United States
Securities and Exchange Commission
Washington, D.C. 20549
Form 10-K
(Mark One)
| x | Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the fiscal year ended December 31, 2016
Or
| ¨ | Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the transition period from ___________to ___________
Commission file number 001-36057
Ring Energy, Inc.
(Exact name of registrant as specified in its charter)
| Nevada | 90-0406406 |
|
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification Number) |
|
901 West Wall St, 3rd Floor Midland, TX |
79702 |
| (Address of principal executive offices) | (Zip Code) |
| (432) 682-7464 |
| (Registrant’s telephone number, including area code) |
Securities registered under Section 12(b) of the Exchange Act:
| Title of Each Class | Name of Exchange |
| Common Stock, par value $0.001 | NYSE MKT |
Securities registered under Section 12(g) of the Exchange Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically 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, 2016, the aggregate market value of the common voting stock held by non-affiliates of the issuer, based upon the closing stock price on the NYSE MKT of $8.82 per share, was approximately $327,635,570.
As of March 14, 2017, the issuer had outstanding 49,116,554 shares of common stock ($0.001 par value).
TABLE OF CONTENTS
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Forward Looking Statements
All statements, other than statements of historical fact included in this Annual Report on Form 10-K (herein, “Annual Report”) regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. All forward-looking statements speak only as of the date of this Annual Report. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
Unless the context otherwise requires, references in this Annual Report to “Ring,” “the Company,” “we,” “us,” “our” or “ours” refer to Ring Energy, Inc.
| 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 “Transglobal 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 and the Delaware Basin in Reeves County and Culberson County, Texas. As of December 31, 2016, Ring had 53,582 gross (32,663 net) acres in Andrews and Gaines counties and 20,794 gross (20,490 net) acres in Reeves and Culberson counties. The Company also has 14,647 gross (14,549 net) acres in Kansas.
As of December 31, 2016, Ring’s proved reserves were approximately 27.7 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 90% of proved reserves consisting of oil and 10% consisting of natural gas. Of those reserves, 32% of the proved reserves are classified as proved developed producing, or “PDP,” 5% are classified as proved developed non-producing, or “PDNP,” and approximately 63% are classified as proved undeveloped, or “PUD.”
Production for the year ended December 31, 2016, was approximately 878,066 BOE, as compared to production of 743,363 BOE for the year ended December 31, 2015, an 18% 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, 2016, will be credited in the first quarter of 2017.
Ring believes that there is significant value to be created by drilling the identified undeveloped opportunities on its Texas properties. As of December 31, 2016, Ring owned interests in a total of 6,925 gross (6,171 net) developed acres and 46,657 gross (26,492 net) undeveloped acres in Andrews and Gaines County, Texas. In these counties, the Company has 174 identified proven vertical drilling locations and 13 identified proven horizontal locations based on the reserve reports as of December 31, 2016, and an additional 319 identified potential vertical drilling locations based on 10-acre downspacing and 446 identified potential horizontal drilling locations based on 6 wells per section or 106 acres per well. Also as of December 31, 2016, Ring owned interests in a total of 10,350 gross (10,252 net) developed acres and 10,444 (10,238 net) undeveloped acres in Culberson and Reeves County, Texas. In these counties, the Company has 44 identified proven vertical drilling locations based on the reserve reports as of December 31, 2016 and an additional 503 potential vertical drilling locations based on 20-acre downspacing. Ring intends to grow its reserves and production through development, drilling, exploitation and exploration activities on this multi-year project inventory of identified potential drilling locations and through acquisitions that meet the Company’s strategic and financial objectives, targeting oil-weighted reserves. Ring has identified 27 wells in Andrews and Gaines County, 48 wells in Culberson and Reeves County and 1 well in Kansas that are suitable candidates for re-stimulation or recompletion, providing attractive returns with lower upfront costs.
Business Segments
Our operations are all oil and gas exploration and production related activities in the United States.
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Principal Executive Office
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
| · | Pursue strategic acquisitions with exceptional upside potential. Ring has a history of acquiring leasehold positions that it believes to have substantial resource potential and to meet its targeted returns on invested capital. Ring has historically pursued acquisitions of properties that it believes to have exploitation and development potential comparable to its existing inventory of drilling locations. The Company has developed and refined an acquisition program designed to increase reserves and complement existing core properties. Ring’s experienced team of management and engineering professionals identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties. Management intends to continue to pursue strategic acquisitions that meet the Company’s operational and financial targets. The executive team, with its extensive experience in the Permian Basin, has many relationships with operators and service providers in the region. Ring believes that leveraging its relationships will be a competitive advantage in identifying acquisition targets. Management’s proven ability to evaluate resource potential will allow Ring to successfully acquire acreage and bring out more value in the assets. | |
| · | Growing production and reserves by developing our oil-rich resource base through conventional and horizontal drilling. Over the long-term, Ring intends to 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 90% oil and 10% natural gas. Of those reserves, 32% of the proved reserves are classified as proved developed producing, or “PDP,” 5% are classified as proved developed non-producing, or “PDNP,” and approximately 63% 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. Recently, Ring has been employing horizontal drilling to some of its acreage with success and plans to continue to do so under appropriate circumstances. |
|
Through December 31, 2016, we increased our proved reserves to approximately 27.7 million BOE (barrel of oil equivalent). As of December 31, 2016, our estimated proved reserves had a pre-tax “PV10” (present value of future net revenues before income taxes discounted at 10%) of approximately $217.3 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $159.8 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.
While Ring will continue to do some development near term, such development will be more limited while commodity prices remain low and unstable. The Company will manage any development activity around its operating cash flow. |
| · | 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. |
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 located in Andrews and Gaines Counties, which is in the heart of the Central Basin Platform, and in Culberson and Reeves Counties, which is in the Delaware Basin. As of December 31, 2016, Ring has drilled 195, with 192 being vertical and 3 horizontal, wells and re-stimulated 35 existing wells on its acreage on its Central Basin Acreage and has drilled 6 wells and recompleted six existing wells on its Delaware Basin acreage. As of December 31, 2016, estimated net proved reserves were comprised of approximately 90% oil and 10% natural gas. |
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| · | De-risked Permian acreage position with multi-year vertical drilling inventory. As of December 31, 2016, Ring has drilled 201 gross operated wells across its leasehold position with a 99.5% success rate. The Company has also re-stimulated 41 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, 2016, Ring has 174 identified proven vertical drilling locations and 13 identified proven horizontal locations in Andrews and Gaines Counties and 44 identified proven vertical drilling locations in Culberson and Reeves Counties in its proved undeveloped reserves. It believes it has an additional 319 potential vertical locations based on 10-acre downspacing and an additional 319 identified potential horizontal drilling locations based on 6 wells per acre or 106 acres per well in Andrews and Gaines Counties and 503 potential vertical locations based on 20-acre downspacing in Culberson and Reeves Counties. 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 24 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. Ring’s Chief Executive Officer Kelly Hoffman has had a successful career in the Permian Basin since 1975 when he started with Amoco Production Company and found further success in West Texas when he co-founded AOCO. In addition, Chairman of the Board, Lloyd T. Rochford, and Director, Stanley M. McCabe, formed Arena Resources, Inc. (“Arena”) in 2001, which operated in the same proximate area as Ring’s Andrews and Gaines County acreage. Arena eventually sold to SandRidge Energy, Inc., in July 2010 for $1.6 billion. Ring’s management team aims to execute a similar growth strategy and development plan by leveraging its industry relationships and significant operational experience in these regions. |
| · | Concentrated acreage position with high degree of operational control. Ring 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 its acreage, Ring retains the ability to adjust its capital expenditures based on well performance and commodity price forecasts. |
Competitive Business Conditions
We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Some of our competitors possess and employ financial resources substantially greater than ours and some of our competitors employ more technical personnel. These factors can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects, and to evaluate, bid for, and purchase a greater number of properties and prospects than what our financial or technical resources permit. Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to identify, evaluate and select suitable properties and to consummate transactions in a highly competitive environment. 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 ended December 31, 2016, sales to two customers, Occidental Energy Marketing (“Oxy”) and Enterprise Crude Oil LLC (“Enterprise”) represented 50% and 42%, respectively, of oil and gas revenues. At December 31, 2016, Oxy represented 59% of our accounts receivable and Enterprise represented 32%. 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.
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Delivery Commitments
As of December 31, 2016, we were not committed to providing a fixed quantity of oil or gas under any existing contracts.
Governmental Regulations
Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability.
Regulation of Drilling and Production
The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Regulation of Transportation of Oil
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission, or the FERC, regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors. Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
Regulation of Transportation and Sale of Natural Gas
Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.
Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Therefore, we cannot provide any assurance that the less stringent regulatory approach established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.
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Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors.
Environmental Compliance and Risks
Our oil and natural gas exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Historically, most of the environmental regulation of oil and gas production has been left to state regulatory boards or agencies in those jurisdictions where there is significant gas and oil production, with limited direct regulation by such federal agencies as the Environmental Protection Agency. However, while we believe this generally to be the case for our production activities in Texas and Kansas, there are various regulations issued by the Environmental Protection Agency (“EPA”) and other governmental agencies that would govern significant spills, blow-outs, or uncontrolled emissions.
In Texas and Kansas specific oil and gas regulations apply to the drilling, completion and operations of wells, and the disposal of waste oil and salt water. There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency.
At the federal level, among the more significant laws and regulations that may affect our business and the oil and gas industry are: The Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as “CERCLA” or “Superfund; the Oil Pollution Act of 1990; the Resource Conservation and Recovery Act, also known as “RCRA,”; the Clean Air Act; Federal Water Pollution Control Act of 1972, or the Clean Water Act; and the Safe Drinking Water Act of 1974.
Compliance with these regulations may constitute a significant cost and effort for us. No specific accounting for environmental compliance has been maintained or projected by us at this time. We are not presently aware of any environmental demands, claims, or adverse actions, litigation or administrative proceedings in which either we or our acquired properties are involved in or subject to, or arising out of any predecessor operations.
In the event of a breach of environmental regulations, these environmental regulatory agencies have a broad range of alternative or cumulative remedies which include: ordering a clean-up of any spills or waste material and restoration of the soil or water to conditions existing prior to the environmental violation; fines; or enjoining further drilling, completion or production activities. In certain egregious situations the agencies may also pursue criminal remedies against us or our principal officers.
Operational Hazards and Insurance
The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.
In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed.
Current Employees
As of December 31, 2016, we had thirty 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.
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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. |
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 63%) or proved developed non-producing (approximately 5%), we will require significant additional capital to develop such properties before they may become productive. Further, because of the inherent uncertainties associated with drilling for oil and gas, some of these properties may never be developed to the extent that they result in positive cash flow. Even if we are successful in our development efforts, it could take several years for a significant portion of our undeveloped properties to be converted to positive cash flow.
While our current business plan is to fund the development costs with cash flow from our other producing properties, if such cash flow is not sufficient we may be forced to seek alternative sources for cash, through the issuance of additional equity or debt securities, increased borrowings or other means.
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:
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| · | delays imposed by or resulting from compliance with regulatory requirements; | |
| · | pressure or irregularities in geological formations; | |
| · | shortages of or delays in obtaining equipment and qualified personnel; | |
| · | equipment failures or accidents; | |
| · | adverse weather conditions; | |
| · | reductions in oil and natural gas prices; | |
| · | title problems; and | |
| · | limitations in the market for oil and natural gas. |
Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve additional risks and uncertainties in their application if compared to conventional drilling.
