UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

[ X ] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2014

Or

[   ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITES EXCHANGE
ACT OF 1934

For the transition period from ___________to ___________

Commission file number 001-36057

RING ENERGY, INC.
(Exact Name of registrant as specified in its charter)

Nevada
(State or other jurisdiction of incorporation or organization)

98-0406406
(IRS Employer Identification No.)

901 West Wall St. 3rd Floor
Midland, TX
(Address of principal executive offices)

79702
(Zip Code)

(432) 682-7464
(Registrant’s telephone number, including area code)


 

Securities registered under Section 12(b) of the Exchange Act: None

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [  ] No [ X ]

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

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [  ] 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [ X ] No [  ] 

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer [  ]                                                          Accelerated filer [ X ]
Non-accelerated filer [  ] (Do not check if a smaller reporting company) Smaller reporting company [  ]

Indicate by check mark whether the registrant is shell company (as defined in Rule 12b-2 of the Act). Yes [  ]   No [ X ]

As of June 30, 2014, the aggregate market value of the common voting stock held by non-affiliates of the issuer, based upon the closing stock price of $17.45 per share, was approximately $360,171,071.

As of March 10, 2015, the issuer had outstanding 25,747,582 shares of common stock ($0.001 par value).


TABLE OF CONTENTS
PART I 2
   Item 1:   Business
8
   Item 1A. Risk Factors 16
   Item 1B: Unresolved Staff Comments 17
   Item 2:   Properties 17
   Item 3:   Legal Proceedings 26
   Item 4:   Mine safety disclosures 26
PART II 28
   Item 5:   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer                 Purchases of Equity Securities 28
   Item 6:   Selected Financial Data 33
   Item 7:   Management’s Discussion and Analysis of Financial Condition and Results
                of Operations
35
   Item 7A  Quantitative and Qualitative Disclosures About Market Risk 43
   Item 8:   Financial Statements and Supplementary Data 44
   Item 9:   Changes in and Disagreements with Accountants and Accounting and
                Financial Disclosure
44
   Item 9A: Controls and Procedures 44
   Item 9B: Other Information 45
PART III 46
   Item 10: Directors, Executive Officers and Corporate Governance 46
   Item 11: Executive Compensation 50
   Item 12: Security Ownership of Certain Beneficial Owners and Management
                and Related Stockholder Matters
56
   Item 13: Certain Relationships and Related Transactions, and Director Independence 58
   Item 14: Principal Accounting Fees and Services 58
PART IV 59
   Item 15: Exhibits, Financial Statement Schedules 59
SIGNATURES 62
 
    1    

Forward Looking Statements

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

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


PART I

Item 1: Business

General

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

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

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

Production for the year ended December, 2014, was approximately 463,495 BOE, as compared to production of 115,681 BOE for the year ended December 2013, a 300% increase in BOE. The stated production amount reflects only the oil and gas that was produced and shipped prior to the end of the fourth quarter. Any oil and gas produced in the fourth quarter but still held on site after December 31, 2014, will be credited in the first quarter of 2015.
    2    

Ring believes that there is significant value to be created by drilling the identified undeveloped opportunities on its Texas properties. As of December 31, 2014, Ring owned interests in a total of 5,835 gross (5,129 net) developed acres and 23,903 gross (12,141 net) undeveloped acres in Texas. The Company has 239 identified proven vertical drilling locations based on the reserve report as of December 31, 2014, and an additional 2,480 identified potential vertical drilling locations based on 10-acre downspacing. Ring intends to grow its reserves and production through development, drilling, exploitation and exploration activities on this multi-year project inventory of identified potential drilling locations and through acquisitions that meet the Company’s strategic and financial objectives, targeting oil-weighted reserves. Ring has identified 24 wells that are suitable candidates for re-stimulation, providing attractive returns with lower upfront costs. Ring has temporarily stopped drilling activity in Kansas pending the completion of an extensive 3-D evaluation.

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

Ring Energy’s Business Strategy and Development

• 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. Ring’s portfolio of proved oil and natural gas reserves consists of 98% oil and 2% natural gas. Of those reserves, 35% of the proved reserves are classified as proved developed producing, or “PDP,” 8% are classified as proved developed non-producing, or “PDNP,” and approximately 57% are classified as proved undeveloped, or “PUD.” 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.

Through December 31, 2014, we increased our proved reserves to approximately 10.4 million BOE (barrel of oil equivalent). As of December 31, 2014, our estimated proved reserves had a pre-tax “PV10” (present value of future net revenues before income taxes discounted at 10%) of approximately $281.7 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $196.3 million. The difference between these two amounts is the effect of income taxes. The Company presents the pre-tax PV10 value, which is a non-GAAP financial measure, because it is a widely used industry standard which we believe is useful to those who may review this Annual Report when comparing our asset base and performance to other comparable oil and gas exploration and production companies. We spent approximately $143.0 million on acquisitions and capital projects during 2013 and 2014, and we intend to continually actively drill and develop our acreage in an effort to maximize shareholder value.

• 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, Ring 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.
    3    

• 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

• 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 in the heart of the Central Basin Platform. The Central Basin Platform is a NW-SE trending uplifted basement block that separates the Midland Basin (to the east) from the Delaware Basin (to the west). As of December 31, 2014, Ring has drilled 180 wells on its acreage and re-stimulated 27 existing wells. As of December 31, 2014, estimated net proved reserves were comprised of approximately 98% oil and 2% natural gas.

• De-risked Permian acreage position with multi-year vertical drilling inventory. As of December 31, 2014, Ring has drilled 180 gross operated wells across its leasehold position with a 100% success rate. The Company has also re-stimulated 27 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, 2014, Ring has 239 identified proven vertical drilling locations in its proved undeveloped reserves. It believes it has an additional 2,480 potential locations based on 10-acre downspacing. 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.

• 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, Lloyd T. Rochford, and Director, Stanley M. McCabe, formed Arena Resources, Inc. (“Arena”) in 2001, which operated in the same proximate area as Ring’s Andrews and Gaines County acreage. Arena eventually sold to SandRidge Energy, Inc., in July 2010 for $1.6 billion. Ring’s management team aims to execute a similar growth strategy and development plan by leveraging its industry relationships and significant operational experience in these regions.

• Concentrated acreage position with high degree of operational control. Ring operates approximately 99% 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.
    4    

Competitive Business Conditions

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

The actual price range of crude oil is largely established by major crude oil purchasers and commodities trading. Pricing for natural gas is based on regional supply and demand conditions. To this extent we believe we receive oil and gas prices comparable to other producers. There is little risk in our ability to sell all our current production at current prices with a reasonable profit margin. The risk of domestic overproduction at current prices is not deemed significant. We view our primary pricing risk to be related to a potential decline in prices to a level which could render our current production uneconomical.

We are presently committed to use the services of the existing gathering systems of the companies that purchase our natural gas production. This commitment is tied to existing natural gas purchase contracts associated with our production This commitment potentially gives such gathering companies certain short-term relative monopolistic powers to set gathering and transportation costs, because obtaining the services of an alternative gathering company would require substantial additional costs (since an alternative gathering company would be required to lay new pipeline and/or obtain new rights of way to any lease from which we are selling production). We are not subject to third party gathering systems for our oil production. Some of our oil production is sold through a third party pipeline which has no regional competition. All other oil production is transported by the oil purchaser by trucks with competitive trucking costs in the area.

Major Customers

We principally sell our oil and natural gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities. In areas where there is no practical access to pipelines, oil is trucked to storage facilities. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For the fiscal year 2014, sales to two customers, HollyFrontier Refining and Marketing (“HollyFrontier”) and Plains Marketing LP (“Plains”) represented 75% and 18%, respectively, of oil and gas revenues. At December 31, 2014, HollyFrontier represented 45% of our accounts receivable and Plains represented 37%. However, we believe that the loss of these customers would not materially impact our business because we could readily find other purchasers for our oil and gas produced.

Delivery Commitments


As of December 31, 2014, we were not committed to providing a fixed quantity of oil or gas under any existing contracts.

Governmental Regulations

Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability.
    5    

Regulation of Drilling and Production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

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

Regulation of Transportation of Oil

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

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

Regulation of Transportation and Sale of Natural Gas

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

Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Therefore, we cannot provide any assurance that the less stringent regulatory approach established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.
    6    

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

Environmental Compliance and Risks

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

In Texas and Kansas specific oil and gas regulations apply to the drilling, completion and operations of wells, and the disposal of waste oil and salt water. There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency.

At the federal level, among the more significant laws and regulations that may affect our business and the oil and gas industry are: The Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as “CERCLA” or “Superfund; the Oil Pollution Act of 1990; the Resource Conservation and Recovery Act, also known as “RCRA,”; the Clean Air Act; Federal Water Pollution Control Act of 1972, or the Clean Water Act; and the Safe Drinking Water Act of 1974.
Compliance with these regulations may constitute a significant cost and effort for us. No specific accounting for environmental compliance has been maintained or projected by us at this time. We are not presently aware of any environmental demands, claims, or adverse actions, litigation or administrative proceedings in which either we or our acquired properties are involved in or subject to, or arising out of any predecessor operations.

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

Operational Hazards and Insurance

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

In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed.
    7    

Current Employees

As of December 31, 2014, we had twenty-two full-time employees. Our employees are not represented by any labor union. We consider our relations with our employees to be satisfactory and have never experienced a work stoppage or strike.

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

Seasonal Nature of Business

Generally, the demand for oil and natural gas fluctuates depending on the time of year. Seasonal anomalies such as mild winters or hot summers may sometimes lessen this fluctuation. Further, pipelines, utilities, local distribution companies, and industrial end users utilize oil and natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand.

Financial Information

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

Item 1A: Risk Factors

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

Risks Relating to the Oil and Natural Gas Industry and Our Business

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

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

• changes in global supply and demand for oil and natural gas;
• the actions of the Organization of Petroleum Exporting Countries, or OPEC;
• the price and quantity of imports of foreign oil and natural gas;
• political conditions, including embargoes, in or affecting other oil-producing activity;
• the level of global oil and natural gas exploration and production activity;
• the level of global oil and natural gas inventories;
• weather conditions;
• technological advances affecting energy consumption; and
• the price and availability of alternative fuels.
    8    

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. Lower prices will also negatively impact the value of our proved reserves. A substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

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

Because a substantial percentage of our proven properties are proved undeveloped (approximately 57%) or proved developed non-producing (approximately 8%), we will require significant additional capital to develop such properties before they may become productive. Further, because of the inherent uncertainties associated with drilling for oil and gas, some of these properties may never be developed to the extent that they result in positive cash flow. Even if we are successful in our development efforts, it could take several years for a significant portion of our undeveloped properties to be converted to positive cash flow.

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

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

Our future success will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control; including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Please read “—Reserve estimates depend on many assumptions that may turn out to be inaccurate” (below) for a discussion of the uncertainty involved in these processes. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following:

• delays imposed by or resulting from compliance with regulatory requirements;
• pressure or irregularities in geological formations;
• shortages of or delays in obtaining equipment and qualified personnel;
• equipment failures or accidents;
• adverse weather conditions;
• reductions in oil and natural gas prices;
• title problems; and
• limitations in the market for oil and natural gas.

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

    9    

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

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

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

Decreases in oil and natural gas prices may require us to take write-downs of the carrying values of our oil and natural gas properties, potentially requiring earlier than anticipated debt repayment and negatively impacting the trading value of our securities.

Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. Because our properties serve as collateral for advances under our existing credit facility, a write-down in the carrying values of our properties could require us to repay any outstanding debt earlier than we would otherwise be required. A write-down could also constitute a non-cash charge to earnings. It is likely the cumulative effect of a write-down could also negatively impact the trading price of our securities.

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

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

In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.
    10    

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

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

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Our prospects are in various stages of evaluation, ranging from prospects that are currently being drilled, to prospects that will require substantial additional seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. This risk may be enhanced in our situation, due to the fact that a significant percentage (57%) of our proved reserves is currently proved undeveloped reserves. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

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

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

• environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;
• abnormally pressured formations;
• mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
• vfires and explosions;
• personal injuries and death; and
• natural disasters.
    11    

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 (72%) of our proved reserves is currently proved undeveloped reserves. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

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

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

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

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

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

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

• discharge permits for drilling operations;
• drilling bonds;
• reports concerning operations;
• the spacing of wells;
• unitization and pooling of properties; and
• taxation.
    12    

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

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

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

• discharge permits for drilling operations;
• drilling bonds;
• reports concerning operations;
• the spacing of wells;
• unitization and pooling of properties; and
• taxation.

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

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

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

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

We have a credit facility in place with a $40 million borrowing base borrowings and letters of credit. As of December 31, 2014, no amount was outstanding on our credit facility. If in the future we utilize this facility, the level of our indebtedness could affect our operations in several ways, including the following:
    13    

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

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

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

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

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

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

Currently, the majority of our production is sold to marketers and other purchasers that have access to nearby pipeline facilities. However, as we begin to further develop our properties, we may find production in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil or natural gas could have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.
    14    

Hedging transactions may limit our potential gains.

