	⁽⁴⁾		1	%
Lloyd T. Rochford		2,484,667	⁽⁵⁾		14	%
Stanley M. McCabe		2,236,502	⁽⁶⁾		13	%
Anthony B. Petrelli		80,000	⁽⁷⁾		*
Clayton E. Woodrum		62,723	⁽⁸⁾		*
Robert S. Owens		0			*

All directors and executive officers as a group (9 persons)		5,656,150	⁽⁹⁾		32	%


Underwriters	Number of Shares
SunTrust Robinson Humphrey, Inc.		2,500,000
Capital One Securities, Inc.		750,000
Global Hunter Securities, LLC		750,000
Euro Pacific Capital Inc.		200,000
IBERIA Capital Partners L.L.C.		200,000
Noble Financial Capital Markets		200,000
Northland Securities, Inc.		200,000
Roth Capital Partners, LLC		200,000

Total		5,000,000


	Per Share				Total
	With No Exercise		With Full Exercise		With No Exercise		With Full Exercise

Underwriting Discounts and Commissions	$	0.50	$	0.50	$	2,500,000	$	2,875,000


Unaudited Condensed Consolidated Financial Statements

Unaudited Condensed Consolidated Balance Sheet as of September 30, 2013			F-2

Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2013			F-3

Unaudited Condensed Consolidated Statement of Cash Flows for the nine months ended September 30, 2013			F-4

Notes to Unaudited Condensed Consolidated Financial Statements			F-5

Audited Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm			F-11

Consolidated Balance Sheets as of December 31, 2012 and 2011			F-12

Condensed Statements of Operations for the years ended December 31, 2012 and 2011			F-13

Condensed Statements of Stockholders Equity for the years ended December 31, 2012 and 2011			F-14

Consolidated Statements of Cash Flows for the years ended December 31, 2012 and 2011			F-15

Notes to Consolidated Financial Statements			F-16

Supplemental Information on Oil and Gas Producing Activities			F-31


	September 30, 2013			December 31, 2012
ASSETS
Current Assets
Cash	$	7,867,616		$	5,404,167
Accounts receivable		1,722,322			417,965
Prepaid expenses and retainers		68,567			60,398

Total Current Assets		9,658,505			5,882,530

Properties and Equipment
Oil and natural gas properties subject to amortization		45,055,587			23,051,904
Office equipment		257,911			175,106

Total Properties and Equipment		45,313,498			23,227,010

Accumulated depreciation, depletion and amortization		(2,253,548	)		(596,162	)
Net Properties and Equipment		43,059,950			22,630,848

Total Assets	$	52,718,455		$	28,513,378

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	5,248,034		$	1,191,431

Total Current Liabilities		5,248,034			1,191,431

Noncurrent Liabilities
Deferred income taxes		625,950			625,950
Asset retirement obligation		1,054,998			496,286

Total Noncurrent Liabilities		1,680,948			1,122,236

Stockholders’ Equity
Preferred stock – $0.001 par value; 50,000,000 shares authorized; no shares issued or outstanding		—			—
Common stock – $0.001 par value; 150,000,000 shares authorized; 17,801,313 shares and 14,166,011 shares outstanding, respectively		17,801			14,166
Additional paid-in capital		53,742,656			32,169,363
Accumulated deficit		(7,970,984	)		(5,983,818	)

Total Stockholders’ Equity		45,789,473			26,199,711

Total Liabilities and Stockholders’ Equity	$	52,718,455		$	28,513,378


	For The Three Months Ended September 30,						For The Nine Months Ended September 30,
	2013			2012			2013			2012
Oil and Gas Revenues	$	2,820,731		$	374,739		$	5,264,267		$	1,045,264

Costs and Operating Expenses
Oil and gas production costs		291,182			216,908			646,905			592,163
Oil and gas production taxes		130,944			17,296			243,620			49,921
Depreciation, depletion and amortization		917,116			117,267			1,657,386			293,102
Accretion expense		13,906			4,763			37,183			14,287
General and administrative expense		1,611,318			671,438			4,678,581			1,825,937

Total Costs and Operating Expenses		2,964,466			1,027,672			7,263,675			2,775,410