Our operations utilize some of the latest horizontal drilling and completion techniques as developed by us, other oil and gas exploration and production companies and our service providers. The additional risks that we face while drilling horizontally include, but are not limited to, the following:
| · | drilling wells that are significantly longer and/or deeper than more conventional wells; |
| · | landing our wellbore in the desired drilling zone; |
| · | staying in the desired drilling zone while drilling horizontally through the formation; |
| · | running our casing the entire length of the wellbore; and |
| · | being able to run tools and other equipment consistently through the horizontal wellbore. |
Risks that we face while completing our wells include, but are not limited to, the following:
| · | the ability to fracture stimulate the planned number of stages in a horizontal or lateral well bore; |
| · | the ability to run tools the entire length of the wellbore during completion operations; and |
| · | the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage. |
If our assessments of recently purchased properties are materially inaccurate, it could have a significant impact on future operations and earnings.
We have aggressively expanded our base of producing properties. The successful acquisition of producing properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including the following:
| · | the amount of recoverable reserves; | |
| · | future oil and natural gas prices; | |
| · | estimates of operating costs; | |
| · | estimates of future development costs; | |
| · | estimates of the costs and timing of plugging and abandonment; and | |
| · | potential environmental and other liabilities. |
Our assessment will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. 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.
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Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reported reserves.
In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reported reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
You should not assume that the present value of future net revenues from our reported proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. If future values decline or costs increase it could negatively impact our ability to finance operations, and individual properties could cease being commercially viable, affecting our decision to continue operations on producing properties or to attempt to develop properties. All of these factors would have a negative impact on earnings and net income, and most likely the trading price of our securities. These factors could also result in the acceleration of debt repayment and a reduction in our borrowing base under our credit facility.
Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Our prospects are in various stages of evaluation, ranging from prospects that are currently being drilled to prospects that will require substantial additional seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. This risk may be enhanced in our situation, due to the fact that a significant percentage (63%) of our proved reserves is currently proved undeveloped reserves. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data obtained by analyzing other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
| · | environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination; |
| · | abnormally pressured formations; |
| · | mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse; |
| · | fires and explosions; |
| · | personal injuries and death; and |
| · | natural disasters. |
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to our Company. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, then it could materially and adversely affect us.
| 10 |
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 $60 million borrowing base for borrowings and letters of credit. As of December 31, 2016, no amount was outstanding on our credit facility. If in the future we further utilize this facility, the level of our indebtedness could affect our operations in several ways, including the following:
| · | 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.
| 11 |
If our access to markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business.
Currently, the majority of our production is sold to marketers and other purchasers that have access to nearby pipeline facilities. However, as we begin to further develop our properties, we may find production in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking or requiring compression facilities. Such restrictions on our ability to sell our oil or natural gas could have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.
Hedging transactions may limit our potential gains.
In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we may enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. While intended to reduce the effects of volatile crude oil and natural gas prices, such transactions may limit our potential gains if crude oil and natural gas prices rise over the price established by the arrangements. As of December 31, 2016, we have not entered into any hedging arrangements with respect to our expected production.
We rely on computer and telecommunications systems, and failures in our systems or cyber security attacks could materially disrupt our business operations.
The oil and 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.
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If oil and natural gas prices decrease, we may be required to record additional write-downs of the carrying value of our oil and gas properties in the future.
We follow the full cost method of accounting for our oil and gas properties. Under the full cost method, the net book value of properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling is the estimated after tax future net revenues from proved oil and gas properties, discounted at 10% per year. Discounted future net revenues are estimated using oil and natural gas spot prices based on the average price during the preceding 12-month period determined as an un-weighted, arithmetic average of the first-day-of-the-month price for each month within such period, except for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an expense. During the years ended December 31, 2015 and 2016, we recorded non-cash write downs of $9.3 million and $56.5 million, respectively. Under SEC full cost accounting rules, any write-off recorded may not be reversed even if higher oil and natural gas prices increase the ceiling applicable to future periods. Future price decreases could result in reductions in the carrying value of such assets and an equivalent charge to earnings.
It is difficult to predict with reasonable certainty the amount of expected future impairments given the many factors impacting the ceiling test calculation including, but not limited to, future pricing, operating costs, upward or downward reserve revisions, reserve adds, and tax attributes.
Risks Relating to Our Common Stock
We have no plans to pay dividends on our common stock. Shareholders may not receive funds without selling their shares.
We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities. In addition, our credit facility prohibits us from paying dividends.
Our board of directors can, without stockholder approval, cause preferred stock to be issued on terms that adversely affect common stockholders.
Under our Articles of Incorporation, our board of directors is authorized to issue up to 50,000,000 shares of preferred stock, of which none are issued and outstanding as of the date of this Annual Report. Also, our board of directors, without shareholder approval, may determine the price, rights, preferences, privileges and restrictions, including voting rights, of those shares. If the board causes shares of preferred stock to be issued, the rights of the holders of our common stock could be adversely affected. The board’s ability to determine the terms of preferred stock and to cause its issuance, while providing desirable flexibility in connection with possible acquisitions and other corporate purposes, could have the effect of making it more difficult for a third party to acquire a majority of our outstanding voting stock. Preferred shares issued by the board of directors could include voting rights, or even super voting rights, which could shift the ability to control the company to the holders of the preferred stock. Preferred shares could also have conversion rights into shares of common stock at a discount to the market price of the common stock which could negatively affect the market for our common stock. In addition, preferred shares would have preference in the event of liquidation of the Company, which means that the holders of preferred shares would be entitled to receive the net assets of the Company distributed in liquidation before the common stock holders receive any distribution of the liquidated assets. We have no current plans to issue any shares of preferred stock.
Provisions under Nevada law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock.
In addition to the ability of the board of directors to issue preferred stock, the existence of some provisions under Nevada law could delay or prevent a change in control of the Company, which could adversely affect the price of our common stock. Nevada law imposes some restrictions on mergers and other business combinations between us and any holder of 10% or more of our outstanding common stock.
| Item 1B: | Unresolved Staff Comments |
None.
| 13 |
| 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 significant 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 strategic 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, 2016, we owned interests in a total of 18,075 gross (17,139 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, 2016, we owned interests in approximately 70,948 gross (50,563 net) undeveloped acres. While our focus will be toward growth through additional acquisitions and leasing, our long term plans include drilling wells on our existing acreage to develop the potential contained therein.
Pursuing Profitable Acquisitions
We have historically pursued acquisitions of properties that we believe to have exploitation and development potential comparable to our existing inventory of drilling locations. We have developed and refined an acquisition program designed to increase reserves and complement our existing core properties. We have an experienced team of management and engineering professionals who identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties.
Summary of Oil and Natural Gas Properties and Projects
Significant Texas Operations
Andrews and Gaines County leases – In 2011, we acquired a 100% working interest and a 75% net revenue interest in the initial leases in Andrews and Gaines counties. Since that time, we have acquired working and net revenue interests in additional producing leases and acquired additional undeveloped acreage in and around our Andrews County leases. The working interests range from 1-100% and the net revenue interests range from 1-80%. In total as of December 31, 2016, we own 53,582 gross (32,663 net), acres with 6,925 gross (6,171 net) acres developed and held by production and the remaining 46,657 gross acres (26,492 net) being undeveloped. We believe the Andrews and Gaines County leases contain a considerable number of remaining potential drilling locations. Our reserve estimates include 174 vertical and 13 horizontal PUD wells. Our reserve estimates include the capital costs required to develop these wells. Our reserve estimates also include secondary recovery (waterflood) reserves in relation to some of our Andrews County acreage.
Culberson and Reeves County leases – In 2015, we acquired properties consisting of 19,983 gross acres (19,679 net) with an average working interest of 98% and an average net revenue interest of 79%. Since that time, we have acquired additional undeveloped acreage in and around our Culberson and Reeves County leases. In total as of December 31, 2016, we own 20,794 gross (20,490 net) acres with 10,350 gross (10,252 net) acres developed and held by production and the remaining 10,444 gross (10,238 net) acres being undeveloped. We believe the Culberson and Reeves County leases contain a considerable number of remaining potential drilling locations. Our reserve estimates include 44 PUD wells. Our reserve estimates include the capital costs required to develop these wells.
Significant Kansas Operations
Kansas Properties – Gray, Finney and Haskell Counties, Kansas. We acquired a 100% working interest and an 80% net revenue interest in 9,541.5 net mineral acres and a 95% working interest and a 76% net revenue interest in 1,600 net mineral acres, along with all production. There was minimal production associated with the acquisition. 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. In total as of December 31, 2016, we own 14,647 gross (14,549 net) acres with 80 gross (716 net) acres developed and held by production and the remaining 13,847 gross (13,833 net) acres being undeveloped.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. Development on this acreage has been temporarily halted. We conducted an extensive 3D seismic analysis, which was encouraging, and we are in discussions with our partner as to how and when we wish to proceed. The Joint Development Agreement with Torchlight was unwound in 2016, and as a result, we currently own 100% of the properties previously subject to the Joint Development Agreement. There are no PUD wells from this acreage included in our reserves, but we believe this acreage has significant potential.
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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, 2016, our estimated proved reserves had a pre-tax PV10 value of approximately $217.3 million and a Standardized Measure of Discounted Future Cash Flows of approximately $159.8 million, essentially 100% of which relate to our properties in Texas. We spent approximately $146.1 million on acquisitions and capital projects during 2015 and 2016. We expect to further develop these properties through additional drilling.
The following table summarizes our total net proved reserves, pre-tax PV10 value and Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2016.
| Geographic Area | Oil (Bbl) | Natural Gas (Mcf) | Total (Boe) | Pre-Tax PV10 Value | Standardized Measure of Discounted Future Net Cash Flows | |||||||||||||||
| Texas | 24,971,300 | 16,197,349 | 27,670,858 | $ | 216,784,048 | $ | 159,206,834 | |||||||||||||
| Kansas | 27,800 | 257,500 | 70,727 | 523,200 | 588,204 | |||||||||||||||
| Total | 24,999,100 | 16,454,849 | 27,741,575 | $ | 217,307,248 | $ | 159,795,038 | |||||||||||||
Reserve Quantity Information
Our estimates of proved reserves and related valuations were based on internally prepared reports and audited by Cawley, Gillespie & Associates, Inc. or Williamson Petroluem Consultants, Inc., independent petroleum engineers. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.