In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we may enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. While intended to reduce the effects of volatile crude oil and natural gas prices, such transactions may limit our potential gains if crude oil and natural gas prices rise over the price established by the arrangements.

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

The oil and gas industry has become increasingly dependent upon digital technologies to conduct day-to-day operations including certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil and natural gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and other third parties. Our business partners, including vendors, service providers, purchasers of our production and financial institutions, are also dependent on digital technology. It is possible that we could incur interruptions from cyber security attacks, computer viruses or malware. We believe that we have positive relations with our vendors and maintain satisfactory anti-virus and malware software and controls. Even so, any cyber incidents or interruptions to our computing and communications infrastructure or our information systems could lead to data corruption, communication interruption, unauthorized release, gathering, monitoring, misuse or destruction of proprietary or other information, or otherwise significantly disrupt our business operations. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

Competition is intense in the oil and gas industry.

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

Risks Relating to Our Common Stock

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


We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities. In addition, our credit facility prohibits us from paying dividends.
    15    

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

Under our Articles of Incorporation, our board of directors is authorized to issue up to 50,000,000 shares of preferred stock, of which none are issued and outstanding as of the date of this Annual Report. Also, our board of directors, without shareholder approval, may determine the price, rights, preferences, privileges and restrictions, including voting rights, of those shares. If the board causes shares of preferred stock to be issued, the rights of the holders of our common stock could be adversely affected. The board’s ability to determine the terms of preferred stock and to cause its issuance, while providing desirable flexibility in connection with possible acquisitions and other corporate purposes, could have the effect of making it more difficult for a third party to acquire a majority of our outstanding voting stock. Preferred shares issued by the board of directors could include voting rights, or even super voting rights, which could shift the ability to control the company to the holders of the preferred stock. Preferred shares could also have conversion rights into shares of common stock at a discount to the market price of the common stock which could negatively affect the market for our common stock. In addition, preferred shares would have preference in the event of liquidation of the Company, which means that the holders of preferred shares would be entitled to receive the net assets of the Company distributed in liquidation before the common stock holders receive any distribution of the liquidated assets. We have no current plans to issue any shares of preferred stock.

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

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




    16    

Item 1B: Unresolved Staff Comments

None.

Item 2: Properties

General Background

Ring is currently engaged in oil and natural gas acquisition, exploration, development and production, with activities currently in Texas and Kansas. Our focus will be on developing our existing properties, while continuing to pursue acquisitions of oil and gas properties with upside potential.

Management’s Business Strategy Related to Properties

Our goal is to increase shareholder value by investing in oil and gas projects with attractive rates of return on capital employed. We plan to achieve this goal by exploiting and developing our existing oil and natural gas properties and pursuing acquisitions of additional properties. Specifically, we have focused, and plan to continue to focus, on the following:

Developing and Exploiting Existing Properties

We believe that there is significant value to be created by drilling the identified undeveloped opportunities on our properties. As of December 31, 2014, we owned interests in a total of 5,835 gross (5,129 net) developed acres and operate essentially all of the net pre-tax PV10 value of our proved undeveloped reserves. In addition, as of December 31, 2014, we owned interests in approximately 23,903 gross undeveloped acres (12,141 net). While our focus will be toward growth through additional acquisitions and leasing, we plan on drilling wells on our existing acreage to develop the potential contained therein.

Pursuing Profitable Acquisitions

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

Summary of Oil and Natural Gas Properties and Projects

Significant Texas Operations


Andrews County leases – Andrews County, Texas. In 2011, we acquired a 100% working interest and a 75% net revenue interest in the initial leases. Since that time, we have acquired working and net revenue interests in additional producing leases and acquired additional undeveloped acreage in and around our Andrews County leases. The working interests range from 2-100% and the net revenue interests range from 2-80%. In total, we now own 29,738 gross acres, with 5,835 acres developed and held by production and the remaining 23,903 acres being undeveloped. We believe the Andrews County leases contain a considerable number of remaining potential drilling locations. Our reserve estimate includes 239 PUD wells. Our reserve estimates include the capital costs required to develop these wells.

    17    

Significant Kansas Operations

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

Title to Properties

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

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

Summary of Oil and Natural Gas Reserves

As of December 31, 2014, our estimated proved reserves had a pre-tax PV10 value of approximately $281.7 million and a Standardized Measure of Discounted Future Cash Flows of approximately $196.3 million, essentially 100% of which relate to our properties in Texas. We spent approximately $143.0 million on acquisitions and capital projects during 2013 and 2014. We expect to further develop these properties through additional drilling. We will closely manage our capital expenditures to our cash flow. As commodity prices change we will consider the resulting impact on our cash flow and adjust our capital expenditures up or down accordingly. We have maintained a strong current cash position with no long-term debt; we will continue to seek acquisition opportunities that complement our core assets.

The following table summarizes our total net proved reserves, pre-tax PV10 value and Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2014.

    18    

Geographic
Area
Oil
(Bbl)
Natural
Gas
(Mcf)
Total
(Boe)
Pre-Tax
PV10
Value
Standardized
Measure of
Discounted
Future Net
Cash Flows
Texas 10,221,491 944,810 10,378,959 280,779,438 195,480,001
Kansas
20,800 43,500 28,050 921,500 864,992
Total 10,242,291 988,310 10,407,009 $ 281,700,938 $ 196,344,993

Reserve Quantity Information

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

Our oil and natural gas reserves are attributable solely to properties within the United States. A summary of the changes in quantities of proved (developed and undeveloped) oil and natural gas reserves is shown below.

Oil (Bbls) Natural Gas
(Mcf)
Balance, December 31, 2012 3,646,743 1,733,780
   Purchase of minerals in place
934,716 208,013
   Improved recovery 282,958 62,970
   Extensions and discoveries 2,393,976 532,760
   Production (109,673) (36,047)
   Sales of minerals in place (16,100)
   Revisions of estimates (276,965) (14,433)
 
Balance, December 31, 2013 6,855,655 2,487,043
 
   Purchase of minerals in place 2,828,530 511,921
   Improved recovery 48,233
   Extensions and discoveries 1,225,094 117,778
   Production (457,038) (38,735)
   Revisions of estimates (258,183) (2,089,697)
Balance, December 31, 2014 10,242,291 988,310
    19    

Our proved oil and natural gas reserves are shown below:

  For the Years Ended December 31,
2013 2014
Oil (Bbls)    
    Developed
1,941,367 4,454,414
    Undeveloped 4,914,288 5,787,877
    Total 6,855,655 10,242,291
   
Natural Gas (Mcf)    
    Developed 630,751 299,188
    Undeveloped 1,856,292 689,122
    Total 2,487,043 988,310
   
Total (Boe)    
    Developed 2,046,493 4,504,279
    Undeveloped 5,223,670 5,902,730
    Total 7,270,163 10,407,009

Standardized Measure of Discounted Future Net Cash Flows

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

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

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

    20    

  December 31, 2014 2013
Future cash flows $ 875,492,876 $ 648,958,812
Future production costs (217,842,533) (165,478,373)
Future development costs (113,073,539) (98,287,766)
Future income taxes (165,083,198) (125,104,471)
Future net cash flows 379,493,606 260,088,202
10% annual discount for estimated timing of cash flows (183,148,613) (126,140,275)
 
Standardized Measure of Discounted Cash Flows $ 196,344,993 $ 133,947,927

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

  2014 2013
Beginning of the year $ 133,947,927 $ 71,358,446
Purchase of minerals in place 89,152,815 24,631,148
Extensions, discoveries and improved recovery, less related costs 39,903,356 72,635,671
Development costs incurred during the year 90,562,299 29,103,392
Sales of oil and gas produced, net of production costs (33,096,276) (994,793)
Sales of minerals in place (1,039,031)
Accretion of discount 16,564,967 8,568,497
Net changes in price and production costs (30,191,382) 5,568,442
Net change in estimated future development costs (31,004,796) (6,499,395)
Revision of previous quantity estimates (15,044,380) (10,313,017)
Revision of estimated timing of cash flows (43,530,618) (29,859,746)
Net change in income taxes (20,918,919) (29,211,687)
 
End of the Year $ 196,344,993 $ 133,947,927

Proved Reserves

Our 10,407,009 BOE of proved reserves, which consist of approximately 98% oil and 2% natural gas, are summarized below as of December 31, 2014, on a net pre-tax PV10 value and Standardized Measure of Discounted Future Net Cash Flows basis. Our reserve estimates have not been filed with any Federal authority or agency (other than the SEC).

As of December 31, 2014, our Texas proved reserves had a net pre-tax PV10 value of $280.8 million and Standardized Measure of Discounted Future Net Cash Flows of $195.5 million and our proved reserves in Kansas had a net pre-tax PV10 value of $0.9 million and Standardized Measure of Discounted Future Net Cash Flows of $0.9 million.
    21    

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

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

Proved Undeveloped Reserves

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

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

Net downward revision of approximately 511,503 BOE primarily as a result of performance.
Purchase of minerals in place through leasing of new acreage and acquisitions resulted in the addition of approximately 2,172,974 BOE.

Our proved reserves as of December 31, 2014 are summarized in the table below.

    22    


 
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
3,623,583
158,563
3,650,010
35%
$     114,593
$        79,779
$                   —
  PDNP
810,031
97,125
826,219
8%
33,067
23,021
3,632
  PUD
5,787,877
689,122
5,902,730
57%
133,120
92,680
109,441
 
Total Proved:
10,221,491
944,810
10,378,959
100%
$     280,780
$     195,480
$        113,073
Kansas:
  PDP
20,800
43,500
28,050
0%
$            921
$            865
$                   —
 
Total Proved:
20,800
43,500
28,050
0%
$            921
$            865
$                   —
 
Total:
  PDP
3,644,383
202,063
3,678,060
35%
$     115,514
$       80,644
$                   —
  PDNP
810,031
97,125
826,219
8%
33,067
23,021
3,632
  PUD
5,787,877
689,122
5,902,730
57%
133,120
92,680
109,441
 
Total Proved:
10,242,291
988,310

10,407,009

100%
$     281,701
$     196,345
$        113,073


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.

Year
Estimated
Oil Reserves Developed (Bbls)
Estimated
Gas Reserves Developed
(Mcf)
Total Boe
Estimated Development
Costs
2015 3,719,931 473,425 3,798,835 48,937,371
2016 2,877,978 312,822 2,930,115 64,136,175
  6,597,909 786,247 6,728,950 $ 113,073,546
         

 

    23    

Internal Controls Over Reserves Estimates

Our reserves data and estimates were compiled, prepared and audited by third party independent consultants, Cawley, Gillespie & Associates, Inc., as described in more detail herein, in compliance with SEC definitions and guidance and in accordance with generally accepted petroleum engineering principles. The technical persons employed by Cawley, Gillespie & Associates, Inc., met the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our reserves estimates are prepared by examination and evaluation of production data, production decline curves, reservoir pressure data, logs, geological data, and offset analogies. The third party independent consultants are provided full access to complete and accurate information pertaining to the property, and to all applicable personnel of the Company. Our reserves estimates and process for developing such estimates are reviewed and approved by its Vice President of Operations, Daniel D. Wilson, a petroleum engineer, and Chief Executive Officer, Kelly Hoffman, to ensure compliance with SEC disclosure and internal control requirements and to verify the independence of the third party consultants. Mr. Daniel Wilson, a petroleum engineer and businessman, has 30 years of experience in operating, evaluating and exploiting oil and gas properties. Mr. Kelly Hoffman has 39 years of well-rounded experience in the oil and gas industry. Our management is ultimately responsible for reserve estimates and reserve disclosures and ensuring that they are in accordance with the applicable regulatory requirements and industry standards and practices.

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

Summary of Oil and Natural Gas Properties and Projects

Production Summary


Our estimated average daily production for the month of December, 2013, is summarized below. The following table indicates the percentage of our estimated December 2013 average daily production of 631 BOE/d attributable to each state and to oil versus natural gas production.

State
  Average
Daily
Production
Oil
Natural Gas
Texas   97.75% 98.25% 76.48%
Kansas   2.25% 1.75% 23.52%
Total   100.00% 100.00% 100.00%

    24    

Acreage

The following table summarizes gross and net developed and undeveloped acreage at December 31, 2013 by region (net acreage is our percentage ownership of gross acreage). Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.