Other Income (Expense)
Gain on derivative put options		—			53,224			—			146,632
Interest income		12,242			2,248			12,242			2,248
Interest expense		—			(33,992	)		—			(221,838	)

Net Other Expense		12,242			21,480			12,242			(72,958	)

Net Loss	$	(131,493	)	$	(631,453	)	$	(1,987,166	)	$	(1,803,104	)

Basic Loss per Share	$	(0.01	)	$	(0.06	)	$	(0.13	)	$	(0.29	)
Diluted Loss per Share	$	(0.01	)	$	(0.06	)	$	(0.13	)	$	(0.29	)


*For the Nine Months Ended September 30,*	2013			2012
Cash Flows From Operating Activities
Net loss	$	(1,987,166	)	$	(1,803,104	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		1,657,386			293,102
Accretion expense		37,183			14,287
Share-based compensation		2,598,046			707,090
Gain on derivative put options		—			(146,632	)
Changes in assets and liabilities:
Accounts receivable		(1,304,357	)		(39,794	)
Prepaid expenses		(8,169	)		27,537
Accounts payable		4,056,603			1,558,156
Accrued compensation		—			(100,000	)

Net Cash Provided by Operating Activities		5,049,526			510,642

Cash Flows from Investing Activities
Payments to purchase oil and natural gas properties		(4,125,676	)		(124,050	)
Payments to develop oil and natural gas properties		(17,356,478	)		(4,711,752	)
Purchase of office equipment		(82,805	)		(179,078	)

Net Cash Used in Investing Activities		(21,564,959	)		(5,014,880	)

Cash Flows From Financing Activities
Proceeds from borrowings from Ring Energy, Inc.		—			1,150,000
Proceeds from issuance of common stock		18,978,882			11,545,983
Proceeds from issuance of common stock to Ring Energy, Inc. shareholders		—			10,887,561
Principal payments on revolving line of credit		—			(9,244,428	)

Net Cash Provided by Financing Activities		18,978,882			14,339,116

Net Increase in Cash		2,463,449			9,834,878
Cash at Beginning of Period		5,404,167			11,372

Cash at End of Period	$	7,867,616		$	9,846,250

Supplemental Cash Flow Information
Cash paid for interest	$	—		$	93,471

Noncash Investing and Financing Activities
Oil and gas properties acquired	$	—		$	825,765
Revision of asset retirement obligation estimate		211,691			—
Asset retirement obligation incurred during development		309,838			(14,214	)
Payments with Ring Energy, Inc. shares		—			(687,501	)

Issuance of common stock to Ring Energy, Inc. shareholders	$	—		$	13,095,369
Accounts payable assumed		—			9,893
Less: Elimination of note payable to Ring Energy, Inc.		—			(2,003,122	)
Less: Prepaid expenses acquired		—			(26,942	)
Less: Property and equipment acquired		—			(187,637	)

Proceeds from issuance of common stock to Ring Energy, Inc. shareholders	$	—		$	10,887,561


	For The Three Months Ended September 30,						For The Nine Months Ended September 30,
	2013			2012			2013			2012
Net Loss	$	(131,493	)	$	(631,453	)	$	(1,987,166	)	$	(1,803,104	)

Basic Weighted-Average Shares Outstanding		17,801,313			11,433,730			15,473,339			6,172,504
Effect of dilutive securities:
Stock options		—			—			—			—

Diluted Weighted-Average Shares Outstanding		17,801,313			11,433,730			15,473,339			6,172,504

Basic Loss per Share	$	(0.01	)	$	(0.06	)	$	(0.13	)	$	(0.29	)
Diluted Loss per Share	$	(0.01	)	$	(0.06	)	$	(0.13	)	$	(0.29	)


Balance, December 31, 2012	$	496,286
Revision of estimate		211,691
Liabilities incurred		309,838
Accretion expense		37,183

Balance, September 30, 2013	$	1,054,998


Expected volatility	128% - 138	%
Weighted-average volatility	137	%
Expected dividends	0
Expected term (in years)	6.5
Risk-free interest rate	0.76% - 1.49	%