Our oil and natural gas reserves are attributable solely to properties within the United States. A summary of the changes in quantities of proved (developed and undeveloped) oil and natural gas reserves is shown below.
| Oil (Bbl) | Gas (Mcf) | |||||||
| Balance, December 31, 2014 | 10,242,291 | 988,310 | ||||||
| Purchase of minerals in place | 5,561,276 | 8,775,407 | ||||||
| Improved recovery | 8,096,290 | 2,573,530 | ||||||
| Extensions and discoveries | 863,327 | 1,114,932 | ||||||
| Production | (664,611 | ) | (472,508 | ) | ||||
| Revisions of estimates | (1,786,123 | ) | (440,071 | ) | ||||
| Balance, December 31, 2015 | 22,312,450 | 12,539,600 | ||||||
| Purchase of minerals in place | - | - | ||||||
| Improved recovery | 79,130 | 60,847 | ||||||
| Extensions and discoveries | 3,635,312 | 2,305,548 | ||||||
| Production | (728,051 | ) | (900,089 | ) | ||||
| Revisions of estimates | (299,741 | ) | 2,448,943 | |||||
| Balance, December 31, 2016 | 24,999,100 | 16,454,849 | ||||||
| 15 |
Our proved oil and natural gas reserves are shown below.
| For the Years Ended December 31, | ||||||||
| 2015 | 2016 | |||||||
| Oil (Bbls) | ||||||||
| Developed | 7,167,300 | 8,479,000 | ||||||
| Undeveloped | 15,145,150 | 16,520,100 | ||||||
| Total | 22,312,450 | 24,999,100 | ||||||
| Natural Gas (Mcf) | ||||||||
| Developed | 8,541,400 | 10,481,300 | ||||||
| Undeveloped | 3,998,200 | 5,973,549 | ||||||
| Total | 12,539,600 | 16,454,849 | ||||||
| Total (Boe) | ||||||||
| Developed | 8,590,867 | 10,225,883 | ||||||
| Undeveloped | 15,811,516 | 17,515,691 | ||||||
| Total | 24,402,383 | 27,741,575 | ||||||
Standardized Measure of Discounted Future Net Cash Flows
Our standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and changes in the standardized measure as described below were prepared in accordance with generally accepted accounting principles.
Future income tax expenses are calculated by applying appropriate year-end tax rates to future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of our oil and natural gas properties.
Our reserve estimates as of December 31, 2016 are based on an average price of $39.169 for oil and $2.426 for gas compared to $48.173 for oil and $2.505 for gas as of December 31, 2015.
The standardized measure of discounted future net cash flows relating to the proved oil and natural gas reserves are shown below.
| December 31, | 2016 | 2015 | ||||||
| Future cash flows | $ | 1,019,179,570 | $ | 1,110,056,990 | ||||
| Future production costs | (318,378,291 | ) | (361,838,780 | ) | ||||
| Future development costs | (140,511,904 | ) | (127,293,170 | ) | ||||
| Future income taxes | (150,765,686 | ) | (177,647,356 | ) | ||||
| Future net cash flows | 409,523,689 | 443,277,684 | ||||||
| 10% annual discount for estimated timing of cash flows | (249,728,651 | ) | (270,591,243 | ) | ||||
| Standardized Measure of Discounted Cash Flows | $ | 159,795,038 | $ | 172,686,441 | ||||
| 16 |
The changes in the standardized measure of discounted future net cash flows relating to the proved oil and natural gas reserves are shown below.
| 2016 | 2015 | |||||||
| Beginning of the year | $ | 172,686,441 | $ | 196,344,992 | ||||
| Purchase of minerals in place | - | 121,753,192 | ||||||
| Extensions, discoveries and improved recovery, less related costs | 42,388,078 | 215,074,627 | ||||||
| Development costs incurred during the year | 43,085,217 | 28,653,794 | ||||||
| Sales of oil and gas produced, net of production costs | (19,477,828 | ) | (20,502,195 | ) | ||||
| Sales of minerals in place | - | - | ||||||
| Accretion of discount | 11,995,583 | 27,688,579 | ||||||
| Net changes in price and production costs | (59,100,870 | ) | (308,347,796 | ) | ||||
| Net change in estimated future development costs | (13,064,453 | ) | 14,823,882 | |||||
| Revision of previous quantity estimates | 1,619,437 | (28,297,019 | ) | |||||
| Revision of estimated timing of cash flows | (30,342,680 | ) | (137,051,390 | ) | ||||
| Net change in income taxes | 10,006,113 | 62,545,775 | ||||||
| End of the Year | $ | 159,795,038 | $ | 172,686,441 | ||||
Proved Reserves
We have approximately 27.7 million BOE of proved reserves, which consist of approximately 90% oil and 10% natural gas, are summarized below as of December 31, 2016, 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, 2016, our Texas proved reserves had a net pre-tax PV10 value of approximately $216.8 million and Standardized Measure of Discounted Future Net Cash Flows of approximately $159.2 million and our proved reserves in Kansas had a net pre-tax PV10 value of approximately $0.5 million and Standardized Measure of Discounted Future Net Cash Flows of approximately $0.6 million.
As of December 31, 2016, approximately 32% of the proved reserves have been classified as proved developed producing, or “PDP”. Proved developed non-producing, or “PDNP” reserves constitute approximately 5% and proved undeveloped, or “PUD”, reserves constitute approximately 63%, of the proved reserves.
Total proved reserves had a net pre-tax PV10 value as of December 31, 2016 of approximately $217.3 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $159.8 million. Approximately $91.9 million and $67.7 million, respectively, of total proved reserves are associated with the PDP reserves, which is approximately 42.3% of total proved reserves’ pre-tax PV10 value. An additional $21.4 million and $15.8 million, respectively, are associated with the PDNP reserves, which is approximately 9.9% of total proved reserves’ pre-tax PV10 value. The remaining $103.9 million and $76.3 million, respectively, are associated with PUD reserves.
Proved Undeveloped Reserves
Our reserve estimates as of December 31, 2016 include 17.5 million BOE as proved undeveloped reserves. As of December 31, 2015, our reserve estimates included approximately 15.8 million BOE as proved undeveloped reserves. Following is a description of the changes in our PUD reserves from December 31, 2015 to December 31, 2016.
Conversion of approximately 112,289 BOE of reserves from PUD to PDP or PDNP through development.
Net upward revision of approximately 1,112,328 BOE primarily as a result of improved production curves and the conversion of vertical PUD reserves to horizontal PUD reserves, all partially offset by downward revisions due to commodity prices.
Improved Recovery and Extension of approximately 704,950, primarily resulting from addition of new horizontal reserves proved up through our development.
Our proved reserves as of December 31, 2016 are summarized in the table below.
| 17 |
| 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 | 7,292,400 | 9,476,500 | 8,871,817 | 32 | % | $ | 91,576 | $ | 67,254 | $ | - | |||||||||||||||||
| PDNP | 1,158,800 | 747,300 | 1,283,350 | 5 | % | 21,277 | 15,626 | 5,369 | ||||||||||||||||||||
| PUD | 16,520,100 | 5,973,549 | 17,515,691 | 63 | % | 103,931 | 76,327 | 135,143 | ||||||||||||||||||||
| Total Proved: | 24,971,300 | 16,197,349 | 27,670,858 | 100 | % | $ | 216,784 | $ | 159,207 | $ | 140,512 | |||||||||||||||||
| Kansas: | ||||||||||||||||||||||||||||
| PDP | 17,400 | 257,500 | 60,317 | 0 | % | $ | 353 | $ | 397 | $ | - | |||||||||||||||||
| PDNP | 10,400 | - | 10,400 | 0 | % | $ | 170 | 191 | $ | - | ||||||||||||||||||
| Total Proved: | 27,800 | 257,500 | 70,717 | 0 | % | $ | 523 | $ | 588 | $ | - | |||||||||||||||||
| Total: | ||||||||||||||||||||||||||||
| PDP | 7,309,800 | 9,734,000 | 8,932,134 | 32 | % | $ | 91,929 | $ | 67,651 | $ | - | |||||||||||||||||
| PDNP | 1,169,200 | 747,300 | 1,293,750 | 5 | % | 21,447 | 15,817 | 5,369 | ||||||||||||||||||||
| PUD | 16,520,100 | 5,973,549 | 17,515,691 | 63 | % | 103,931 | 76,327 | 135,143 | ||||||||||||||||||||
| Total Proved: | 24,999,100 | 16,454,849 | 27,741,575 | 100 | % | $ | 217,307 | $ | 159,795 | $ | 140,512 | |||||||||||||||||
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 | ||||||||||||
| 2017 | 6,331,081 | 4,004,750 | 6,998,539 | $ | 64,798,140 | |||||||||||
| 2018 | 4,931,590 | 2,716,099 | 5,384,273 | 49,750,210 | ||||||||||||
| 2019 | 6,426,629 | - | 6,426,629 | 25,963,564 | ||||||||||||
| 17,689,300 | 6,720,849 | 18,809,441 | $ | 140,511,914 | ||||||||||||
Internal Controls Over Reserves Estimates
Our reserves data and estimates were compiled and prepared internally and audited by third party independent consultants, Cawley, Gillespie & Associates, Inc. or Williamson Petroleum Consultants, Inc., as described in more detail herein, in compliance with SEC definitions and guidance and in accordance with generally accepted petroleum engineering principles. The technical persons employed by Cawley, Gillespie & Associates, Inc. and Williamson Petroleum Consultants, Inc., met the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our reserves estimates are prepared by examination and evaluation of production data, production decline curves, reservoir pressure data, logs, geological data, and offset analogies. The third party independent consultants are provided full access to complete and accurate information pertaining to the property, and to all applicable personnel of the Company. Our reserves estimates and process for developing such estimates are reviewed and approved by its Vice President of Operations, Daniel D. Wilson, a petroleum engineer, and Chief Executive Officer, Kelly Hoffman, to ensure compliance with SEC disclosure and internal control requirements and to verify the independence of the third party consultants. Mr. Daniel Wilson, a petroleum engineer and businessman, has over 30 years of experience in operating, evaluating and exploiting oil and gas properties. Mr. Kelly Hoffman has over 40 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.
| 18 |
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 2016, is summarized below. The following table indicates the percentage of our estimated December 2016 average daily production of 2,551 BOE/d attributable to each state and to oil versus natural gas production.
| State | Average Daily Production | Oil | Natural Gas | |||||||||
| Texas | 99.55 | % | 99.82 | % | 98.00 | % | ||||||
| Kansas | 0.45 | % | 0.18 | % | 2.00 | % | ||||||
| Total | 100.00 | % | 100.00 | % | 100.00 | % | ||||||
Acreage
The following table summarizes gross and net developed and undeveloped acreage at December 31, 2016 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 | 17,275 | 16,423 | 57,101 | 36,730 | 74,376 | 53,153 | ||||||||||||||||||
| Kansas | 800 | 716 | 13,847 | 13,833 | 14,647 | 14,549 | ||||||||||||||||||
| Total | 18,075 | 17,139 | 70,948 | 50,563 | 89,023 | 67,702 | ||||||||||||||||||
Production History
The following table presents the historical information about our produced natural gas and oil volumes.
| Years Ended December 31, | ||||||||||||
| 2014 | 2015 | 2016 | ||||||||||
| Oil production (Bbls) | 457,039 | 664,612 | 728,051 | |||||||||
| Natural gas production (Mcf) | 38,735 | 472,509 | 900,089 | |||||||||
| Total production (Boe) | 463,495 | 743,363 | 878,066 | |||||||||
| Daily production (Boe/d) | 1,270 | 2,037 | 2,406 | |||||||||
| Average sales price: | ||||||||||||
| Oil (per Bbl) | $ | 83.04 | $ | 44.90 | $ | 39.28 | ||||||
| Natural gas (per Mcf) | 3.53 | 2.48 | 2.50 | |||||||||
| Total (per Boe) | 81.18 | 41.72 | 35.13 | |||||||||
| Average production cost (per Boe) | $ | 10.77 | $ | 13.40 | $ | 11.24 | ||||||
| Average production taxes (per Boe) | 3.80 | 1.97 | 1.71 | |||||||||
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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, 2016, in productive oil and natural gas wells by region (a net well is our percentage ownership of a gross well).
| Oil Wells | Gas wells | Total Wells | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
| Texas | 372 | 266 | - | - | 372 | 266 | ||||||||||||||||||
| Kansas | 3 | 1 | 1 | 1 | 4 | 2 | ||||||||||||||||||
| Total | 375 | 268 | 1 | 1 | 376 | 269 | ||||||||||||||||||
Drilling Activity
During 2016, we drilled 3 horizontal development wells and 9 vertical development wells in Texas. We completed and placed on production the 3 horizontal wells and 8 vertical wells, leaving 2 vertical wells drilled but not yet completed and on production as of December 31, 2016.