Developed Acreage
Undeveloped Acreage
Total Acreage
Gross Net Gross Net Gross Net
Texas 5,835 5,129 23,903 12,141v 29,738 17,270
Kansas 800 716 17,477 16,301 18,277 17,017
Total 6,635 5,845 41,380 28,442 48,015 34,287

Production History

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

  Year Ended December 31,
2012 2013 2014
Oil production (Bbls) 20,531 109,673 457,039
Natural gas production (Mcf) 6,480 36,047 38,735
Total production (Boe) 21,611 115,681 463,495
Daily production (Boe/d) 59 317 1,270
Average sales price:      
  Oil (per Bbl) $ 84.50 $ 92.81 $ 83.06
  Natural gas (per Mcf) 3.50 3.82 3.53
    Total (per Boe) 81.39 89.17 82.18
Average production cost (per Boe) $ 36.37 $ 10.44 $ 10.77
Average production taxes (per Boe) 3.84 4.12 3.80

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

Productive Wells

The following table presents our ownership at December 31, 2014, in productive oil and natural gas wells by region (a net well is our percentage ownership of a gross well).
    25    

  Oil Wells
Gas wells Total Wells
Gross Net Gross Net Gross Net
Texas 245 181 245 181
Kansas 4 2 1 1 5 3
 
Total 249 183 1 1 250 184

Drilling Activity

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

Cost Information

We conduct our oil and natural gas activities entirely in the United States. As noted previously in the table appearing under “Production History”, our average production costs, per BOE, were $36.37, $10.44 and $10.77 during the years ended December 31, 2012, 2013 and 2014, respectively, and our average production taxes, per BOE, were $3.84, $4.12 and $3.80 for the years ended December 31, 2012, 2013 and 2014, respectively. These amounts are calculated by dividing our total production costs or total production taxes by our total volume sold, in BOE.

Costs incurred for property acquisition, exploration and development activities during the years ended December 31, 2012, 2013 and 2014 are shown below.

For the Year Ended December 31,
2012 2013 2013
Acquisition of proved properties $    9,873,128 $    5,192,441 $   15,812,995
Acquisition of unproved properties
Exploration costs
Development costs 6,581,343 29,796,379 92,182,681
Total Costs Incurred $ 16,454,471 $ 34,988,820 $ 107,995,676

Other Properties and Commitments

Our principal executive offices are in leased office space in Midland, Texas. The leased office space consists of approximately 15,000 square feet. Additionally, we still have a lease for our previous office space in Midland, Texas, consisting of approximately 3,700 square feet. We vacated this space as of February 28, 2015 and have begun efforts to sublet this space. Additionally, we lease office space in Tulsa, Oklahoma, which serves as our primary accounting office. The leased office space consists of approximately 3,700 square feet. We also lease office space in Andrews, Texas, which is currently our only field office. The leased office space consists of approximately 2,000 square feet. We expect our current office space to be adequate as we move forward.
    26    

Item 3: Legal Proceedings

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

Item 4: Mine safety disclosures

Not applicable.

    27    

PART II

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

Market for our Common Stock

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

OTCQB/OTC Bulletin Board
  Period High Sale Low Sale
 
1st Quarter 2013 $                  9.51 5.85
2nd Quarter 2013 8.76 6.60
3rd Quarter 2013 (through August 31) 15.27 8.65
 
NYSE MKT
  Period High Sale Low Sale
3rd Quarter 2013 (September 1 - September 30) $                15.75 $                13.50
4th Quarter 2013 14.39 11.05
 
1st Quarter 2014 $                15.35 $                12.10
2nd Quarter 2014 20.61 15.25
3rd Quarter 2014 19.35 14.25
4th Quarter 2014 17.77 7.54
 
1st Quarter 2015 (through March 10) 10.93 8.32

The following graph compares the cumulative 5-year total return attained by stockholders on Ring Energy, Inc.’s common stock relative to the cumulative total retruns of the S&P 500 index and that of a selected peer group, named below. The graph assumes a $100 investment at the closing price on December 31, 2009, and reinvestment of dividends on the date of payment without commission. This table is not intended to forecast future performance of our common stock.
    28    



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

Record Holders

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

Dividend Policy


We have not paid any dividends on our common stock during the last three years, and we do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, our credit facility prohibits us from paying dividends.



    29    

Securities Authorized for Issuance Under Equity Compensation Plans

The following table sets forth information concerning our executive stock compensation plans as of December 31, 2014.

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) (c)
Equity compensation
plans approved by
security holders
2,684,500 $              4.67 2,136,500
       
Equity compensation
plans not approved by
security holders
       
Total 2,684,500 $              4.67 2,136,500

Description of Our Long Term Incentive Plan


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

Shares Available

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

Administration

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

    30    

Eligibility

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

Stock Options

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

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

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

Restricted Stock

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

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

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

    31    

Fair Market Value

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

Transferability Restrictions

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

Termination and Amendments to the Plan


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

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

Recent Sales of Unregistered Securities


On June 18, 2014, we completed our offering of 2,000,001 shares of common stock at $15.00 in the Private Placement. The shares were sold without registration under the Securities Act by reason of the exemption from the registration afforded by the provisions of Section 4(a)(2) and/or Section 4(a)(5) of the Securities Act of 1933, as amended, and Rule 506 promulgated thereunder for sales of unregistered securities. Commissions in the amount of $1,227,000 were paid to the placement agents. The Company has filed a registration statement with the SEC with respect to the Resale Shares.
    32    

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

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

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

Issuer Repurchases

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

Item 6: Selected Financial Data

The selected consolidated financial information set forth below is derived from our consolidated balance sheets and statements of operations as of and for the years ended December 31, 2014, 2013, 2012 and 2011. The data set forth below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes thereto included in this Annual Report.

 

    33    

  Successor Predecessor
  For the
Year
ended
December 31,
2014
For the
Year
ended
December 31,
2013
For the
Year
ended
December 31,
2012
For the
Eight Months
ended
December 31,
2011

For the
Four Months
ended
April 30,
2011

Statement of
Operations Data:
         
Revenues $    38,089,443 $    10,315,701 $      1,757,444 $          388,674 $           96,956
Cost of revenues 6,753,372 1,684,493 868,954 191,738 76,124
Depreciation,
depletion
and amortization
11,807,794 2,284,091 506,786 89,376 2,778
Accretion 154,973 53,681 20,906 5,547 3,732
General and
administrative
6,803,029 6,682,760 2,392,645 428,575 6,000
Net income (loss) 8,420,500 (452,209) (1,669,283) 63,165 8,322
Basic income (loss) per
common share
$                0.34 $             (0.03) $             (0.21) $                0.01 $                    —
Diluted income (loss) per
common share
$                0.33 $             (0.03) $             (0.21) $                0.01 $                    —

      As of December 31,
    Successor Predecessor
2013 2013 2012 2011 2011
Balance Sheet Data:          
Current assets $  15,083,298 $  56,305,036 $   5,882,530 $      223,695 $            30,383
Oil and gas properties
subject to amortization
166,036,400 58,040,724 23,051,904 6,597,433 306,460
Total assets 167,641,640 111,723,418 28,513,378 6,742,885 285,411
Total current liabilities 16,263,051 7,231,643 1,191,431 477,057 12,127
Total long-term liabilities 8,835,879 1,886,061 1,122,236 10,372,338 261,598
Total Stockholders/Owners
Equity (Deficit)
142,542,530 102,605,714 26,199,711 (4,106,510) 11,686

Reorganization into Ring – On June 28, 2012, Ring completed the acquisition of Stanford Energy, Inc. (“Stanford”) through the closing of a stock-for-stock exchange agreement dated May 3, 2012. As a result, Stanford’s stockholders obtained control of Ring under current accounting guidance. Since the Stanford stockholders obtained a controlling interest in Ring’s Common Stock and stock options, Stanford was determined to be the accounting acquirer and its historical financial statements have been adjusted to reflect its reorganization in a manner equivalent to a 2,500-for-1 stock split. The accompanying historical financial statements prior to the reorganization into Ring are Stanford’s financial statements, adjusted to reflect the authorized capital and par value of Ring and to reflect the effects of the stock split for all periods presented.
    34    

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

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

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

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

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

Overview

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

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

Business Description and Plan of Operation


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

Our goal is to increase stockholder value by investing in oil and gas projects with attractive rates of return on capital employed. We plan to achieve this goal by exploiting and developing our existing oil and natural gas properties and pursuing acquisitions of additional properties. Specifically, our business strategy is to increase our stockholders value through the following:
    35    

• Growing production and reserves by developing our oil-rich resource base. We intend to actively drill and develop its acreage base in an effort to maximize its value and resource potential. Ring’s portfolio of proved oil and natural gas reserves consists of 98% oil and 2% natural gas. Of those reserves, 35% of the proved reserves are classified as proved developed producing, or “PDP,” 8% are classified as proved developed non-producing, or “PDNP,” and approximately 57% are classified as proved undeveloped, or “PUD.” 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. Through December 31, 2014, we increased our proved reserves to approximately 10.4 million BOE (barrel of oil equivalent). Effectively 100% of our reserves relate to properties located in Texas. We spent approximately $143.0 million on acquisitions and capital projects during 2013 and 2014, and we intend to continually actively drill and develop our acreage in an effort to maximize shareholder value.

• 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, Ring 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.

• 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. We believe that management’s proven ability to evaluate resource potential will allow Ring to successfully acquire acreage and bring out more value in the assets.
    36    

Results of Operations

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

For the Years Ended December 31,
2012 2013 2013
Net production:      
  Oil (Bbls) 20,531 109,673 457,039
  Natural gas (Mcf) 6,480 36,047 38,735
       
Net sales:      
  Oil $         1,734,739 $       10,178,176 $       37,952,888
  Natural Gas 22,705 137,525 136,555
       
Average sales price:      
  Oil (per Bbl) $               84.50 $               92.81 $               83.06
  Natural gas (per Mcf) 3.50 3.82 3.53
       
Production costs and expenses      
  Oil and gas production costs $            785,959 $         1,207,529 $        4,993,167
  Production taxes 82,995 476,964 1,760,206
  Depreciation, depletion and 
    amortization expense
506,786 2,284,091 11,807,794
  Accretion expense 20,906 53,681 154,972

  General and administrative
    expenses

2,392,645 6,682,760 6,803,029
       

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

Oil and natural gas sales. Oil and natural gas sales revenue increased approximately $27.8 million to $38.1 million in 2014. Oil sales increased approximately $27.8 million while natural gas sales remained effectively the same. The oil sales increase was the result of an increase in sales volume from 109,673 barrels of oil in 2013 to 457,039 barrels of oil in 2014 offset by a decrease of 10% in the average realized per barrel oil price from $92.81 in 2013 to $83.04 in 2014. These per barrel amounts are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels. Natural gas sales volume increased from 36,047 Mcf in 2013 to 38,735 Mcf in 2014 but was offset by an 8% decrease in the average realized per Mcf gas price from $3.82 in 2013 to $3.53 in 2014. These per Mcf amounts are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf. The volume increases for both oil and natural gas are the result of both the acquisitions we made during the year and the result of our development of existing properties.
    37    

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

Oil and gas production taxes. Oil and gas production taxes as a percentage of oil and natural gas sales were 4.62% during 2013 and remained the same in 2014. Production taxes vary from state to state. Therefore, these taxes are likely to vary in the future depending on the mix of production we generate from various states, and on the possibility that any state may raise its production tax.
Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased by $9,523,703 to $11,807,794 in 2014. The increase was a result of increased production volumes and an increase in the average depreciation, depletion and amortization rate from $19.74 per BOE during 2013 to $25.48 per BOE during 2014. These per BOE amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total volume sold, in BOE.

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

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

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

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

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

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


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


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

Oil and gas production taxes. Oil and gas production taxes as a percentage of oil and natural gas sales were 4.72% during 2012 and decreased slightly to 4.62% in 2013. Production taxes vary from state to state. Therefore, these taxes are likely to vary in the future depending on the mix of production we generate from various states, and on the possibility that any state may raise its production tax.

Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased by $1,777,305 to $2,284,091 in 2013. The increase was a result of increased production volumes partially offset by a decrease in the average depreciation, depletion and amortization rate from $23.45 per BOE during 2012 to $19.74 per BOE during 2013. These per BOE amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total volume sold, in BOE. The decreased depreciation, depletion and amortization rate was the result of development throughout the year and adding additional reserves.

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

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

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

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

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

Liquidity and Capital Resources

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

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

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In July 2014, the Company entered into a Credit Agreement with SunTrust Bank, as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (“Administrative Agent”) (the “Credit Facility”). The Credit Facility provides for a senior secured revolving credit facility with a maximum borrowing amount of $150 million. The Credit Facility matures on July 1, 2019, and is secured by substantially all of the Company’s assets.

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

The Credit Facility allows for Eurodollar Loans and Base Rate Loans (each as defined in the Credit Facility). The interest rate on each Eurodollar Loan will be the adjusted LIBOR for the applicable interest period plus a margin between 1.75% and 5.00% (depending on the then-current level of borrowing base usage). The annual interest rate on each Base Rate Loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the federal funds rate plus 0.5% per annum or the (iii) adjusted LIBOR determined on a daily basis for an interest period of one-month, plus 1.00% per annum, plus (b) a margin between 2.75% and 6.00% (depending on the then-current level of borrowing base usage).

The credit facility contains certain covenants, which, among other things, require the maintenance of (i) a total leverage ratio of not more than 4.0 to 1.0 and (ii) a minimum current ratio of 1.0 to 1.0. The Credit Facility also contains other customary affirmative and negative covenants and events of default.

As of December 31, 2014, no amounts are outstanding on our credit facility.