During 2015, we drilled 9 vertical development wells in Texas. We completed and placed on production 20 wells, leaving 1 well drilled but not yet completed and on production as of December 31, 2015. All of the wells drilled in 2015 were successful.
During 2014, we drilled 135 vertical development wells in Texas. We completed and placed on production 125 wells, leaving 12 wells drilled but not yet completed and on production at December 31, 2014. All wells drilled in Texas during 2014 were successful. Also during 2014, we drilled 7 vertical wells in Kansas. 6 of these wells were successful and 1 was a dry hole.
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 $10.77, $13.40 and $11.24 during the years ended December 31, 2014, 2015 and 2016, respectively, and our average production taxes, per BOE, were $3.80, $1.97 and $1.71 for the years ended December 31, 2014, 2015 and 2016, 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, 2014, 2015 and 2016 are shown below.
| 2015 | 2016 | |||||||||||||||
| Texas | Kansas | Texas | Kansas | |||||||||||||
| Acquisition of proved properties | $ | 78,251,263 | $ | 348,710 | $ | 9,984,809 | $ | 209,118 | ||||||||
| Acquisition of unproved properties | - | - | - | - | ||||||||||||
| Exploration costs | - | - | - | - | ||||||||||||
| Development costs | 31,606,612 | 176,257 | 26,594,671 | (40,500 | ) | |||||||||||
| Total Costs Incurred | $ | 109,857,875 | $ | 524,967 | $ | 36,579,480 | $ | 168,618 | ||||||||
| 20 |
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 sublet this space. Additionally, we lease office space in Tulsa, Oklahoma which serves as our primary accounting office consisting of approximately 3,700 square feet. We also lease office space in Andrews, Texas for a field office consisting of approximately 2,000 square feet. We expect our current office space to be adequate as we move forward.
| Item 3: | Legal Proceedings |
In the ordinary course of business, we may be, from time to time, a claimant or a defendant in various legal proceedings. We do not presently have any material litigation pending or threatened requiring disclosure under this item.
| Item 4: | Mine safety disclosures |
Not applicable.
| 21 |
| 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.” 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 sale prices of our common stock as reported on the NYSE MKT.
NYST MKT
| Period | High Sale | Low Sale | ||||||
| 1st Quarter 2015 | $ | 10.93 | $ | 8.32 | ||||
| 2nd Quarter 2015 | 13.41 | 10.40 | ||||||
| 3rd Quarter 2015 | 11.54 | 7.62 | ||||||
| 4th Quarter 2015 | 11.53 | 6.57 | ||||||
| 1st Quarter 2016 | $ | 6.83 | $ | 4.04 | ||||
| 2nd Quarter 2016 | 9.85 | 4.96 | ||||||
| 3rd Quarter 2016 | 11.01 | 7.59 | ||||||
| 4th Quarter 2016 | 13.36 | 9.23 | ||||||
| 1st Quarter 2017 (through March 14) | $ | 13.81 | $ | 9.78 | ||||
Performance Graph
The following graph compares the cumulative 5-year total return attained by stockholders on Ring’s common stock relative to the cumulative total returns of the S&P 500 index and that of a selected peer group, named below. The graph assumes a $100 investment at the closing price on December 31, 2011, and reinvestment of dividends on the date of payment without commission. This table is not intended to forecast future performance of our common stock.
| * | The peer group consists of: Callon Petroleum Company, Rex Energy Corporation, Approach Resources, Inc., Resolute Energy Corporation and Earthstone Energy, Inc., all of which are in the oil and gas exploration and production industry. |
The performance graph above is furnished and not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and will not be incorporated by reference into any registration filed under the Securities Act of 1933 unless specifically identified therein as being incorporated by reference. The performance graph is not solicitation material subject to Regulation 14A.
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Record Holders
As of March 6, 2017, there are approximately 5,566 holders of record of our common stock. As of March 14, 2017, 4,251,171 shares, or approximately 8.7%, of the 49,113,063 shares issued and outstanding as of such date are held by management or affiliated parties.
Dividend Policy
We have not paid any dividends on our common stock during the last three years, and we do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, our credit facility prohibits us from paying dividends.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets forth information concerning our executive stock compensation plans as of December 31, 2016.
| 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 | 3,358,250 | $ | 5.90 | 1,367,150 | ||||||||
| Equity compensation plans not approved by security holders | - | - | - | |||||||||
| Total | 3,358,250 | $ | 5.90 | 1,367,150 | ||||||||
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.
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Eligibility
Awards may be granted pursuant to the Plan only to persons who are eligible individuals at the time of the grant thereof or in connection with the severance or retirement of Eligible Individuals. Under the Plan, “Eligible Individuals” means (a) employees, (b) non-employee Directors and (c) any other person that the Committee designates as eligible for an Award (other than for Incentive Options) because the Person performs bona fide consulting or advisory services for the Company or any of its Subsidiaries (other than services in connection with the offer or sale of securities in a capital raising transaction).
Stock Options
Under the Plan, the plan administrator is authorized to grant stock options. Stock options may be either designated as non-qualified stock options or incentive stock options. Incentive stock options, which are intended to meet the requirements of Section 422 of the Internal Revenue Code such that a participant can receive potentially favorable tax treatment, may only be granted to employees. Therefore, any stock option granted to consultants and non-employee directors are non-qualified stock options.
Options granted under the Plan become exercisable at such times as may be specified by the plan administrator. In general, options granted to participants become exercisable in five equal annual installments, subject to the optionee’s continued employment or service with our company. However, the aggregate value (determined as of the grant date) of the shares subject to incentive stock options that may become exercisable by a participant in any year may not exceed $100,000.
Each option will be exercisable on such date or dates, during such period, and for such number of shares of common stock as shall be determined by the plan administrator on the day on which such stock option is granted and set forth in the option agreement with respect to such stock option; provided, however, the maximum term of options granted under the Plan is ten years.
Restricted Stock
Under the Plan, the plan administrator is also authorized to make awards of restricted stock. Before the end of a restricted period and/or lapse of other restrictions established by the plan administrator, shares received as restricted stock will contain a legend restricting their transfer, and may be forfeited in the event of termination of employment or upon the failure to achieve other conditions set forth in the award agreement.
An award of restricted stock will be evidenced by a written agreement between us and the participant. The award agreement will specify the number of shares of common stock subject to the award, the nature and/or length of the restrictions, the conditions that will result in the automatic and complete forfeiture of the shares and the time and manner in which the restrictions will lapse, subject to the participant’s continued employment by us, and any other terms and conditions the plan administrator imposes consistent with the provisions of the Plan. Upon the lapse of the restrictions, any legends on the shares of common stock subject to the award will be re-issued to the participant without such legend.
The plan administrator may impose such restrictions or conditions, to the vesting of such shares as it, in its absolute discretion, deems appropriate. Prior to the vesting of a share of restricted stock granted under the Plan, no transfer of a participant’s rights to such share, whether voluntary or involuntary, by operation of law or otherwise, will vest the transferee with any interest, or right in, or with respect to, such share, but immediately upon any attempt to transfer such rights, such share, and all the rights related thereto, will be forfeited by the participant and the transfer will be of no force or effect; provided, however, that the plan administrator may, in its sole and absolute discretion, vest in the participant all or any portion of shares of restricted stock which would otherwise be forfeited.
Fair Market Value
Under the Plan, “Fair Market Value” means, for a particular day, the value determined in good faith by the plan administrator, which determination shall be conclusive for all purposes of the Plan. For purposes of valuing incentive options, the fair market value of stock: (i) shall be determined without regard to any restriction other than one that, by its terms, will never lapse; and (ii) will be determined as of the time the option with respect to such stock is granted.
Transferability Restrictions
Notwithstanding any limitation on a holder’s right to transfer an award, the plan administrator may (in its sole discretion) permit a holder to transfer an award, or may cause the Company to grant an award that otherwise would be granted to an eligible individual, in any of the following circumstances: (a) pursuant to a qualified domestic relations order; (b) to a trust established for the benefit of the eligible individual or one or more of the children, grandchildren or spouse of the eligible individual; (c) to a limited partnership or limited liability company in which all the interests are held by the eligible individual and that person’s children, grandchildren or spouse; or (d) to another person in circumstances that the plan administrator believes will result in the award continuing to provide an incentive for the eligible individual to remain in the service of the Company or its subsidiaries and apply his or her best efforts for the benefit of the Company or its subsidiaries. If the plan administrator determines to allow such transfers or issuances of awards, any holder or eligible individual desiring such transfers or issuances shall make application therefore in the manner and time that the plan administrator specifies and shall comply with such other requirements as the plan administrator may require to assure compliance with all applicable laws, including securities laws, and to assure fulfillment of the purposes of 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.
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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
None.
Issuer Repurchases
We did not make any repurchases of our equity securities during the year ending December 31, 2016.
| Item 6: | Selected Financial Data |
The selected financial information set forth below is derived from our balance sheets and statements of operations as of and for the years ended December 31, 2016, 2015, 2014, 2013 and 2012. The data set forth below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes thereto included in this Annual Report.
| For the years ended December 31, | ||||||||||||||||||||
| 2016 | 2015 | 2014 | 2013 | 2012 | ||||||||||||||||
| Statement of Operations Data: | ||||||||||||||||||||
| Revenues | $ | 30,850,248 | $ | 31,013,892 | $ | 38,089,443 | $ | 10,315,701 | $ | 1,757,444 | ||||||||||
| Cost of revenues | 11,372,420 | 11,426,453 | 6,753,372 | 1,684,493 | 868,954 | |||||||||||||||
| Depreciation, depletion and amortization | 11,483,314 | 15,175,791 | 11,807,794 | 2,284,091 | 506,786 | |||||||||||||||
| Ceiling test impairment | 56,513,016 | 9,312,203 | - | - | - | |||||||||||||||
| Accretion | 487,182 | 418,384 | 154,973 | 53,681 | 20,906 | |||||||||||||||
| General and administrative | 8,027,077 | 7,995,395 | 6,803,029 | 6,682,760 | 2,392,645 | |||||||||||||||
| Net income (loss) | (37,637,687 | ) | (9,052,771 | ) | 8,420,500 | (452,209 | ) | (1,669,283 | ) | |||||||||||
| Basic income (loss) per common share | $ | (0.97 | ) | $ | (0.32 | ) | $ | 0.34 | $ | (0.03 | ) | $ | (0.21 | ) | ||||||
| Diluted income (loss) per common share | $ | (0.97 | ) | $ | (0.32 | ) | $ | 0.33 | $ | (0.03 | ) | $ | (0.21 | ) | ||||||
| As of December 31, | ||||||||||||||||||||
| 2016 | 2015 | 2014 | 2013 | 2012 | ||||||||||||||||
| Balance Sheet Data: | ||||||||||||||||||||
| Current assets | $ | 75,220,915 | $ | 8,714,491 | $ | 15,083,298 | $ | 56,305,036 | $ | 5,882,530 | ||||||||||
| Oil and gas properties subject to amortization | 250,133,965 | 269,590,374 | 166,036,400 | 58,040,724 | 23,051,904 | |||||||||||||||
| Total assets | 308,931,165 | 250,866,245 | 167,641,640 | 111,723,418 | 28,513,378 | |||||||||||||||
| Total current liabilities | 9,099,391 | 11,333,167 | 16,263,051 | 7,231,643 | 1,191,431 | |||||||||||||||
| Total long-term liabilities | 7,957,035 | 53,301,950 | 8,835,879 | 1,886,061 | 1,122,236 | |||||||||||||||
| Total Stockholders Equity | 290,540,973 | 186,231,128 | 142,542,530 | 102,605,714 | 26,199,711 | |||||||||||||||
| 25 |
Reorganization into Ring – On June 28, 2012, Ring completed the acquisition of 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.
| 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.