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

Schedule of Contractual Obligations. The following table summarizes our future estimated lease payments for periods subsequent to December 31, 2014. The leases pertain to approximately 15,000 square feet of space for our corporate headquarters in Midland, Texas, approximately 3,700 square feet for our previous office space in Midland, Texas, as we attempt to sublet the space, approximately 3,700 square feet of office space for our accounting offices in Tulsa, Oklahoma and approximately 2,000 square feet of office space for our field office in Andrews, Texas. The Company incurred lease expenses of $149,872, $141,593 and $208,091 for the years ended December 31, 2014, 2013 and 2012, respectively. The following table reflects the future minimum lease payments under the operating leases as of December 31, 2014.

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   Payment due by period
  Contractual Obligations Total Less than
1 year
1-3 years 3-5 years More than
5 years
Operating Lease Obligations 1,519,695 465,175 1,054,520
           
Total 1,519,695 465,175 1,054,520

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

Off-Balance Sheet Financing Arrangements

As of December 31, 2014, we had no off-balance sheet financing arrangements.

Critical Accounting Policies and Estimates

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

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

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

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

    41    

prepared in accordance with guidelines established by the SEC and FASB. The accuracy of our reserve estimates is a function of:

• the quality and quantity of available data;
• the interpretation of that data;
• the accuracy of various mandated economic assumptions; and
• the judgments of the persons preparing the estimates.

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

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

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

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

Income Taxes. Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to actual in the period we file our tax returns.
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Effects of Inflation and Pricing

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

Item 7A Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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

The prices we receive depend on many factors outside of our control. Oil prices we received during 2014 ranged from a low of $54.60 per barrel to a high of $96.72 per barrel. Natural gas prices we received during 2014 ranged from a low of $1.96 per Mcf to a high of $7.09 per Mcf. A significant decline in the prices of oil or natural gas could have a material adverse effect on our financial condition and results of operations.

Customer Credit Risk

Our principal exposures to credit risk is through receivables from the sale of our oil and natural gas production (approximately $3.6 million at December 31, 2014). We are subject to credit risk due to the concentration of our oil and natural gas receivables with our most significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the fiscal year 2014, sales to two customers, HollyFrontier and Plains Marketing, represented 74% and 18%, respectively, of oil and gas revenues. At December 31, 2014, HollyFrontier and Plains Marketing represented 45% and 37%, respectively, of our accounts receivable.

Interest Rate Risk

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

Please also see Item 1A “Risk Factors” above for a discussion of other risks and uncertainties we face in our business.
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Item 8: Financial Statements and Supplementary Data

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

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


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 year ended December 31, 2012 did not contain an adverse opinion or a disclaimer of opinion, and was not qualified or modified as to uncertainty, audit scope, or accounting principles.
Prior to engaging Eide Bailly, the Company did not consult with Eide Bailly regarding the application of accounting principles to a specific completed or contemplated transaction or regarding the type of audit opinions that might be rendered by Eide Bailly on the Company’s financial statements, and Eide Bailly did not provide any written or oral advice that was an important factor considered by the Company in reaching a decision as to any such accounting, auditing or financial reporting issue.

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

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

Item 9A – Controls and Procedures

Evaluation of disclosure controls and procedures.


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

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Based on management’s evaluation, our chief executive officer and chief financial officer concluded that, as of December 31, 2014, our disclosure controls and procedures are designed at a reasonable assurance level and are effective to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure.

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

Changes in internal control over financial reporting.

We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes. There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

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

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

In making our assessment of internal control over financial reporting, our management used the criteria issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (1992). Based on our assessment, we believe that, as of December 31, 2014, our internal control over financial reporting is effective based on those criteria.

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

Item 9B: Other Information

None.

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PART III
Item 10: Directors, Executive Officers and Corporate Governance

Executive Officers and Directors


The following table sets forth information regarding our executive officers, certain other officers and directors as of March 10, 2015. The Board believes that all the directors named below are highly qualified and have the skills and experience required for effective service on the Board. The directors’ and officers’ individual biographies below contain information about their experience, qualifications and skills that led the Board to nominate them.

  Name Age Position
Kelly Hoffman
56
Chief Executive Officer, Director
David A. Fowler
56
President, Director
Daniel D. Wilson
53
Vice President of Operations
William R. Broaddrick
37
Chief Financial Officer
Lloyd T. Rochford
68
Chairman of the Board of Directors
Stanley M. McCabe
82
Director
Anthony B. Petrelli
62
Director
Clayton E. Woodrum
74
Director


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

Messrs. Rochford and McCabe joined the Board in June 2012 as a part of the merger between Ring and Stanford Messrs. Hoffman, Fowler, Woodrum and Petrelli joined the Board in January 2013. All of the Board members were re-elected at the Company’s 2014 annual shareholders’ meeting. There are no family relationships between any director or executive officer or person nominated or chosen to become andirector or officer of the Company.

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

Kelly Hoffman – Chief Executive Officer and Director

Mr. Hoffman, 56, has organized the funding, acquisition and development of many oil and gas properties. He began his career in the Permian Basin in 1975 with Amoco Production Company. His responsibilities included oilfield construction, crew management, and drilling and completion operations. In the early 1990s Mr. Hoffman co-founded AOCO and began acquiring properties in West Texas. In 1996 he arranged financing and purchased 10,000 acres in the Fuhrman Mascho field in Andrews, Texas. In the first six months he organized a 60 well drilling and completion program resulting in a 600% increase in revenue and approximately 18 months later sold the properties to Lomak (Range Resources). In 1999 he again arranged financing and acquired 12,000 acres in Lubbock and Crosby counties. After drilling and completing 19 successful wells, unitizing the acreage, and instituting a secondary recovery project he sold his interest in the property to Arrow Operating Company. From April 2009 until December 2011 Mr. Hoffman served as President of Victory Park Resources, a privately held exploration and production company focused on the acquisition of oil and gas producing properties in Oklahoma, Texas and New Mexico. Mr. Hoffman currently serves as a director of Joes Jeans Inc. (NASDAQ: JOEZ), a reporting company.

    46    

David A. Fowler – President and Director

Mr. Fowler, 56, has served in several management positions for various companies in the insurance and financial services industries. In 1994, he joined Petroleum Listing Service as Vice President of Operations, overseeing oil and gas property listings, information packages, and marketing oil and gas properties to industry players. In late 1998, Mr. Fowler became the Corporate Development Coordinator for the Independent Producer Finance (“IPF”) group of Range Resources Corporation. Leaving Range IPF in April of 2001, he co-founded and became President of Simplex Energy Solutions, LLC (“Simplex”). Representing Permian Basin oil and gas independent operators, Simplex became known as the Permian Basin’s premier oil and gas divestiture firm, closing over 150 projects valued at approximately $675 million.

Daniel D. Wilson – Executive Vice President

Mr. Wilson, 53, has 30 years of experience in operating, evaluating and exploiting oil and gas properties. He has experience in production, drilling and reservoir engineering. For the last 22 years he has served as the Vice President and Manager of Operations for Breck Operating Corporation (“Breck”). He has overseen the building, operating and divestiture of two companies during this time. At Breck’s peak Mr. Wilson was responsible for over 750 wells in seven states and had an operating staff of 27 including engineers, foremen, pumpers and clerks. Mr. Wilson personally performed or oversaw all of the economic evaluations for both acquisition and banking purposes.

William R. Broaddrick – Chief Financial Officer

Mr. Broaddrick, 37, was employed from 1997 to 2000 with Amoco Production Company, performing lease revenue accounting and state production tax regulatory reporting functions. During 2000, Mr. Broaddrick was employed by Duke Energy Field Services, LLC performing state production tax functions. From 2001 until 2010, Mr. Broaddrick was employed by Arena as Vice President and Chief Financial Officer. During 2011, Mr. Broaddrick joined Stanford as Chief Financial Officer. Subsequent to and as a result of the merger transaction between Stanford and Ring Mr. Broaddrick became Chief Financial Officer of Ring Energy as of July 2012.

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

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

Mr. Rochford, 68, has been active as an individual consultant and entrepreneur in the oil and gas industry since 1973. During that time, he has been an operator of wells in the mid-continent of the United States, evaluated leasehold drilling and production projects, and arranged and raised in excess of $500 million in private and public financing for oil and gas projects and development.

Mr. Rochford has successfully formed, developed and sold/merged four natural resource companies, two of which were listed on the New York Stock Exchange. The most recent, Arena, was founded by Mr. Rochford and his associate Stanley McCabe in August 2000. From inception until May of 2008, Mr. Rochford served as President, Chief Executive Officer (“CEO”) and as a director of Arena. During that time, Arena received numerous accolades from publications such as Business Week (2007 Hot Growth Companies), Entrepreneur (2007 Hot 500), Fortune (2007, 2008, 2009 Fastest Growing Companies), Fortune Small Business (2007, 2008 Fastest Growing Companies) and Forbes (Best Small Companies of 2009). In May 2008, Mr. Rochford resigned from the position of CEO at Arena and accepted the position of Chairman of the Board. In his role as Chairman, he continued to pursue
    47    

opportunities that would enhance the then current, as well as long-term value of Arena. Through his efforts, Arena entered into a merger agreement and was acquired by another New York Stock Exchange company for $1.6 billion in July, 2010.

Stanley M. McCabe – Director

Mr. McCabe, 82, has been active in the oil and gas industry for over 30 years, primarily seeking individual oil and gas acquisition and development opportunities. In 1979 he founded and served as Chairman and CEO of Stanton Energy, Inc., a Tulsa, Oklahoma natural resource company specializing in contract drilling and operation of oil and gas wells. In 1990, Mr. McCabe co-founded with Mr. Rochford, Magnum Petroleum, Inc., serving as an officer and director. In 2000, Mr. McCabe co-founded with Mr. Rochford, Arena , serving as Chairman of the Board until 2008 and then as a director of Arena until 2010.

Anthony B. Petrelli – Director

Mr. Petrelli, 62, is President, member of the Board of Directors, and Director of Investment Banking of Neidiger, Tucker, Bruner, Inc., a Denver, Colorado based financial services firm founded in 1977. Beginning his career in 1972, Mr. Petrelli has had extensive experience in the areas of operations, sales, trading, management of sales, underwriting and corporate finance. He has served on numerous regulatory and industry committees including service on the FINRA Corporate Finance Committee, the NASD Small Firm Advisory Board and as Chairman of the FINRA District Business Conduct Committee, District 3. Mr. Petrelli received his BS in Business (Finance) and his Masters of Business Administration (MBA) from the University of Colorado and a Masters of Arts in Counseling from Denver Seminary.

Clayton E. Woodrum – Director

Mr. Woodrum, CPA, 74, is a founding partner of Woodrum, Tate & Associates, PLLC. His financial background encompasses over 40 years of experience from serving as a partner in charge of the tax department of a big eight accounting firm to chief financial officer of BancOklahoma Corp., and Bank of Oklahoma. His areas of expertise include business valuation, litigation support including financial analysis, damage reports, depositions and testimony, estate planning, financing techniques for businesses, asset protection vehicles, sale and liquidation of businesses, debt restructuring, debt discharge and CFO functions for private and public companies.

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

Involvement in Certain Legal Proceedings

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

    48    

Board Committees

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

Audit Committee

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

Compensation Committee

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

Nominating and Corporate Governance Committee

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

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

Executive Committee

The Executive Committee’s principal function is to exercise the powers and duties of the Board between Board meetings and while the Board is not in session, and implement the policy decisions of the Board. The Executive Committee is comprised of Messrs. Rochford and McCabe.
    49    

Code of Ethics

We have adopted a Code of Ethics that applies to our Chief Executive Officer, President, Chief Financial Officer, and Corporate Controller, as well as the principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions. We have also adopted a Code of Conduct that applies to our officers, directors, and employees. These documents are available on the Company’s website at www.ringenergy.com. We shall also provide any person without charge, upon request, a copy of the Code of Ethics or Code of Conduct. Requests may be directed to Ring Energy, Inc., 6555 S. Lewis Ave., Suite 200, Tulsa, Oklahoma 74136, attention William R. Broaddrick, or by calling (918) 499-3880.

Section 16(a) Beneficial Ownership Reporting Compliance

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

Item 11: Executive Compensation

Compensation Discussion & Analysis


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

Our current executive compensation programs are determined and approved by our Compensation Committee, after consideration of recommendations by our Chairman of the Board and our Chief Executive Officer, as to the other Named Executive Officers. None of the Named Executive Officers are members of the Compensation Committee. The Compensation Committee has the direct responsibility and authority to review and approve the Company’s goals and objectives relative to the compensation of the Named Executive Officers, and to determine and approve (either as a committee or with the other members of the Company’s Board of Directors who qualify as “independent” directors under applicable guidelines adopted by the NYSE MKT, LLC) the compensation levels of the Named Executive Officers.

Our current executive compensation programs are intended to achieve two objectives. The primary objective is to enhance the profitability of the Company, and thus, shareholder value. The second objective is to attract, motivate, reward and retain employees, including executive personnel, who contribute to the long-term success of the Company. As described in more detail below, the material elements of our current executive compensation program for Named Executive Officers includes a base salary, discretionary annual bonuses and discretionary stock options grants.

The Company believes that each element of the executive compensation program helps to achieve one or both of the compensation objectives outlined above. The table below lists each material element of our executive compensation program and the compensation objective or objectives that it is designed to achieve.