Business Description and Plan of Operation
Ring is currently engaged in oil and natural gas acquisition, exploration, development and production, with activities 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 strategic acquisitions of additional properties. Specifically, our business strategy is to increase our stockholders value through the following:
| · | Growing production and reserves by developing our oil-rich resource base. Our long term plan is to actively drill and develop our acreage base in an effort to maximize its value and resource potential. However, given the current environment as it relates to commodity prices, we have scaled back our development plans to associate it, to the extent possible, with our cash flows from operations. Ring’s portfolio of proved oil and natural gas reserves consists of 90% oil and 10% natural gas. Of those reserves, 32% of the proved reserves are classified as proved developed producing, or “PDP,” 5% are classified as proved developed non-producing, or “PDNP,” and approximately 63% are classified as proved undeveloped, or “PUD.” Through the conversion of undeveloped reserves to developed reserves, Ring seeks to increase production, reserves and cash flow while gaining favorable returns on invested capital. Through December 31, 2016, we increased our proved reserves to approximately 27.7 million BOE. Effectively 100% of our reserves relate to properties located in Texas. We spent approximately $146.1 million on acquisitions and capital projects during 2015 and 2016. |
| · | 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 relationships 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. |
| 26 |
Market Conditions and Commodity Prices
Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future commodity prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our drilling program, production volumes or revenues. We expect oil and natural gas to remain volatile. Additionally, the ability to find and develop sufficient amounts of natural gas and crude oil reserves at economical costs are critical to our long-term success.
Although commodity prices continued to decline during 2016 compared to 2015 and 2014, we believe we are well-positioned to manage the challenges presented in the lower commodity pricing environment, and we can endure the current cyclical downturn in the oil and gas industry and the continued volatility in current and future commodity prices by continuing our plans to manage our development activity around our operating cash flow.
Results of Operations
The following table sets forth selected operating data for the periods indicated:
| For the Years Ended December 31, | 2014 | 2015 | 2016 | |||||||||
| Net production: | ||||||||||||
| Oil (Bbls) | 457,039 | 664,612 | 728,051 | |||||||||
| Natural gas (Mcf) | 38,735 | 472,509 | 900,089 | |||||||||
| Net sales: | ||||||||||||
| Oil | $ | 37,952,888 | $ | 29,839,852 | $ | 28,599,140 | ||||||
| Natural gas | 136,555 | 1,174,040 | 2,251,108 | |||||||||
| Average sales price: | ||||||||||||
| Oil (per Bbl) | $ | 83.04 | $ | 44.90 | $ | 39.28 | ||||||
| Natural gas (per Mcf) | 3.53 | 2.48 | 2.50 | |||||||||
| Production costs and expenses | ||||||||||||
| Oil and gas production costs | $ | 4,993,166 | $ | 9,958,380 | $ | 9,867,800 | ||||||
| Production taxes | 1,760,206 | 1,468,073 | 1,504,620 | |||||||||
| Depreciation, depletion and amortization expense | 11,807,794 | 15,175,791 | 11,483,214 | |||||||||
| Ceiling test impairment | - | 9,312,203 | 56,513,016 | |||||||||
| Accretion expense | 154,972 | 418,384 | 487,182 | |||||||||
| General and administrative expenses | 6,803,029 | 7,995,395 | 8,027,077 | |||||||||
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Oil and natural gas sales. Oil and natural gas sales revenue decreased approximately $0.2 million to $30.9 million in 2016. Oil sales decreased approximately $1.2 million while natural gas sales increased approximately $1.1 million. The oil sales decrease was the result of a decrease in the average realized per barrel oil price from $44.90 in 2015 to $39.28 in 2016 partially offset by an increase in sales volume from 644,612 barrels of oil in 2015 to 728,051 barrels of oil in 2016. 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 472,509 Mcf in 2015 to 900,089 Mcf in 2016 and the average realized per Mcf gas price increased from $2.48 in 2015 to $2.50 in 2016. These per Mcf amounts are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf. The volume increases for both oil and natural gas are the result of both the acquisitions we made during the year and the result of our development of existing properties.
Oil and gas production costs. Our aggregate oil and gas production costs decreased from $9,958,380 in 2015 to $9,867,800 in 2016 and decreased on a BOE basis from $13.40 in 2015 to $11.24 in 2016. These per BOE amounts are calculated by dividing our total production costs by our total volume sold, in BOE. The decreases in the cost per BOE is the result of increased production.
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Oil and gas production taxes. Oil and gas production taxes as a percentage of oil and natural gas sales were 4.73% during 2015 and increased to 4.88% in 2016. 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 decreased by $3,692,577 to $11,483,214 in 2016. The decrease was the result of a reduction in our average depreciation, depletion and amortization rate from $20.41 per BOE during 2015 to $13.08 per BOE during 2016, partially offset by increased production volumes. The reduced rate is the result of write downs of our oil and gas properties subject to amortization and increases in our reserve volumes. These per BOE amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total volume sold, in BOE.
Ceiling Test Write-Down. The Company recorded non-cash write-downs of the carrying value of its proved oil and natural gas properties of $9,312,203 and $56,513,016 for the periods ended December 31, 2015 and 2016 as a result of ceiling test limitations, which is reflected as ceiling test impairments in the accompanying Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2015 and 2016, adjusted for market differentials, per SEC guidelines. The write-down reduced earnings in the period and will result in a lower depreciation, depletion and amortization rate in future periods.
General and administrative expenses. General and administrative expenses was relatively flat between the periods ended December 31, 2015 and 2016 with the amounts being $7,995,395 and $8,027,077, respectively.
Interest income. Interest income was $56,498 in 2016 as compared to $6,984 in 2015. The increase was the result of higher average cash on hand during 2016.
Interest expense. Interest expense decreased from $749,134 in 2015 to $649,009 in 2016. This decrease was the result of lower average balances on the credit facility between periods.
Provision for income taxes. The provision for income taxes changed from a negative provision of $5,003,713 in 2015 to a negative provision of $19,987,585 for 2016. The change is due to the Company having a larger net loss in 2016 as compared to 2015.
Net loss. Net loss increased from $9,052,771 in 2015 to $37,637,687 in 2016. The primary reason for this change is the referenced ceiling test write-down.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Oil and natural gas sales. Oil and natural gas sales revenue decreased approximately $7.1 million to $31.0 million in 2015. Oil sales decreased approximately $8.1 million while natural gas sales increased approximately $1.0 million. The oil sales decrease was the result of a decrease in the average realized per barrel oil price from $83.04 in 2014 to $44.90 in 2015 partially offset by an increase in sales volume from 457,039 barrels of oil in 2014 to 664,612 barrels of oil in 2015. 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 38,735 Mcf in 2014 to 472,509 Mcf in 2015 but was offset by a 30% decrease in the average realized per Mcf gas price from $3.53 in 2014 to $2.48 in 2015. These per Mcf amounts are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf. The volume increases for both oil and natural gas are the result of both the acquisitions we made during the year and the result of our development of existing properties.
Oil and gas production costs. Our aggregate oil and gas production costs increased from $4,993,166 in 2014 to $9,958,380 in 2015, and increased on a BOE basis from $10.77 in 2014 to $13.40 in 2015. These per BOE amounts are calculated by dividing our total production costs by our total volume sold, in BOE. These increases in both the aggregate production costs and the cost per BOE are 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 2014 and increased to 4.73% in 2015. 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 $3,367,997 to $15,175,791 in 2015. The increase was the result of an increase in production volumes, partially offset by a decrease in the average depreciation, depletion and amortization rate from $25.48 per BOE during 2014 to $20.42 per BOE during 2015. These per BOE amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total volume sold, in BOE.
Ceiling Test Write-Down. The Company recorded a $9.3 million non-cash write-down of the carrying value of its proved oil and natural gas properties for the period ended December 31, 2015 as a result of ceiling test limitations, which is reflected as ceiling test impairments in the accompanying Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2015, adjusted for market differentials, per SEC guidelines. The write-down reduced earnings in the period and will result in a lower depreciation, depletion and amortization rate in future periods. The Company did not have any write-downs related to the full cost ceiling limitation during the prior year ended December 31, 2014.
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General and administrative expenses. General and administrative expenses increased by $1,192,366 to $7,995,395 during 2015. This increase was the result of various factors, including acquisition related costs, increased office lease rent expense and compensation related costs.
Interest income. Interest income was $6,984 in 2015 as compared to $85,964 in 2014. The decrease was the result of lower average cash on hand during 2015.
Interest expense. Interest expense increased from zero in 2014 to $749,134 in 2015. This increase was the result of drawing on our credit facility during 2015, particularly in relation to our acquisition of the properties in Culberson and Reeves counties.
Provision for income taxes. The provision for income taxes changed from $4,235,739 in 2014 to a negative provision of $5,003,713 in 2015. The change is due to the Company having a net loss in 2015 versus net income in 2014.
Net income (loss). During 2015, the Company had a net loss of $9,052,771 as compared to net income of $8,420,500 during 2014. The primary reasons for this change are the referenced ceiling test write-down and reduced revenues as a result of significantly lower received commodity prices.
Liquidity and Capital Resources
Financing of Operations. We have historically funded our operations through cash available from operations and from equity offerings of our stock. Our primary sources of cash in 2016 were from funds generated from the sale of oil and natural gas production and proceeds from the issuance of common stock. These cash flows were primarily used to fund our capital expenditures.
Credit Facility. On July 1, 2014, the Company entered into a Credit Agreement with SunTrust Bank, as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (“Administrative Agent”), which was amended on May 18, 2016, June 26, 2015 and July 24, 2014 (as amended, the “Credit Facility”). The Credit Facility provides for a senior secured revolving credit facility with a maximum borrowing amount of $500 million. The Credit Facility matures on June 26, 2020, and is secured by substantially all of the Company’s assets.
In May 2016, the borrowing base (the “Borrowing Base”) was reduced from the initial $100 million to $60 million. The Borrowing Base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The Borrowing Base will be redetermined semi-annually on each May 1 and November 1, beginning November 1, 2015. The Borrowing Base will also be reduced in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and cancellation of certain hedging positions.