    50    

  Compensation Element Compensation Objectives Attempted to be Achieved
   
Base Salary Attract and retain qualified executive’s Motivate and reward executives performance
   
Bonus Compensation Motivate and reward executive’s performance Enhance profitability of Company and shareholder value
   
Equity-Based Compensation – stock options and restricted stock grants Enhance profitability of Company and shareholder value by aligning long-term incentives with shareholders’ long-term interests

As illustrated by the table above, base salary is primarily intended to attract and retain qualified executives. This is the element of the Company’s current executive compensation program where the value of the benefit in any given year is not wholly dependent on performance. Base salaries are intended to attract and retain qualified executives as well as being linked to performance by rewarding and/or motivating executives. Base salaries are reviewed annually and take into account: experience and retention considerations; past performance; improvement in historical performance; anticipated future potential performance; and other issues specific to the individual executive.|

There are specific elements of the current executive compensation program that are designed to reward performance and enhance profitability and shareholder value, and therefore the value of these benefits is based on performance. The Company’s discretionary annual bonus plan is primarily intended to motivate and reward Named Executive Officers’ performance to achieve specific strategies and operating objectives, as well as improved financial performance.

The Compensation Committee does not currently benchmark executive compensation to any other companies. The Compensation Committee believes that bonuses and equity compensation should fluctuate with the Company’s success in achieving financial, operating and strategic goals. The Committee’s philosophy is that the Company should continue to use long-term compensation such as stock options to align shareholder and executives’ interests and should allocate a portion of long-term compensation to the entire executive compensation package.

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

Current Executive Compensation Program Elements

Base Salaries


Similar to most companies within the industry, our policy is to pay Named Executive Officers’ base salaries in cash. Effective July 1, 2012, the Compensation Committee designated a salary of $100,000 for Mr. Broaddrick. Effective September 1, 2012 the Compensation Committee recommended an increase of $25,000 for Mr. Broaddrick. Mr. Hoffman joined the Company effective January 1, 2013 and the Compensation Committee designated a salary of $175,000. Mr. Fowler joined the Company effective January 1, 2013 and the Compensation Committee designated a salary of $150,000. Mr. Wilson joined the Company effective January 1, 2013 and the Compensation Committee designated a salary of $150,000.
    51    

Annual Bonuses

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

Equity-Based Compensation – Options and Restricted Stock Grants

It is our policy that the Named Executive Officers’ long-term compensation should be directly linked to enhancing profitability and value provided to shareholders of the Company’s common stock. Accordingly, the Compensation Committee grants equity awards under the Company’s long term incentive plan designed to link an increase in shareholder value to compensation. Mr. Broaddrick was granted non-qualified stock options in 2012, 2013 and 2014. Messrs. Hoffman, Fowler and Wilson were granted non-qualified stock options in 2013 and 2014. Stock option grants are valued using the Black-Scholes Model and are calculated as a part of the executive compensation package for the year based on the amount of requisite service period served. Non-qualified stock options for Named Executive Officers and other key employees generally vest ratably over five years. No restricted stock was granted to any of the Named Executive Officers.’ The Compensation Committee believes that these awards encourage Named Executive Officers to continue to use their best professional skills and to retain Named Executive Officers for longer terms.

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

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

Compensation of Named Executive Officers

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

The Company does not have any pension plans, non-qualified deferred compensation plans or severance, retirement, termination, constructive termination or change in control arrangements for any of its Named Executive Officers for the year ended December 31, 2014.
    52    

Summary Compensation Table

Name and
Principal Position
Year Salary
($) (1)
Bonus
($)
Option
Awards
(2) ($)
All Other
Compensation
(3) ($)
Total ($)
Kelly Hoffman,
Chief Executive
Officer,
effective January 1, 2013
2014 175,000 196,728 24,000 (3)      395,728
2013 175,000 5,000 2,336,928 122,500 (4)   2,639,428
2012 232,156 90,833 (5)        90,833
             
David Fowler,
President,
effective January 1, 2013
2014 150,000 196,728 24,000 (3)      370,728
2013 150,000 5,000 2,336,928 22,500 (7)   2,514,428
2012
             
Danny Wilson,
Executive Vice President,
effective December 17, 2013
2014 150,000 163,940 313,940
2013 150,000 5,000 1,454,044 1,609,044
2012
             

William R. Broaddrick, Chief
Financial Officer, Interim Chief
Executive Officer from
September 1, 2012 through
December 31, 2012

2014 125,000 163,940 288,940
2013 125,000 5,000 207,549 337,549
2012 108,333 3,000 213,711 325,044
             

(1) Salary information for William R. Broaddrick during 2012 includes compensation received from Stanford Energy, Inc. prior to the merger between Stanford and Ring Energy, Inc. and compensation received from Ring subsequent to the merger.
(2) See discussion of assumptions made in valuing these awards in the notes to our financial statements.
(3) 2014 Other Compensation for Mssrs. Hoffman and Fowler consists of $24,000 in directors fees.
(4) 2013 Other Compensation to Mr. Hoffman includes a $100,000 signing bonus and $22,500 in director’s fees.
(5) 2012 Other Compensation to Mr. Hoffman consisted of consulting fees.
(7) David Fowler received $22,500 in director’s fees during 2013.


The Company awards stock options to key employees and the Named Executive Officers either on the initial date of employment or based on performance incentives throughout the year. The following table reflects the stock options granted during 2014.

Grants of Plan-Based Awards

Name Grant Date All Other Option Awards: Number
of Securities Underlying
Options (#)
Exercise or Base Price of Option Awards ($) Fair Value
on Grant
Date (1)
Kelly Hoffman 12/1/2014 30,000 $   8.00 $  196,728
David Fowler 12/1/2014 30,000 8.00 196,728
Daniel D. Wilson 12/1/2014 25,000 8.00 163,940
William R. Broaddrick 12/1/2014 25,000 8.00 163,940
    53    

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

The following table provides certain information regarding unexercised stock options outstanding for each Named Executive Officer as of December 31, 2014.

Outstanding Equity Awards

Name and
Principal
Position
Number of Securities
Underlying Unexercised
Options (#) Exercisable
Number of Securities
Underlying Unexercised
Options (#) Unexercisable
Options
Exercise
Price ($)
Option
Expiration
Date
Kelly Hoffman 150,000
200,000
5,000
100,000
300,000
20,000
30,000
$ 2.00
4.50
10.00
8.00
12/01/21
01/01/23
12/16/23
12/01/24
David Fowler 200,000
5,000
300,000
20,000
30,000
4.50
10.00
8.00
01/01/23
12/16/23
12/01/24
Daniel D. Wilson

120,000
4,000

180,000
16,000
25,000
4.50
10.00
8.00
01/01/23
12/16/23
12/01/24
William R. Broaddrick

20,000
10,000
4,000
40,000
30,000
16,000
25,000
2.00
4.50
10.00
8.00
12/01/21
09/01/22
12/16/23
12/01/24

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

Director Compensation

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


    54    

Director Compensation Table

Name Fees Earned or
Paid in Cash ($)
Option Awards ($) All Other Compensation ($) Total ($)
Lloyd T. Rochford  (2)    $   24,000 $  262,304 $   286,304
Stanley M. McCabe  (3) 24,000 262,304 286,304
David A. Fowler  (4) 24,000 262,304 286,304
Kelly Hoffman  (5) 24,000 262,304 286,304
Clayton E. Woodrum  (6) 24,000 262,304 286,304
Anthony B. Petrelli  (7) 24,000 262,304 286,304

(1) See discussion of assumptions made in valuing these awards in the notes to our financial statements.
(2) Lloyd T. Rochford has 140,000 options to purchase Ring stock.
(3) Stanley McCabe has 140,000 options to purchase Ring stock.
(4) David A. Fowler has an aggregate of 555,000 options to purchase Ring stock.
(5) Kelly Hoffman has an aggregate of 805,000 options to purchase Ring stock.
(5) Clayton E. Woodrum has 140,000 options to purchase Ring stock.
(6) Anthony B. Petrelli has 140,000 options to purchase Ring stock.


Report of Compensation Committee

Among the duties imposed on our Compensation Committee under its charter, is the direct responsibility and authority to review and approve the Company’s goals and objectives relevant to the compensation of the Company’s Chief Executive Officer and other executive officers, to evaluate the performance of such officers in accordance with the policies and principles established by the Compensation committee and to determine and approve, either as a Committee, or (as directed by the Board) with the other “independent” Board members (as defined by the New York Stock Exchange listing standards), the compensation level of the Chief Executive Officer and the other executive officers. During 2014 the Compensation Committee was composed of the two non-employee Directors named at the end of this report each of whom is “independent” as defined by the New York Stock Exchange listing standards.

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

Compensation Committee of the Board of Directors
Lloyd T. Rochford (Chair)
Stanley McCabe

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


    55    

Compensation Committee Interlocks and Insider Participation

The Compensation Committee members whose names appear above were committee members during 2014. No member of the Compensation Committee is or has been a former or current Named Officer of the Company. Both members of the Compensation Committee, Messrs. Rochford and McCabe, are owners of Arenaco, LLC, which is currently leasing office space to the Company in Tulsa, Oklahoma, as further described in Item 13 of this annual report. None of our Named Officers identified herein served as a director or a member of a compensation committee (or other committee serving an equivalent function) of any other entity.

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


Securities Authorized for Issuance Under Equity Compensation Plan


The following table sets forth information concerning our executive stock compensation plans as of December 31, 2014.

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) (c)
Equity compensation plans approved by security holders 2,684,500 4.67 2,136,500
Equity compensation plans not approved by security holders
Total 2,684,500 4.67 2,136,500

The Plan was in existence with Stanford and was adopted by the Board of Directors on June 27, 2012, and assumed by the Company upon the acquisition of Stanford. The Plan was subsequently approved by vote of a majority of shareholders on January 22, 2013. Information regarding the material terms of this plans may be found in this Annual Report under Part II, Item 5.

Security Ownership of Certain Beneficial Owners and Management

The following table sets forth certain information furnished by current management and others, concerning the ownership of our common stock as of March 10, 2015, 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 25,747,582 shares outstanding at March 10, 2015.
    56    

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.

Name Shares of Common Stock Beneficially Owned
Number Percent
Kelly Hoffman 362,546 (1) 1%
David A. Fowler 403,200 (2) 2%
Daniel D. Wilson 239,000 (3) 1%
William R. Broaddrick 134,000 (4) 1%
Lloyd T. Rochford 2,334,667 (5) 9%
Stanley M. McCabe 2,351,502 (6) 9%
Anthony B. Petrelli 100,000 (7) *
Clayton E. Woodrum 78,423 (8) *
All directors and executive officers as a group (9 persons) 6,013,638 (9) 23%
(1) Includes 255,000 shares issuable upon the exercise of stock options that are currently exercisable and 100,000 shares issuable upon the exercise of stock options that will be exercisable within the next 60 days.
(2) Includes 105,000 shares issuable upon the exercise of stock options that are currently exercisable and 100,000 shares issuable upon the exercise of stock options that will be exercisable within the next 60 days.
(3) Includes 64,000 shares issuable upon the exercise of stock options that are currently exercisable and 60,000 shares issuable upon the exercise of stock options that will be exercisable within the next 60 days.
(4) Includes 34,000 shares issuable upon the exercise of stock option that are current exercisable.
(5) Includes 60,000 shares issuable upon the exercise of stock options that are currently exercisable. Includes 2,220,000 shares held by a family trust controlled by Mr. Rochford.
(6) Includes 60,000 shares issuable upon the exercise of stock options that are currently exercisable. Also includes 1,646,502 shares held by a family trust controlled by Mr. McCabe.
(7) Includes 60,000 shares issuable upon the exercise of stock options that are currently exercisable.
(8) Includes 60,000 shares issuable upon the exercise of stock options that are currently exercisable.
(9) Includes 698,000 shares issuable upon the exercise of stock options that are currently exercisable and 260,000 shares issuable upon the exercise of stock options that will be exercisable within the next 60 days.

* Represents beneficial ownership of less than 1%

    57    

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

The office space being leased by the Company in Tulsa, Oklahoma, is owned by Arenaco, LLC, a company that is owned by Mr. Rochford, Chairman of the Board of the Company, and Mr. McCabe, a Director of the Company. During the years ended December 31, 2014, 2013 and 2012, the Company paid $107,000 to this company.

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

As discussed under Item 10 of this Annual Report, the Board of Directors has determined that Messrs. Woodrum and Petrelli, are each “independent” directors within the meaning the NYSE MKT, LLC definition of independent director set forth in the Company Guide, Part 8, Section 803(A). The Board has also determined that Messrs. Rochford and McCabe are “independent” directors under the same definitions. 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.

Item 14: Principal Accounting Fees and Services

The firm of Hansen, Barnett & Maxwell, P.C., (“HBM”) served as the Company’s independent auditors effective April 15, 2012. On September 1, 2013, HBM resigned as the independent registered public accounting firm of Ring Energy, Inc. and entered into an agreement with Eide Bailly LLP (“Eide Bailly”), pursuant to which Eide Bailly acquired the operations of HBM. 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 for the fiscal year ended December 31, 2013. The Audit Committee selected Eide Bailly as its independent registered public accounting firm for the fiscal year ended December 31, 2014. The Audit Committee has adopted a policy that requires advance approval of all audit, audit-related, tax services and other services performed by the independent auditor.

Fees and Independence

Audit Fees. HBM billed the Company an aggregate of $17,000 for professional services rendered for reviews of the Company’s financial statements included in its Form 10-Q’s for the 1st and 2nd quarters of 2013, and the audit of the Company’s financial statements for the year ended December 31, 2012, respectively. Eide Bailly billed the Company an aggregate of $53,500 for professional services rendered for the review of the Company’s financial statements included in its Form 10-Q for the 3rd quarter of 2013, and the audit of the Company’s financial statements for the year ended December 31, 2013 and an aggregage of $100,000 for professional services rendered for the review of the Company’s financial statements included in its Form 10-Q’s for 2014 and the audit of the Company’s financial statements for the year ended December 31, 2014.

Audit Related Fees. HBM billed the Company $1,488 for the year ended December 31, 2013 for services related to the Company’s filing of registration statements and the audit of the Kansas Property acquisition. Eide Bailly billed the Company $11,936 and $32,860, respectively, for the years ended December 31, 2014 and 2013, for services related to the Company’s filing of registration statements.
    58    

Tax Fees. Eide Bailly billed the Company $8,500 and $7,500, respectively, for professional services rendered for tax compliance, tax advice and tax planning for the years ended December 31, 2014 and 2013.

All Other Fees. No other fees were billed by HBM or Eide Bailly to the Company during 2014 and 2013.

The Audit Committee of the Board of Directors has determined that the provision of services by Eide Bailly described above is compatible with maintaining Eide Bailly’s independence as the Company’s principal accountant.

PART IV

Item 15: Exhibits, Financial Statement Schedules


(a) Financial Statements

The following financial statements are filed with this Annual Report:

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets at December 31, 2014 and 2013

Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012

Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2014, 2013 and 2012

Consolidated Statements of Cash Flows for the year ended December 31, 2014, 2013 and 2012

Notes to Consolidated Financial Statements

Supplemental Information on Oil and Gas Producing Activities
    59    

Incorporated by Reference
Exhibit Number
Exhibit Description Form File No. Exhibit Filing Date Filed
Here-with
2.1 Stock for Stock Exchange Agreement dated May 3, 2012 8-K 000-53920 2.1 7/5/12
2.1 Merger Agreement dated November 7, 2012 8-K 000-53920 2.1 1/26/12
3.1 Articles of Incorporation X
3.2 Current Bylaws 8-K 000-53920 3.2 1/24/13
10.1 Letter Agreement with Patriot Royalty & Land, LLC entered into on March 1, 2012 10-K 000-53920 10.1 3/20/12
10.2* Ring Energy Inc. Long Term Incentive Plan, as Amended 8-K 000-53920 99.3 1/24/13
10.3* Form of Option Grant for Long-Term Incentive Plan 10-Q 000-53920 10.2 8/14/12
10.4 Stanford Energy Promissory Note dated March 28, 2012 8-K 000-53920 99.1 4/3/12
10.5 Stanford Energy Promissory Note dated May 15, 2012 8-K 000-53920 99.1 5/17/12
10.6 Revolver Loan Agreement with the F&M Bank &Trust Company Dated May 12, 2011 10-Q 000-53920 10.3 8/14/12
10.7 First Amendment dated May 12, 2012, to Revolver Loan Agreement with F&M Bank & Trust Company 10-Q 000-53920 10.4 8/14/12
10.8 Second Amendment to Loan Agreement with F&M Bank & Trust Company 8-K 000-53920 99.1 1/24/13
10.9 Executive Committee Charter 10-K 000-53920 3.1 4/1/13  
10.10 Audit Committee Charter 10-K 000-53920 3.1 4/1/13  
10.11 Compensation Committee Charter 10-K 000-53920 3.1 4/1/13  
10.12 Nominating and Corporate Governance Committee Charter 10-K 000-53920 3.1 4/1/13  
10.13 Development Agreement 8-K 001-36057 10.1 10/18/13
10.14 Third Amendment to Loan Agreement with F&M Bank & Trust Company 10-Q 001-36057 10.2 11/7/13
10.15 Fourth Amendment to Loan Agreement with F&M Bank & Trust Company 10-Q 001-36057 10.3 11/7/13
10.16 Purchase and Sale Agreement, dated February 4, 2014, between Ring Energy, Inc. and Raw Oil & Gas, Inc., JDH Raw LC, and Smith Energy Company. 8-K 001-36057 10.1 2/7/14
* Management contract          
    60    

Incorporated by Reference
Exhibit Number
Exhibit Description Form File No. Exhibit Filing Date Filed
Here-with
10.17 First Amendment to First Amended and Restated Revolver Loan Agreement 10-Q 001-36057 10.17 5/8/14
10.18 Form of Subcription Agreement 8-K 001-36057 10.1 6/20/14
10.19 Credit Agreement dated July 1, 2014 with SunTrust Bank 8-K 001-36057 10.1 7/3/14  
14.1 Code of Ethics 8-K 000-53920 14.1 1/24/13
16.1 Letter dated April 19, 2012, from Haynie & Company 8-K 000-53920 16.1 4/19/12
23.1 Consent of Cawley, Gillespie & Associates, Inc. X
23.2 Consent of Eide Bailly LLC X
31.1 Rule 13a-14(a) Certification by Chief Executive Officer X
31.2 Rule 13a-14(a) Certification by Chief Financial Officer X
32.1 Section 1350 Certification of Chief Executive Officer X
32.2 Section 1350 Certification Chief Financial Officer X
99.1 Reserve Report of Cawley, Gillespie & Associates, Inc. X
101. INS XBRL Instance Document
101. SCH XBRL Taxonomy Extension Schema Document
101. CAL XBRL Taxonomy Extension Calculation Linkbase Document
101. DEF XBRL Taxonomy Extension Definition Linkbase Document
101. LAB XBRL Taxonomy Extension Label Linkbase Document
101. PRE XBRL Taxonomy Extension Presentation Linkbase Document
* Management contract          
    61    

SIGNATURES

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

Ring Energy, Inc.

By: /s/ Kelly Hoffman
Mr. Kelly Hoffman
Chief Executive Officer

Date: March 16, 2015

By: /s/ William R. Broaddrick
Mr. William R. Broaddrick
Chief Financial Officer

Date: March 16, 2015

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

/s/ Lloyd T. Rochford
Mr. Lloyd T. Rochford
Director
/s/ Anthony B. Petrelli
Mr. Anthony B. Petrelli
Director
Date: March 16, 2015 Date: March 16, 2015
   
/s/ Stanley McCabe
Mr. Stanley McCabe
Director
/s/ David A. Fowler
Mr. David A. Fowler
Director
Date: March 16, 2015 Date: March 16, 2015
   
/s/ Clayton E. Woodrum
Mr. Clayton E. Woodrum
Director
/s/ Kelly Hoffman
Mr. Kelly Hoffman
Director
Date: March 16, 2015 Date: March 16, 2015
   
    62    

RING ENERGY, INC.
INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm F-2
Consolidated Balance Sheets F-5
Consolidated Statements of Operations F-6
Consolidated Statements of Stockholders’ Equity F-7
Consolidated Statements of Cash Flows F-8/9
Notes to Consolidated Financial Statements F-10
Supplemental Information on Oil and Gas Producing Activities F-25
   
   
   

    F-1    

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM




To the Board of Directors and
Stockholders of Ring Energy, Inc.

We have audited the accompanying consolidated balance sheets of Ring Energy, Inc. and subsidiary (Ring Energy) as of December 31, 2014, and 2013, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2014. We also have audited Ring Energy’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Ring Energy’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the company’s internal control over financial reporting 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 consolidated financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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


Salt Lake City, Utah
March 20, 2014

www. e i d e b a i l l y . c om
5 Triad Center, Ste. 750 | Salt Lake City, UT 84180-1128 | T 801.532.2200 | F 801.532.7944 | EOE
    F-2    

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Ring Energy as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, Ring Energy maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).


Salt Lake City, Utah
March 16, 2015

    F-3    

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and the Shareholders
Ring Energy, Inc.

We have audited the accompanying consolidated statements of earnings, stockholders’ equity, and cash flows for the year ended December 31, 2012. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit 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 audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of their operations and their cash flows for the year ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America.

/s/ HANSEN, BARNETT & MAXWELL, P.C.
Salt Lake City, Utah
April 1, 2013



    F-4    

RING ENERGY, INC. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
As of December 31,
2013
2013
ASSETS
   
Current Assets
   
     Cash $ 8,622,235 $ 52,350,583
     Accounts receivable 3,616,402 3,888,402
     Joint interest billing receivable 2,683,787
     Prepaid expenses and retainers 160,600 66,051
     Total Current Assets 15,083,298 56,305,036
Property and Equipment    
     Oil and natural gas properties subject to amortization 166,036,400 58,040,724
     Fixed assets subject to depreciation1,209,809 1,209,809 257,911
    Total Properties and Equipment 167,246,209 58,298,635
     Accumulated depreciation, depletion and amortization (14,688,047) (2,880,253)
     Net Properties and Equipment 152,558,162 55,418,382
Total Assets $ 167,641,460 $ 111,723,418
   
LIABILITIES AND STOCKHOLDERS' EQUITY    
Current Liabilities    
     Accounts payable $ 16,241,022 $ 6,229,490
     Other accured liabilities 22,029 1,002,153
Total Current Liabilities 16,263,051 7,231,643
     Deferred income taxes 4,939,390 703,651
     Asset retirement obligations 3,896,489 1,182,410
     Total Liabilites 25,098,930 1,886,061
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;    
     25,734,467 shares and 23,576,313 shares outstanding, respectively 25,734 23,576
     Additional paid-in capital 140,532,323 109,018,165
     Retained earnings (accumulated deficit) 1,984,473 (6,436,027)
     Total Stockholders' Equity 142,542,530 102,605,714
Total Liabilities and Stockholders' Equity $ 167,641,460 $ 111,723,418
The accompanying notes are an integral part of these consolidated financial statements.
    F-5    

RING ENERGY, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
 
  For The Years Ended December 31, 2014 2013 2012
Oil and Natural Revenues $ 38,089,443 $ 10,315,701 $ 1,757,444
     
Costs and Operating Expenses
   
    Oil and gas production costs 4,993,166 1,207,529 785,959
    Oil and gas production taxes 1,760,206 476,964 82,995
    Depreciation, depletion and amortization 11,807,794 2,284,091 506,786
    Asset retirement obligation accretion 154,973 53,681 20,906
    General and administrative expenses 6,803,029 6,682,760 2,392,645
Total Costs and Operating Expenses 25,519,168 10,705,025 3,789,291
       
Income (Loss) from Operations 12.570,275   (2,031,847)
       
Other income (Expense)
     Gain on derivative put options 276,736
     Interest income 85,964 24,706 4,309
     Interest expense (9,890) (218,805)
        Net Other income 85,964 14,816 62,240
          
Income (Loss) Before Provision for Income Taxes 12,656,239 (374,508) (1,969,607)
       
(Provision for) Benefit from Income Taxes (4,235,739)    
       
Net Income (Loss) $    8,420,500 (452,209) (1,669,283)
Basic Earnings (Loss) per Share $           (0.34) $           (0.03) $           (0.21)
Diluted Earnings (Loss) per Share $           (0.33) $           (0.03) $           (0.21)
The accompanying notes are an integral part of these consolidated financial statements.
    F-6    

RING ENERGY, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
 
Successor Common Stock Additional
Paid-in
Capital
Accumulated
Deficit
Total
Stockholders'
Equity
(Deficit)
Shares Amount
Balance, December 31, 2011
3,440,000 $ 3,440 $ 204,585  $  (4,314,535) $ (4,106,510)
Share-based compensation 944,681 944,681
Common stock issued to purchase
Ring Energy, Inc.
6,579,808 6,580 13,525,180 13,531,760
Common stock issued for cash 3,148,425 3,148 13,005,914 13,009,062

Common stock issued in property acquisitions

997,778 998 4,489,003 4,490,001
Net loss (1,669,283) (1,669,283)
Balance, December 31, 2012 14,166,011 14,166 32,169,363 (5,983,818) $ 26,199,711
Share-based compensation 3,489,022 3,489,022
Common stock issued for cash 9,378,580 9,378 73,192,312 73,201,690
Common stock issued for services 10,000 10 99,990 100,000
Options exercised (cashless exercise) 6,722 7 (7)
Options exercised 15,000 15 67,485 67,500
   Net loss (452,209) (452,209)
Balance, December 31, 2013 23,576,313 $ 23,576 $ 109,018,165 (6,436,027) $ 102,605,714
Share-based compensation 2,517,211 2,517,211
Common stock issued for cash, net 2,000,001 2,000 28,512,686 28,514,686
Common stock issued for services 5,000 5 87,045 87,050
Options exercised (cashless exercise) 68,547 68 (68)
Options exercised 70,000 70 214,930 215,000
Common stock issued as consideration in property acquisitions 14,606 15 182,354   182,369
   Net loss 8,420,500 8,420,500
Balance, December 31, 2014 $ 25,734,467 $ 25,734 $ 140,532,323 $1,984,473 $ 142,542,530
The accompanying notes are an integral part of these consolidated financial statements.
    F-7    