The Credit Facility allows for Eurodollar Loans and Base Rate Loans (each as defined in the Credit Facility). The interest rate on each Eurodollar Loan will be the adjusted LIBOR for the applicable interest period plus a margin between 1.75% and 2.75% (depending on the then-current level of borrowing base usage). The annual interest rate on each Base Rate Loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the federal funds rate plus 0.5% per annum or the (iii) adjusted LIBOR determined on a daily basis for an interest period of one-month, plus 1.00% per annum, plus (b) a margin between 2.75% and 3.75% (depending on the then-current level of borrowing base usage).
The Credit Facility contains certain covenants, which, among other things, require the maintenance of (i) a total leverage ratio 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, 2016, the Company was in compliance with all covenants contained in the Credit Facility, and no amounts were outstanding on the Credit Facility.
Cash Flows. Historically, our primary sources of cash have been from operations, equity offerings and borrowings on our Credit Facility. During 2016, 2015 and 2014, we had cash inflow from operations of $11,214,397, $9,397,552 and $33,708,749, respectively. During the three years ended December 31, 2016, we financed $218,122,518 through proceeds from the sale of stock. During 2016 and 2015, we had proceeds from drawdowns on our Credit Facility of $52,900,000. We primarily used this cash to fund our capital expenditures and development aggregating $251,295,891 over the three years ended December 31, 2016. At December 31, 2016, we had cash on hand of $71,086,381 and working capital of $66,121,524, as compared to cash on hand of $8,714,491 and negative working capital of $2,618,676 at December 31, 2015 and cash on hand $8,22,235 and negative working capital of $1,179,753 at December 31, 2014.
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Schedule of Contractual Obligations. The following table summarizes our contractual obligations for periods subsequent to December 31, 2016. The future estimated office lease payments pertain to approximately 15,000 square feet of space for our corporate headquarters in Midland, Texas, approximately 3,700 square feet for our previous office space in Midland, Texas, approximately 3,700 square feet of office space for our accounting offices in Tulsa, Oklahoma and approximately 2,000 square feet of office space for our field office in Andrews, Texas. The Company incurred lease expenses of $537,582, $526,658 and $149,872 for the years ended December 31, 2016, 2015 and 2014, respectively. The following table reflects the outstanding balance under our Credit Facility and future minimum lease payments under the operating leases as of December 31, 2016.
| Payment due by period | ||||||||||||||||||||
| Contractual Obligations | Total | Less than 1 year | 1-3 years | 3-5 years | More than 5 years | |||||||||||||||
| Credit Facility (1) | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
| Operating Lease Obligations | 711,635 | 552,335 | 159,300 | - | - | |||||||||||||||
| Total | $ | 711,635 | $ | 552,335 | $ | 159,300 | $ | - | $ | - | ||||||||||
| (1) | This table does not include future commitment fees, interest expense or other fees on this facility because they are floating rate instruments, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. |
Long-term asset retirement obligation is not included in the above table as the timing of these payments cannot be reasonably predicted.
Effects of Inflation and Pricing
The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Material changes in prices impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans and the value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. We anticipate business costs will vary in accordance with commodity prices for oil and natural gas, and the associated increase or decrease in demand for services related to production and exploration.
Off-Balance Sheet Financing Arrangements
As of December 31, 2016 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 (internal or external) associated with property acquisition, exploration and development of oil and gas reserves are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and cost of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. All of our properties are located within the continental United States.
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Write-down of Oil and Gas Properties. Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly utilizing the average of prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.
During 2016 and 2015, the Company recorded non-cash write-downs of the carrying value of the Company’s proved oil and gas properties as a result of ceiling test limitations of $56.5 million and $9.3 million, respectively, which are reflected with ceiling test and other impairments in the accompanying Statements of Operations. The Company did not have any write-downs related to the full cost ceiling limitation in 2014.
Our reserve estimates as of December 31, 2016 are based on an average price of $39.169 for oil and $2.426 for gas.
Oil and Natural Gas Reserve Quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Reserve quantities and future cash flows included in this Annual Report are prepared in accordance with guidelines established by the SEC and FASB. The accuracy of our reserve estimates is a function of:
| · | the quality and quantity of available data; | |
| · | the interpretation of that data; | |
| · | the accuracy of various mandated economic assumptions; and | |
| · | the judgments of the persons preparing the estimates. |
Our proved reserve information included in this Annual Report was based on internal reports and audited by Cawley, Gillespie & Associates, Inc. and Williamson Petroleum Consultants, 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.
Income Taxes. Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to the actual values in the period we file our tax returns.
| 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 2016 ranged from a low of $24.78 per barrel to a high of $49.43 per barrel. Natural gas prices we received during 2016 ranged from a low of $0.81 per Mcf to a high of $4.10 per Mcf. A significant decline in the prices of oil or natural gas could have a material adverse effect on our financial condition and results of operations. In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we may enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. As of December 31, 2016, the Company has not entered into any hedging or derivative instruments for our expected oil and natural gas production.
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Customer Credit Risk
Our principal exposures to credit risk is through receivables from the sale of our oil and natural gas production (approximately $3.5 million at December 31, 2016). 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 2016, sales to two customers, Oxy and Enterprise represented 50% and 42%, respectively, of oil and gas revenues. At December 31, 2016, Oxy represented 59% of our accounts receivable and Enterprise represented 32%. Due to availability of other purchasers, we do not believe the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations.
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility, which bears variable interest based upon a prime rate and is therefore susceptible to interest rate fluctuations. Changes in interest rates affect the interest earned on the Company’s cash and cash equivalents and the interest rate paid on borrowings under the Credit Facility.
As of December 31, 2016, we had no amounts outstanding on our Credit Facility. If we draw funds on this Credit Facility, interest rate changes will impact future results of operations and cash flows.
Currently, the Company does not use interest rate derivative instruments to manage exposure to interest rate changes.
Please also see Item 1A “Risk Factors” above for a discussion of other risks and uncertainties we face in our business.
| Item 8: | Financial Statements and Supplementary Data |
The financial statements and supplementary data required by this item are included beginning at page F-1 of this Annual Report.
| Item 9: | Changes in and Disagreements with Accountants and Accounting and Financial Disclosure |
None.
| Item 9A: | Controls and Procedures |
Evaluation of disclosure controls and procedures.
Our management, with the participation of our chief executive officer and chief financial officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Exchange Act. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.
Based on management’s evaluation, our chief executive officer and chief financial officer concluded that, as of December 31, 2016, 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, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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Management’s Annual Report on Internal Control Over Financial Reporting and Report of Independent Accounting Firm
Our management is responsible for establishing and maintaining adequate internal controls over financial reporting. Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
In making our assessment of internal control over financial reporting, our management used the criteria issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013). Based on our assessment, we believe that, as of December 31, 2016, 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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| 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 14, 2017. 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 | 58 | Chief Executive Officer, Director | ||
| David A. Fowler | 58 | President, Director | ||
| Daniel D. Wilson | 56 | Executive Vice President | ||
| William R. Broaddrick | 39 | Chief Financial Officer | ||
| Lloyd T. Rochford | 70 | Chairman of the Board of Directors | ||
| Stanley M. McCabe | 84 | Director | ||
| Anthony B. Petrelli | 64 | Director | ||
| Clayton E. Woodrum | 76 | 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 2016 annual shareholders’ meeting. There are no family relationships between any director or executive officer or person nominated or chosen to become a director or officer of the Company.
The following biographies describe the business experience of our executive officers and directors:
Kelly Hoffman – Chief Executive Officer and Director
Mr. Hoffman, 58, has organized the funding, acquisition and development of many oil and gas properties. He began his career in the Permian Basin in 1975 with Amoco Production Company. His responsibilities included oilfield construction, crew management, and drilling and completion operations. In the early 1990s, Mr. Hoffman co-founded AOCO and began acquiring properties in West Texas. In 1996, he arranged financing and purchased 10,000 acres in the Fuhrman Mascho field in Andrews, Texas. In the first six months, he organized a 60 well drilling and completion program resulting in a 600% increase in revenue and approximately 18 months later sold the properties to Lomak (Range Resources). In 1999, Mr. Hoffman 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 has served as our Chief Executive Officer since January 2013. Mr. Hoffman currently serves as a director of Differential Brands Inc. (NASDAQ: DFBG), a reporting company.
David A. Fowler – President and Director
Mr. Fowler, 58, 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 2001, Mr. Fowlerco-founded and became President of Simplex Energy Solutions, LLC (“Simplex”). Representing Permian Basin oil and gas independent operators, Simplex became known as the Permian Basin’s premier oil and gas divestiture firm, closing over 150 projects valued at approximately $675 million. Mr. Fowler has served as President of the Company since January 2013.
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Daniel D. Wilson – Executive Vice President
Mr. Wilson, 56, has over 30 years of experience in operating, evaluating and exploiting oil and gas properties. He has experience in production, drilling and reservoir engineering. From 1983 to 2012, Mr. Wilson was employed at Breck Operating Corporation (“Breck”), including 22 years as the Vice President and Manager of Operations. He had the responsibility for overseeing the building, operating and divestiture of two companies during this time. At Breck’s peak Mr. Wilson was responsible for over 750 wells in seven states and had an operating staff of 27 including engineers, foremen, pumpers and clerks. Mr. Wilson personally performed or oversaw all of the economic evaluations for both acquisition and banking purposes. Mr. Wilson has served as Vice President of Operations of the Company since January 2013.
William R. Broaddrick – Chief Financial Officer.
Mr. Broaddrick, 39, 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. As a result of the merger transaction between Stanford and Ring, Mr. Broaddrick became Chief Financial Officer of Ring as of July 2012.
In 1999, Mr. Broaddrick received a Bachelor’s Degree in Accounting from Langston University, through Oklahoma State University – Tulsa. Mr. Broaddrick is a Certified Public Accountant.
Lloyd T. (“Tim”) Rochford – Chairman of the Board of Directors
Mr. Rochford, 70, 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 2008, Mr. Rochford served as President, Chief Executive Officer and as a director of Arena. During that time, Arena received numerous accolades from publications such as Business Week (2007 Hot Growth Companies), Entrepreneur (2007 Hot 500), Fortune (2007, 2008, 2009 Fastest Growing Companies), Fortune Small Business (2007, 2008 Fastest Growing Companies) and Forbes (Best Small Companies of 2009). In May 2008, Mr. Rochford resigned from the position of Chief Executive Officer at Arena and accepted the position of Chairman of the Board. In his role as Chairman, Mr. Rochford continued to pursue opportunities that would enhance the then current, as well as long-term value of Arena. Through his efforts, Arena entered into a merger agreement and was acquired by another New York Stock Exchange company for $1.6 billion in July, 2010.
Stanley M. McCabe – Director
Mr. McCabe, 84, has been active in the oil and gas industry for over 30 years, primarily seeking individual oil and gas acquisition and development opportunities. In 1979 he founded and served as Chairman and Chief Executive Officer of Stanton Energy, Inc., a Tulsa, Oklahoma natural resource company specializing in contract drilling and operation of oil and gas wells. In 1990, Mr. McCabe co-founded with Mr. Rochford, Magnum Petroleum, Inc., serving as an officer and director. In 2000, Mr. McCabe co-founded Arena with Mr. Rochford and Mr. McCabe served as Chairman of the Board until 2008 and then as a director of Arena until 2010.
Anthony B. Petrelli – Director
Mr. Petrelli, 64, is President, a 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 Bachelors of Science in Business (Finance) and his Masters of Business Administration (MBA) from the University of Colorado and a Masters of Arts in Counseling from Denver Seminary.