RING ENERGY, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
  For the Years Ended December 31,2013 2014 2013 2012
Cash Flows From Operating Activities
     
   Net income (Loss) $       8,420,500 $        (452,209) $     (1,669,283)
   Adjustments to reconcile net income (loss) to
     net cash provided by (used in) operating activities:
     
     Depreciation, depletion and amortization 11,807,794 2,284,091 506,786
     Accretion expense 154,973 53,681 20,906
     Shared-based compensation 2,517,211 3,489,022 944,681
     Stock issued for services 87,050 100,000
     Gain on derivative put options (276,736)
     Deferred income tax expense (benefit) 4,235,739 77,701 (300,324)
   Changes in assets and liabilities:      
    Accounts receivable (2,412,061) (3,470,437) (326,943)
     Prepaid expenses (94,549) (5,653) 87,845
     Accounts payable 9,031,408 6,040,212 1,081,217
     Accrued compensation (100,000)
Net Cash Provided by (used in) Operating Activities 33,748,065 8,116,408 (31,851)
Cash Flows from Investing Activities      
     Payments to purchase oil and natural gas properties (15,054,649) (5,192,441) (3,684,674)
     Payments to develop oil and natural gas properties (90,160,236) (29,103,392) (6,532,898)
     Purchase of equipment, vehicles and leasehold        improvements (951,898) (82,805) (159,977)
     Plugging and abandonment cost incurred (39,316) (60,544)
     Net Cash Used in Investing Activities (106,206,099) (34,439,182) (10,377,549)
Cash Flows from Financing Activities      
     Proceeds from borrowing from Ring Energy, Inc. 1,150,000
     Proceeds from issuance of common stock 28,514,686 73,201,690 13,009,062
     Proceeds from option exercise 215,000 67,500
     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 28,729,686 73,269,190 15,802,195
Net Increase (Decrease) in Cash (43,728,348) 46,946,416 5,392,795
Cash at Beginning of Period 52,350,583 5,404,167 11,372
Cash at End of Period  $      8,622,235  $ 52,350,583  $ 5,404,167
Supplemental Cash Flow Information      
     Cash paid for interest $  9,890 $  221,927
    F-8    

RING ENERGY, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
  For the Years Ended December 31,2013 2014 2013 2012
       
Noncash Investing and Financing Activities      
  Oil and natural gas properties acquired $                    — $                    — $       9,689,488
  Deferred tax liability assumed (net) (1,362,665)
  Asset retirement obligations assumed 575,977 (152,148)
  Revision of asset retirement obligation estimate 211,691
  Asset retirement obligation incurred during development 2,022,445 481,296 (14,214)
  Payments with Ring Energy, Inc. shares 182,369 (4,490,001)
       
  Issuance of common stock to Ring Energy, Inc.      shareholders $                    — $                    — $     13,531,760
  Accounts payable assumed 9,893
  Less: Tax benefit (436,391)
  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
The accompanying notes are an integral part of these consolidated financial statements.
    F-9    

RING ENERGY, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Nature of Operations – Ring Energy, Inc. is a Nevada corporation. Ring Energy, Inc. 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 shareholders 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 had 5,786,884 shares of common stock outstanding, of which Stanford shareholders held 793,317 shares. In addition, Stanford’s shareholders obtained the right to appoint 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 shareholders 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.

Consolidation – 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.

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

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

Fair Values of Financial Instruments – The carrying amounts reported for the revolving line of credit approximates fair value because the underlying instruments are at interest rates which approximate current market rates. The carrying amounts of receivables and accounts payable and other current assets and liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities.
    F-10    

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 $8,372,235 at December 31, 2014. 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 at December 31, 2014 and 2013. 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, 2014, 2013 and 2012.

For the Years Ended December 31,
  2014 2013 2012
Depletion $ 11,680,537 $ 2,223,477 $ 474,056
Depletion rate, per
barrel-of-oil-equivalent (BOE)
$ 25.20 $ 20.27 $ 21.94

In addition, capitalized costs less accumulated amortization and related deferred income taxes shall not exceed an amount (the full cost ceiling) equal to the sum of:
1) the present value of estimated future net revenues discounted ten percent computed in compliance with SEC guidelines;
2) plus the cost of properties not being amortized;
3) plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized;
4) less income tax effects related to differences between the book and tax basis of the properties.
    F-11    

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

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

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


Depreciation expense was $127,257, $60,614 and $32,730 for the years ended December 31, 2014, 2013 and 2012, 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.

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 and Kansas income tax returns for the years ended December 31, 2011 through 2013 remain subject to examination. The Company’s franchise tax returns in Texas remain subject to examination for 2010 through 2013. 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.

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, 2014, sales to two customers represented 75% and 18%, respectively. At December 31, 2014, these two customers made up 45% and 37%, respectively, of accounts receivable. During the year ended December 31, 2013, sales to one customer represented 97% of total sales, respectively. At December 31, 2013, this one customer made up 99% of accounts receivable. 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. The loss of this customer would not have a material adverse effect on the Company as there is an available market for its crude oil and natural gas production from other purchasers.

    F-12    

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, 2014, 2013 and 2012 was $2,517,211, $3,489,022 and $944,681, respectively.

Recently Adopted Accounting Pronouncement

In May 2014, the FASB issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606). The new revenue standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. The Company must comply with this ASU beginning in fiscal year 2017 and early adoption is not permitted. Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach. The Company is currently evaluating the potential impact of this guidance.

    F-13    

NOTE 2 – EARNINGS PER SHARE INFORMATION

  For the years ended December 31, 2014 2013 2012
Net Income (Loss) $    8,420,500 $     (452,209) $   (1,669,283)
Basic weighted-average shares outstanding 24,739,795 16,376,911 8,073,176
Effect of dilutive securities:      
   Stock options 1,150,490
Diluted Weighted-Average Shares Outstanding 25,890,285 16,376,911 8,073,176
Basic Earnings (Loss) per share $            0.34 $          (0.03) $          (0.21)
Diluted Earnings (Loss) per Share $            0.33 $          (0.03) $          (0.21)

Stock options to purchase 455,500, 2,647,500 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, 2014, 2013 and 2012, respectively, as their effect would have been anti-dilutive.

NOTE 3 – OIL AND GAS PROPERTIES

Torchlight Joint Venture – On October 16, 2013, Ring Energy, Inc. (“Ring”) entered into a Joint Development Agreement (the “Agreement”), effective immediately, with Torchlight Energy Resources, Inc. (“Torchlight”), to develop Ring’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.

RAW Acquisition – In February 2014, Ring acquired additional proved developed and undeveloped oil and natural gas reserves (the “RAW Properties”) located in the Permian Basin, Andrews County, Texas. The RAW Properties consist of varied working interests (81% to 93%) and net revenue interests (61% to 70%) in eleven producing leases which included 907 net acres. The transaction also included 660 net acres of non-producing leasehold. Consideration given consisted of cash payments totaling $6,510,791. The Company incurred $20,003 in acquisition-related costs, which were recognized in general and administrative expense.

The acquisition was recognized as a business combination whereby Ring recorded the assets acquired and the liabilities assumed at their fair values as of February 27, 2014, 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 RAW Properties approximated the consideration paid, which the Company concluded approximated the fair value that would be paid by a typical market participant. The following table summarizes the fair values of the assets acquired and the liabilities assumed:

    F-14    

Proved oil and natural gas properties   $ 6,805,563
Asset retirement obligations   (294,772)
Total Identifiable Net Assets   $ 6,510,791

Subsequent to the initial acquisition, Ring spent $1,914,386 to acquire or lease additional interests in the acreage, including deeper lease rights and acquire an additional 397 net acres.

NOTE 4 – OIL AND GAS PRODUCING ACTIVITIES


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:

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

As of
December 31,
2014
As of
December 31,
2013
Proved oil and natural gas properties
$     166,036,400 $       58,040,724
Office equipment 1,209,809 257,911
Total capitalized costs 167,246,209 58,298,635
Accumulated depletion, depreciation and amortization (14,688,047) (2,880,253)
Net Capitalized Costs $     152,558,162 $       55,418,382

Net Costs Incurred in Oil and Gas Producing Activities

For the Year
Ended
December 31,
2014
For the Year
Ended
December 31,
2013
Acquisition of proved properties $       15,812,995 $          5,192,441
Development costs 92,182,681 29,796,379
Total Net Costs Incurred $     107,995,676 $        34,988,820

    F-15    

NOTE 5 – NOTES PAYABLE

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

In July 2014, the Company entered into a Credit Agreement with SunTrust Bank, as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (“Administrative Agent”) (the “Credit Facility”). The Credit Facility provides for a senior secured revolving credit facility with a maximum borrowing amount of $150 million. The Credit Facility matures on July 1, 2019, and is secured by substantially all of the Company’s assets.

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

The Credit Facility allows for Eurodollar Loans and Base Rate Loans (each as defined in the Credit Facility). The interest rate on each Eurodollar Loan will be the adjusted LIBOR for the applicable interest period plus a margin between 1.75% and 5.00% (depending on the then-current level of borrowing base usage). The annual interest rate on each Base Rate Loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the federal funds rate plus 0.5% per annum or the (iii) adjusted LIBOR determined on a daily basis for an interest period of one-month, plus 1.00% per annum, plus (b) a margin between 2.75% and 6.00% (depending on the then-current level of borrowing base usage).

The credit facility contains certain covenants, which, among other things, require the maintenance of (i) a total leverage ratio of not more than 4.0 to 1.0 and (ii) a minimum current ratio of 1.0 to 1.0. The Credit Facility also contains other customary affirmative and negative covenants and events of default. As of December 31, 2014, the Company was in compliance with all covenants.

As of December 31, 2014, no amounts are outstanding on our credit facility.
    F-16    

NOTE 6 – ASSET RETIREMENT OBLIGATION

A reconciliation of the asset retirement obligation for the years ended December 31, 2013 and 2014 is as follows:

  Balance, December 31, 2011 $ 274,788  
  Liabilities incurred
200,593  
  Accretion expense 20,906  
Balance, December 31, 2012 $ 496,286  
  Liabilities incurred 481,296  
  Revision of estimate 211,691  
  Liabilities settled (60,544)  
  Accretion expense 53,681  
Balance, December 31, 2013 $ 1,182,410  
  Liabilities acquired 575,977  
  Liabilities incurred 2,022,445  
  Liabilities settled (39,316)  
  Accretion expense 154,973  
  Balance, December 31, 2014 $ 3,896,489  

NOTE 7 – STOCKHOLDERS’ EQUITY

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 shareholders obtained control of Ring under current accounting guidance. Since the Stanford shareholders 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 shareholders. 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 Private Offering – 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.

In January 2013, the Company issued 100,000 shares of common stock, valued at $450,000, or $4.50 per share, in a private placement. There were no related offering costs.

In June 2013, the Company issued 3,528,580 shares of common stock, valued at $19,407,190, or $5.50 per share, in a private placement. Proceeds from the offering totaled $18,522,657, net of offering costs and expenses paid of $884,533.

In June 2014, the Company closed on an offering of 2,000,001 shares of common stock at $15.00 per share for gross proceeds of $30,000,015. The shares were sold without registration under the Securities Act by reason of the exemption from the registration afforded by the provisions of Section 4(a)(2) and/or Section 4(a)(5) of the Securities Act of 1933, as amended, and Rule 506 promulgated thereunder for sales of unregistered securities. Offering costs totaled $1,485,328. The Company filed a registration statement with the SEC to register such shares, which was declared effective September 3, 2014.

    F-17    

Common Stock Issued in Public Offering – In December 2013, the Company issued 5,750,000 shares of common stock, valued at $57,500,000, or $10.00 per share, in a public offering. Proceeds from the offering totaled $54,229,033, net of underwriters fees, offering costs and expenses paid totaling $3,270,967.

Common Stock Issued for Services – In October 2013, the Company issued 10,000 shares of common stock, valued at $100,000, or $10.00 per share, as compensation for services provided.

In July 2014, the Company issued 5,000 shares of common stock, valued at $87,050, or $17.41 per share, as consideration in a property acquisition.

Common Stock Issued for Option Exercises – In January 2013, the Company issued 6,722 shares of common stock as the result of the cashless exercise of 10,000 stock options with an exercise price of $2.00. The Company withheld 3,278 shares, valued at $20,000 or $6.10 per share, as the exercise price.

In December 2013, the Company issued 15,000 shares of common stock as the result of an option exercise. The options had an exercise price of $4.50 per share. The company received the $67,500 exercise price.

In January 2014, the Company issued 5,000 shares of common stock as the result of an option exercise. The Company received the exercise price of $4.50 per share for an aggregate amount of $22,500.