Clayton E. Woodrum – Director
Mr. Woodrum, CPA, 76, 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.
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Our executive officers are elected by, and serve at the pleasure of, our Board of Directors. Our directors serve terms of one year each, with the current directors serving until the next annual meeting of stockholders, and in each case until their respective successors are duly elected and qualified.
Involvement in Certain Legal Proceedings
During the past ten years, there have been no events under any bankruptcy act, no criminal proceedings and no judgments, injunctions, orders or decrees material to the evaluation of the ability and integrity of any of our directors or executive officers, and none of our executive officers or directors has been involved in any judicial or administrative proceedings resulting from involvement in mail or wire fraud or fraud in connection with any business entity, any judicial or administrative proceedings based on violations of federal or state securities, commodities, banking or insurance laws or regulations, and any disciplinary sanctions or orders imposed by a stock, commodities or derivatives exchange or other self-regulatory organization.
Board Committees
Our Board of Directors has established an Audit Committee, a Compensation Committee, a Nominating and Corporate Governance Committee, and an Executive Committee, the composition and responsibilities of which are briefly described below. The charters for each of these committees shall be provided to any person without charge, upon request. The charters are also available on the Company’s website at www.ringenergy.com. Requests may be directed to Ring Energy, Inc., 6555 S. Lewis Ave., Suite 200, Tulsa, Oklahoma 74136, Attention William R. Broaddrick, or by calling (918) 499-3880.
Audit Committee
The Audit Committee’s principal functions are to assist the Board in monitoring the integrity of our financial statements, the independent auditor’s qualifications and independence, the performance of our independent auditors and our compliance with legal and regulatory requirements. The Audit Committee has the sole authority to retain and terminate our independent auditors and to approve the compensation paid to our independent auditors. The Audit Committee is also responsible for overseeing our internal audit function. The Audit Committee is comprised of Messrs. Woodrum, Petrelli and McCabe, with Mr. Woodrum acting as the chairman. Our Board of Directors determined that Mr. Woodrum qualified as “audit committee financial expert” as defined in Item 407 of Regulation S-K promulgated by the Securities and Exchange Commission (see the biographical information for Mr. Woodrum, infra, in this discussion of “Directors and Executive Officers”). Each of Messrs. Woodrum, Petrelli and McCabe further qualified as “independent” in accordance with the applicable regulations of the NYSE MKT, LLC definition of independent director set forth in the Company Guide, Part 8, Section 803(A). (see the biographical information for Messrs. Woodrum, Petrelli and McCabe, infra, in this discussion of “Directors and Executive Officers”).
Compensation Committee
The Compensation Committee’s principal function is to make recommendations regarding the compensation of the Company’s officers. In accordance with the rules of the NYSE MKT, LLC, the compensation of our chief executive officer is recommended to the Board (in a proceeding in which the chief executive officer does not participate) by the Compensation Committee. Compensation for all other officers is also recommended to the Board for determination by the Compensation Committee. The Compensation Committee is comprised of Messrs. Rochford and McCabe, with Mr. Rochford acting as the chairman.
Nominating and Corporate Governance Committee
The Nominating and Corporate Governance Committee’s principal functions are to (a) identify and recommend qualified candidates to the Board of Directors for nomination as members of the Board and its committees, and (b) develop and recommend to the Board corporate governance principles applicable to the Company. The Nominating and Corporate Governance Committee is comprised of Messrs. Rochford and McCabe, with Mr. Rochford acting as the chairman.
There have been no material changes to the procedures by which security holders may recommend nominees to our Board of Directors.
Executive Committee
The Executive Committee’s principal function is to exercise the powers and duties of the Board between Board meetings and while the Board is not in session, and implement the policy decisions of the Board. The Executive Committee is comprised of Messrs. Rochford and McCabe.
Our Board may establish other committees from time to time to facilitate our management.
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Code of Ethics
We have adopted a Code of Ethics that applies to our Chief Executive Officer, President, Chief Financial Officer, and Corporate Controller, as well as the principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions to ensure the highest standard of ethical conduct and fair dealing.
We have also adopted a Code of Business Conduct covering a wide range of business practices that applies to all of our officers, directors, and employees to help promote honest and ethical conduct. The Code of Business Conduct covers standards for professional conduct, including, among others, conflicts of interest, insider trading, confidential information, protection and proper use of Company assets, and compliance with all laws and regulations applicable to the Company’s business.
These documents are available on the Company’s website at www.ringenergy.com. We shall also provide any person without charge, upon request, a copy of the Code of Ethics or Code of Business Conduct. Requests may be directed to Ring Energy, Inc., 6555 S. Lewis Ave., Suite 200, Tulsa, Oklahoma 74136, Attention William R. Broaddrick, or by calling (918) 499-3880.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our officers and directors, and persons who own more than ten percent of a registered class of our equity securities, to file initial reports of ownership and reports of changes in ownership with the SEC. Such persons are required by SEC regulations to furnish us with copies of all Section 16(a) forms they file.
Based solely upon a review of Section 16(a) reports furnished to us for our most recent fiscal year, we know of no director, officer or beneficial owner of more than ten percent of our common stock who failed to file on a timely basis reports of beneficial ownership of the our common stock as required by Section 16(a) of the Securities Exchange Act of 1934, as amended.
| Item 11: | Executive Compensation |
Compensation Discussion & Analysis
This Compensation Discussion and Analysis (1) provides an overview of our compensation policies and programs; (2) explains our compensation objectives, policies and practices with respect to our executive officers; and (3) identifies the elements of compensation for each of the individuals identified in the following table, whom we refer to in this annual report as our “Named Executive Officers” for the fiscal year ending December 31, 2016.
| Name | Principal Position | |
| Kelly Hoffman | Chief Executive Officer, effective January 1, 2013 | |
| David A. Fowler | President, effective January 1, 2013 | |
| Daniel D. Wilson | Executive Vice President, effective January 1, 2013 | |
| William R. Broaddrick | Chief Financial Officer, effective July 1, 2012 |
This section contains a discussion of the material elements of compensation awarded to, earned by or paid to (i) all individuals serving as the Company’s principal executive officer or acting in a similar capacity during the last completed fiscal year (“PEO”), regardless of compensation level, and (ii) all individuals serving as the Company’s principal financial officer or acting in a similar capacity during the last completed fiscal year (“PFO”), regardless of compensation level. As of the end of the last completed fiscal year, the Company had two executive officers other than the PEO and PFO, and this discussion includes the material elements of compensation awarded to, earned by, or paid to such executive officers. This section omits tables and columns if there has been no compensation awarded to, earned by, or paid to any of the Named Executive Officers or directors required to be reported in such table or column in any fiscal year covered by such table.
Objectives and Philosophy of Our Executive Compensation Program
Ring strives to attract, motivate and retain high-quality executives by providing total compensation that is performance-based and competitive within the labor market in which the Company competes for executive talent as a public company. Our compensation program is intended to align the interests of management with the interests of stockholders by linking pay with performance, thereby incentivizing performance and furthering the ultimate goal of increasing stockholder value.
Setting Executive Compensation
Our current executive compensation programs are determined and approved by our Compensation Committee. The Compensation Committee takes into consideration the recommendations by our Chairman of the Board and our Chief Executive Officer as to the compensation of executive officers other than the Chief Executive Officer. None of the Named Executive Officers are members of the Compensation Committee. The Compensation Committee has the direct responsibility and authority to review and approve the Company’s goals and objectives relative to the compensation of the Named Executive Officers, and to determine and approve (either as a committee or with the other members of the Company’s Board of Directors who qualify as “independent” directors under applicable guidelines adopted by the NYSE MKT, LLC) the compensation levels of the Named Executive Officers.
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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 include three major elements: a base salary, discretionary annual bonuses and discretionary stock options grants.
General
The Company believes that each element of the executive compensation program helps to achieve one or both of the Company’s compensation objectives outlined above. Our executive’s compensation is based on individual and Company performance and designed to attract, retain and motivate highly qualified executives while creating a strong connection to financial and operational performance and stockholder value. The table below lists each material element of our executive compensation program and the compensation objective or objectives that it is designed to achieve.
| Compensation Element | Compensation Objectives | ||
| Base Salary | Attract and retain qualified executives 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 to reward and/or motivate 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 Company also awards stock options and restricted stock grants to promote long-term value creation for stockholders and to retain talented executives for an extended period.
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.
In determining 2016 executive compensation, the Compensation Committee considered the outcome of the say-on-pay vote at the most recent annual meeting as supportive of our pay practices and programs. As a result, the Compensation Committee concluded that the 2016 compensation paid to our Named Executive Officers and our overall pay practices did not require changes; although the Compensation Committee will continue to evaluate the Company’s compensation program to ensure competitiveness, the alignment of the Company’s executive compensation with stockholders’ interests and to met other compensation objectives..
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Current Executive Compensation Program Elements
Base Salaries
The Compensation Committee believes base salary is an integral element of executive compensation to provide executive officers with a base level of monthly income. Similar to most companies within the industry, our policy is to pay Named Executive Officers’ base salaries in cash. Base salary is reviewed annually by the Compensation Committee. The base salary of each Named Executive Officer is reviewed annually, with the salary of the Chief Executive Officer being established by the Compensation Committee and the salaries of the other executive officers being determined and approved by the Compensation Committee after consideration of recommendations by the Chairman of the Board and Chief Executive Officer.
Effective July 1, 2012, the Compensation Committee designated a salary of $100,000 for Mr. Broaddrick. Effective September 1, 2012 the Compensation Committee recommended an increase of $25,000 for Mr. Broaddrick.
Mr. Hoffman joined the Company effective January 1, 2013 and the Compensation Committee designated a salary of $175,000.
Mr. Fowler joined the Company effective January 1, 2013 and the Compensation Committee designated a salary of $150,000.
Mr. Wilson joined the Company effective January 1, 2013 and the Compensation Committee designated a salary of $150,000.
Annual Bonuses
The Company does not have 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 incentive bonuses are designed to provide our executive officers with an incentive to achieve the Company’s business goals and objectives. Cash bonuses are not expected to be a significant portion of the executive compensation package. Cash bonuses 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.
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 the Company’s stockholders. 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 each year from 2012 through 2016.. Messrs. Hoffman, Fowler and Wilson were granted non-qualified stock options in each year from 2013 to 2016.
Stock option grants are valued using the Black-Scholes Model and are calculated as a part of the executive compensation package for the year based on the amount of the requisite service period served. Non-qualified stock options 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 their respective hire dates. 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.
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Pension Plans, Non-Qualified Deferred Compensation Plans, Change-In-Control Arrangements and Retirement Plans
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, 2016.
Other Benefits
Our Named Executive Officers are eligible to participate in all of our employee benefit plans, such as medical, dental, vision, group life, and short and long-term disability, in each case, on the same basis as other employees, subject to applicable laws. We also provide vacation and other paid holidays to all employees, including our Named Executive Officers.
Tax Considerations
Although our Compensation Committee considers the tax and accounting treatment associated with the cash and equity grants it makes, these considerations are not dispositive. Section 162(m) of the Code places a limit of $1.0 million per person on the amount of compensation that we may deduct in any year with respect to our chief executive officer, chief financial officer and our three most highly compensated executive officers other than the chief executive officer and the chief financial officer. There is an exemption from the $1.0 million limitation for performance-based compensation that meets certain requirements. Our benefit plans are generally designed to permit compensation to be structured to meet the qualified performance-based compensation exception. To maintain flexibility in compensating Named Executive Officers in a manner designed to promote our Company goals and objectives, our Compensation Committee has not adopted a policy requiring all compensation to be deductible. The Compensation Committee retains the ability to evaluate the performance of our executive officers and to pay appropriate compensation, even if some of it may be non-deductible, to ensure competitive levels of total compensation is paid to certain individuals.