Also, in January 2014, the Company issued 20,361 shares of common stock as the result of the cashless exercise of 20,000 stock options with an exercise price of $2.00 and 5,000 stock options with an exercise price of $5.50. The Company withheld 4,639 shares, valued at $67,500 or $14.55 per share.

In April 2014, the Company issued 43,632 shares of common stock as the result of the cashless exercise of 42,500 stock options with an exercise price of $2.00 and 10,000 stock options with an exercise price of $4.50. The Company withheld 8,868 shares, valued at $130,000 or $14.66 per share.

In June 2014, the Company issued 307 shares of common stock as the result of the cashless exercise of 500 stock options with an exercise price of $7.50. The Company withheld 193 shares, valued at $3,750 or $19.39 per share.

In July 2014, the Company issued 65,000 shares of common stock as the result of option exercise. The options exercised included 25,000 at $4.50 per share and 40,000 at $2.00 per share. The company received the aggregate exercise price of $192,500.

Also in July 2014, the Company issued 604 shares of common stock as the result of the cashless exercise of 1,000 stock options with an exercise price of $7.50 per share. The Company withheld 396 shares, valued at $7,500 or $18.96 per share.

In November 2014, the Company issued 3,643 shares of common stock as the result of the cashless exercise of 5,000 stock options with an exercise price of $4.50 per share. The Company withheld 1,357 shares, valued at $22,500 or $16.58 per share.

Common Stock Issued as Consideration for Property 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.

    F-18    

In September 2014, the Company issued 8,783 shares of common stock, valued at $130,428, or $14.85 per share, as consideration in a property acquisition.

In December 2014, the Company issued 5,823 shares of common stock, valued at $51,941, or $8.92 per share, as consideration in property acquisitions.


NOTE 8 – EMPLOYEE STOCK OPTIONS AND RESTRICTED STOCK AWARD PLAN


In 2011, the Company’s Board of Directors approved and adopted a long term incentive plan, which was subsequently approved and amended by the shareholders. There are 2,136,500 shares eligible for grant, either as options or as restricted stock, at December 31, 2014.

Employee Stock Options – Following is a table reflecting the issuances during 2012, 2013 and 2014 and their related exercise prices:

  Grant date # of options Exercise price
July 1, 2012
75,000 $              4.50
September 1, 2012 50,000 4.50
October 1, 2012 40,000 4.50
     
January 1, 2013 1,400,000 $              4.50
February 13, 2013 25,000 4.50
March 15, 2013 150,000 4.50
June 25, 2013 35,000 7.50
December 16, 2013 100,000 10.00
     
April 11, 2014 5,000 $             16.99
September 25, 2014 23,000 14.54
October 13, 2014 2,500 13.12
November 18, 2014 45,000 12.79
December 1, 2014 293,000 8.00
  2,218,500  

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, 2014, 2013 and 2012 and changes during the years ended December 31, 2014, 2013 and 2012 is as follows:

    F-19    

  2014 2013 2012
Options Weighted-
Average
Exercise
Price
Options Weighted-
Average
Exercise
Price
Options Weighted-Average Exercise
Price
Outstanding at beginning
of the year
2,647,500 $          4.01 1,125,000 $          2.37 1,125,000 $          2.00
Issued 368,500 9.15 1,685,000 4.98 165,000 4.50
Forfeited (177,500) 5.62 (137,500) 2.55 (165,000) 2.00
Exercised (154,000) 2.90 (25,000) 3.50
           
Outstanding at end
of year
2,684,500 $          4.67 2,647,500 $          4.01 1,125,000 $          2.37
           
Exercisable at end
of year
728,000 $          3.22 662,500 $          3.13 200,000 $          2.00
           
Weighted average fair
value of options granted
during the year
  $         7.55   $          4.35   $          4.26

The Company uses the Black-Scholes option pricing model to calculate the fair-value of each option grant. The expected volatility is based on the historical price volatility of the Company’s common stock.We elected to use the simplified method for estimating the expected term as allowed by generally accepted accounting principles for options granted during the years ended December 31, 2014, 2013 and 2012. 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, 2014, 2013 and 2012:

    F-20    

 

Risk free interest rate

Expected life (years) Dividend yield Volatility
July 1, 2012
0.67% 6.5 158%
September 1, 2012 0.80% 6.5 153%
October 1, 2012 0.25% 5.75 147%
         
January 1, 2013 0.76% 6.5 138%
February 13, 2013 0.92% 6.5 137%
March 15, 2013 0.84% 6.5 132%
June 25, 2013 1.49% 6.5 128%
December 16, 2013 1.55% 6.5 119%
         
April 11, 2014 1.58% 6.5 114%
September 25, 2014 1.75% 6.5 108%
October 13, 2014 1.45% 6.5 107%
November 18, 2014 1.66% 6.5 106%
December 1, 2014 1.52% 6.5 108%

As of December 31, 2014, there was approximately $5,053,443 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, 2014 was $15,780,775. The aggregate intrinsic value of options exercisable at December 31, 2014 was $5,299,000. The year end intrinsic values are based on a December 31, 2014 closing price of $10.50.

Options exercised of 154,000 in 2014 and 25,000 in 2013, had an aggregate intrinsic value on the date of exercise of $2,159,330 and $149,000, respectively. No options were exercised during 2012.

The following table summarizes information related to the Company’s stock options outstanding at December 31, 2014:

    F-21    

Exercise price Options Outstanding
Number Outstanding Weighted-Average Remaining Contractual Life
(in years)
Number Exercisable
2.00
740,000 6.92 420,000
4.50
1,415,000 7.97 280,000
5.50 45,000 8.20
7.50 29,000 8.48 5,000
10.00 90,000 8.96 5,000
16.99
5,000 9.28 18,000
14.54
20,000 9.73
13.12 2,500 9.78
12.79 45,000 9.88
8.00 293,000 9.92
2,684,000 7.99 728,000

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, 2014, 2013 or 2012.

NOTE 9 – RELATED PARTY TRANSACTIONS


The company is leasing office space from Arenaco, LLC, a company that is owned by two of stockholders’ of the company, Mr. Rochford, Chairman of the Board of the Company, and Mr. McCabe, a Director of the Company. During the years ended December 31, 2014, 2013 and 2012, the Company paid $107,000 to this company.

The Company entered into a promissory note for $1,000,000 in January 2012 to cover $850,000 in advances from Ring Energy, Inc. to Stanford Energy, Inc. in 2011 and $150,000 in advances made during early 2012. This was settled as part of the merger in 2012.

NOTE 10 – COMMITMENTS AND CONTINGENT LIABILITIES

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, 2014. The leases pertain to approximately 15,000 square feel of space for our corporate headquarters in Midland, Texas, approximately 3,700 square feet that was our former corporate headquarters in Midland, Texas, which we have recently vacated and will attempt to sublet, 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 $167,120, $141,593 and $208,091 for the years ended December 31, 2014, 2013 and 2012, respectively. The following table reflects the future minimum lease payments under the operating lease as of December 31, 2014.

    F-22    

Year Lease Obligation
2015 465,175
2016 537,335
2017 450,935
2018 60,250
  $ 1,519,695

NOTE 11 – INCOME TAXES

For the years ended December 31, 2014, 2013 and 2012, components of our provision for income taxes are as follows:

  Provision for Income Taxes 2014 2013 2012
  Deferred Taxes $ 4,235,739 $ 77,701 $ (707,270)
  Effect of offset from Kansas
  property acquisition
406,946
  Provision for (Benefit from)
  Income Taxes
$ 4,235,739 $ 77,701 $ (300,324)

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

  Rate Reconciliation 2014 2013 2012
  Tax at federal statutory rate (34%) $ 4,303,121 $ (127,333) $ (669,666)
  Non-deductible expenses
4,465 4,450 1,098
  Excess tax benefit from stock option exercises (595,322)
  Adjust prior estimates to tax return 396,061 213,431 406,946
  States taxes, net of Federal benefit 127,414 (17,864) (93,950)
  Effect of tax rates lower than statutry rate 5,017 55,248
  Provision for (Benefit from) Income Taxes $ 4,235,739 $ 77,701) $ (300,324)

The net deferred tax liability consisted of the following at December 31, 2014 and 2013:

  Deferred Taxes: 2014 2013
  Deferred tax liabilities    
  Property and equipment $ 25,683,495 $ 9,009,106
     
  Deferred tax assets    
  Stock-based compensation 2,253,286 1,682,601
  Operating loss and IDC carryforwards 18,490,819 6,622,854
  Deferred tax assets 20,744,105 8,305,455
  Net deferred income tax liability $ 4,939,390 $ 703,651
    F-23    

As of December 31, 2014, the Company had net operating loss carry forwards for federal income tax reporting purposes of approximately $54.4 million which, if unused, will begin to expire in 2027 and fully expire in 2033.

2012
Three Months Ended
  March 31 June 30 September 30 December 31
Revenues $       328,003 $      342,522 $      374,739 $      712,180
Operating Income (Loss)
(589,127) (488,086) (652,933) (301,701)
Net Income (Loss) (630,274) (541,377) (631,453) 133,821
Basic Net Income Per Share $          (0.18) $          (0.15) $         (0.06) $           0.01
Diluted New Income Per Share (0.18) (0.15) (0.06) 0.01


2013
Three Months Ended
  March 31 June 30 September 30 December 31
Revenues $    1,151,597 $    1,291,579 $    2,820,731 $    5,051,794
Operating Income (Loss)
(965,280) (890,393) (143,735) 1,610,084
Net Income (Loss) (965,280) (890,393) (131,493) 1,534,957
Basic Net Income Per Share $          (0.07) $          (0.06) $          (0.01) $            0.08
Diluted New Income Per Share (0.07) (0.06) (0.01) 0.08


2014
Three Months Ended
  March 31 June 30 September 30 December 31
Revenues $    5,970,452 $  11,204,238 $  10,929,771 $    9,984,982
Operating Income (Loss)
1,804,352 4,459,373 2,724,204 3,582,346
Net Income (Loss) 1,163,689 2,821,738 1,726,469 2,708,604
Basic Net Income Per Share $            0.05 $            0.12 $            0.07 $            0.11
Diluted New Income Per Share 0.05 0.11 0.06 0.10

NOTE 12 – SUBSEQUENT EVENTS


Subsequent to December 31, 2014, the Company has drawn down $5,000,000.00 on its credit facility.

We have evaluated subsequent events after the balance sheet date of December 31, 2014 through the time of filing with the SEC on March 16, 2015, which is the date the financial statements were issued.
    F-24    

RING ENERGY, INC.
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
(Unaudited)


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.

For the years ended
December 31,
2014 2013 2012
Oil and gas sales $ 38,089,443 $ 10,315,701 $ 1,757,444
Production costs
(4,993,167) (1,207,529) (785,959)
Production taxes (1,760,206) (476,964) (82,995)
Depreciation, depletion,
amortization and accretion
(11,962,766) (2,337,772) (527,692)
General and administrative
(exclusive of corporate overhead)
(660,862) (646,625) (322,821)
Results of Oil and Gas
Producing Operations
$ 18,712,442 $ 5,646,811 $ 37,977

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.



    F-25    

  For the Year Ended December 31, 2014 2013
Oil (1) Natural Gas(1) Oil (1) Natural Gas (1)
Proved Developed and Undeveloped Reserves      
Beginning of year 6,855,655 2,487,042 3,646,743 1,733,780
Purchases of minerals in place 2,828,530 511,921 934,716 208,013
Improved recovery and extensions 1,273,327 117,778 2,676,934 595,729
Sale of minerals in place (16,100)
Production (456,852) (70,534) (109,673) (36,047)
Revision of previous estimate (258,369) (2,057,898) (276,965) (14,433)
         
End of year 10,242,291 988,309 6,855,655 2,487,042
         
Proved Developed at end of year 4,454,414 299,188 1,941,367 630,751
1 Oil reserves are stated in barrels; gas reserves are stated in thousand cubic feet.

  December 31, 2014 2013
Future cash flows $ 875,492,876 $ 648,958,812
Future production costs (217,842,533) (165,478,373)
Future development costs (113,073,539) (98,287,766)
Future income taxes (165,083,198) (125,104,471)
Future net cash flows 379,493,606 260,088,202
10% annual discount for estimated
timing of cash flows
(183,148,613) (126,140,275)
     
Standardized Measure of Discounted Cash Flows $ 196,344,993 $ 133,947,927
     
2014 2013
Beginning of the year $ 133,947,927 $ 71,358,446
Purchase of minerals in place 89,152,815 24,631,148
Extensions, discoveries and improved recovery,
less related costs
39,903,356 72,635,671
Development costs incurred during the year 90,562,299 29,103,392
Sales of oil and gas produced, net of production costs (33,096,276) (994,793)
Sales of minerals in place (1,039,031)
Accretion of discount 16,564,967 8,568,497
Net changes in price and production costs (30,191,382) 5,568,442
Net change in estimated future development costs (31,004,796) (6,499,395)
Revision of previous quantity estimates (15,044,380) (10,313,017)
Revision of estimated timing of cash flows (43,530,618) (29,859,746)
Net change in income taxes (20,918,919) (29,211,687)
     
End of the Year $ 196,344,993 $ 133,947,927


    F-26