We account for stock-based awards based on their grant date fair value, as determined under FASB ASC Topic 718. In connection with its approval of stock-based awards, the Compensation Committee is cognizant of and sensitive to the impact of such awards on stockholder dilution. The Compensation Committee also endeavors to avoid stock-based awards made subject to a market condition, which may result in an expense that must be marked to market on a quarterly basis. The accounting treatment for stock-based awards does not otherwise impact the Compensation Committee’s compensation decisions.
Risk Considerations in our Overall Compensation Program
When establishing and reviewing our executive compensation program, the Compensation Committee has considered whether the program encourages unnecessary or excessive risk taking and has concluded that it does not. While behavior that may result in inappropriate risk taking cannot necessarily be prevented by the structure of compensation practices, we believe that our compensation policies and practices do not create risks that are reasonably likely to have a material adverse effect on us. Our compensation program is comprised of both fixed and incentive-based elements. The fixed compensation (i.e., base salary) provides reliable, foreseeable income that mitigates the focus of our employees on our immediate financial performance or our stock price, encouraging employees to make decisions in our best long-term interests. The incentive components are designed to be sensitive to our short-term and long-term goals, performance and stock price. In combination, we believe that our compensation structures do not encourage our officers and employees to take unnecessary or excessive risks in performing their duties. In conclusion, we believe that our compensation policies and practices for all employees, including executive officers, do not create risks that are reasonably likely to have a material adverse effect on our Company.
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Compensation of Named Executive Officers
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.
| Summary Compensation Table | ||||||||||||||||||||||
| Name and Principal Position | Year | Salary ($) | Bonus ($) | Option Awards (1) (2) ($) | All Other ($) (3) | Total ($) | ||||||||||||||||
| Kelly Hoffman, | 2016 | $ | 175,000 | $ | - | $ | 740,283 | $ | 24,000 | $ | 929,899 | |||||||||||
| Chief Executive Officer | 2015 | 175,000 | - | 260,762 | 24,000 | 459,762 | ||||||||||||||||
| 2014 | 175,000 | - | 196,728 | 24,000 | 395,728 | |||||||||||||||||
| David Fowler, | 2016 | 150,000 | - | 496,650 | 24,000 | 661,266 | ||||||||||||||||
| President | 2015 | 150,000 | - | 260,762 | 24,000 | 434,762 | ||||||||||||||||
| 2014 | 150,000 | - | 196,728 | 24,000 | 370,728 | |||||||||||||||||
| Daniel D. Wilson, | 2016 | 150,000 | - | 496,477 | - | 637,266 | ||||||||||||||||
| Executive Vice President | 2015 | 150,000 | - | 238,167 | - | 388,167 | ||||||||||||||||
| 2014 | 150,000 | - | 163,940 | - | 313,940 | |||||||||||||||||
| William R. Broaddrick, | 2016 | 125,000 | - | 398,024 | - | 514,813 | ||||||||||||||||
| Chief Financial Officer | 2015 | 125,000 | - | 238,167 | - | 363,167 | ||||||||||||||||
| 2014 | 125,000 | - | 163,940 | - | 288,940 | |||||||||||||||||
(1) See discussion of assumptions made in valuing these awards in the notes to our financial statements.
(2) On December 9, 2015, Ring issued option awards to its named executive officers and directors. On January 13, 2016, upon the recommendation of the Compensation Committee, Ring rescinded the option awards granted to its employees and directors (other than Messrs McCabe and Rochford, who are the members of the Compensation Committee) as the result of a significant decline in the stock price and re-issued the the option awards as of that date to meet the goals and objectives of the Company’s equity based compensation program. The amounts shown as Option Awards includes the additional fair value of the new options over the original grant.
(3) Other Compensation for Mssrs. Hoffman and Fowler consists of $24,000 in directors fees.
The Company awards stock options to key employees and the Named Executive Officers either on the initial date of employment or based on performance incentives throughout the year. The following table reflects the stock options granted during 2016.
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| Grants of Plan-Based Awards | ||||||||||||||
| Name | Grant Date | All Other Option Awards: Number of Securities Underlying Options (#) | Exercise or Base Price of Option Awards ($) | Fair Value on Grant Date (1) | ||||||||||
| Kelly Hoffman | 1/13/2016 | 40,000 | $ | 5.25 | $ | 9,384 | ||||||||
| David Fowler | 1/13/2016 | 40,000 | 5.25 | 9,384 | ||||||||||
| Daniel D. Wilson | 1/13/2016 | 35,000 | 5.25 | 8,211 | ||||||||||
| William R. Broaddrick | 1/13/2016 | 35,000 | 5.25 | 8,211 | ||||||||||
| Kelly Hoffman | 12/13/2016 | 50,000 | 11.75 | 260,762 | ||||||||||
| David Fowler | 12/13/2016 | 75,000 | 11.75 | 260,762 | ||||||||||
| Daniel D. Wilson | 12/13/2016 | 50,000 | 11.75 | 238,167 | ||||||||||
| William R. Broaddrick | 12/13/2016 | 40,000 | 11.75 | 238,167 | ||||||||||
(1) On December 9, 2015, Ring issued option awards to its named executive officers and directors. On January 13, 2016, upon the recommendation of the Compensation Committee, Ring rescinded the option awards granted to its employees and directors (other than Messrs McCabe and Rochford, who are the members of the Compensation Committee) as the result of a significant decline in the stock price and re-issued the the option awards as of that date to meet the goals and objectives of the Company’s equity based compensation program. The Fair Value reflected is the additional fair value of the new options over the original grant.
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, 2016.
| Outstanding Equity Awards | ||||||||||||||||
| Name | Number of Securities Underlying Unexercised Options (#) Exercisable | Number of Securities Underlying Unexercised Options (#) Unexercisable | Options Exercise Price ($) | Option Grant Date | Option Expiration Date | |||||||||||
| Kelly Hoffman | 230,000 | - | $ | 2.00 | 12/01/11 | 12/01/21 | ||||||||||
| 300,000 | 200,000 | 4.50 | 01/01/13 | 01/01/23 | ||||||||||||
| 15,000 | 10,000 | 10.00 | 12/16/13 | 12/16/23 | ||||||||||||
| 12,000 | 18,000 | 8.00 | 12/01/14 | 12/01/24 | ||||||||||||
| - | 40,000 | 5.25 | 01/13/16 | 01/13/26 | ||||||||||||
| - | 75,000 | 11.75 | 12/13/16 | 12/13/26 | ||||||||||||
| David Fowler | 300,000 | 200,000 | 4.50 | 01/01/13 | 01/01/23 | |||||||||||
| 15,000 | 10,000 | 10.00 | 12/16/13 | 12/16/23 | ||||||||||||
| 12,000 | 18,000 | 8.00 | 12/01/14 | 12/01/24 | ||||||||||||
| - | 40,000 | 5.25 | 01/13/16 | 01/13/26 | ||||||||||||
| - | 50,000 | 11.75 | 12/13/16 | 12/13/26 | ||||||||||||
| Daniel D. Wilson | 180,000 | 120,000 | 4.50 | 01/01/13 | 01/01/23 | |||||||||||
| 12,000 | 8,000 | 10.00 | 12/16/13 | 12/16/23 | ||||||||||||
| 10,000 | 15,000 | 8.00 | 12/01/14 | 12/01/24 | ||||||||||||
| - | 35,000 | 5.25 | 01/13/16 | 01/13/26 | ||||||||||||
| - | 50,000 | 11.75 | 12/13/16 | 12/13/26 | ||||||||||||
| William R. Broaddrick | 60,000 | - | 2.00 | 12/01/11 | 12/01/21 | |||||||||||
| 30,000 | 10,000 | 4.50 | 01/01/13 | 09/01/22 | ||||||||||||
| 12,000 | 8,000 | 10.00 | 12/16/13 | 12/16/23 | ||||||||||||
| 10,000 | 15,000 | 8.00 | 12/01/14 | 12/01/24 | ||||||||||||
| - | 35,000 | 5.25 | 01/13/16 | 01/13/26 | ||||||||||||
| - | 40,000 | 11.75 | 12/13/16 | 12/13/26 | ||||||||||||
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.
The following table provides information regarding options exercised by Named Executive Officers during 2014 and 2015.
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Option Exercises and Stock Vesting
| Option Awards | ||||||||||||
| Year | Name | Number of Shares Acquired on Exercise (#) | Value Realized on Exercise ($) | |||||||||
| 2014 | William R. Broaddrick | 50,000 | $ | 809,000 | ||||||||
| 2015 | Kelly Hoffman | 20,000 | 325,600 | |||||||||
There were no option exercises by Named Executive Officers during 2016.
Director Compensation
All directors receive a monthly stipend of $2,000. In 2016, each outside director also received 50,000 stock options with an exercise price of $11.75 per share as an annual bonus. Mr. Rochford received an additional 100,000 stock options with an exercise price of $11.75 per share as additional compensation as Chariman. Additionally, as referenced below, Mssrs. Fowler, Hoffman, Woodrum and Petrelli received 25,000 stock options with an exercise price of $5.25 per share as part of a decision to rescind options granted in December 2015. Director compensation to Messrs. Fowler and Hoffman is included here but is also included in the executive compensation schedule above. No director receives a salary as a director.
Director Compensation Table
| Name | Fees Earned or Paid in Cash ($) | Option Awards ($) (1) | All Other Compensation ($) | Total ($) | ||||||||||||||
| Lloyd T. Rochford | (2) | $ | 24,000 | $ | 1,461,797 | $ | - | $ | 1,485,797 | |||||||||
| Stanley M. McCabe | (3) | 24,000 | 487,266 | - | 511,266 | |||||||||||||
| David A. Fowler | (4) | 24,000 | 496,650 | (8) | - | 520,650 | ||||||||||||
| Kelly Hoffman | (5) | 24,000 | 740,283 | (8) | - | 764,283 | ||||||||||||
| Clayton E. Woodrum | (6) | 24,000 | 487,266 | (8) | - | 511,266 | ||||||||||||
| Anthony B. Petrelli | (7) | 24,000 | 487,266 | (8) | - | 511,266 | ||||||||||||
(1) See discussion of assumptions made in valuing these awards in the notes to our financial statements.
(2) Lloyd T. Rochford has 315,000 options to purchase Ring stock.
(3) Stanley McCabe has 215,000 options to purchase Ring stock.
(4) David A. Fowler has an aggregate of 655,000 options to purchase Ring stock.
(5) Kelly Hoffman has an aggregate of 900,000 options to purchase Ring stock.
(6) Clayton E. Woodrum has 215,000 options to purchase Ring stock.
(7) Anthony B. Petrelli has 215,000 options to purchase Ring stock.
(8) On December 9, 2015, Ring issued option awards to its named executive officers and directors. On January 13, 2016, upon the recommendation of the Compensation Committee, Ring rescinded the option awards granted to its employees and directors (other than Messrs McCabe and Rochford, who are the members of the Compensation Committee) as the result of a significant decline in the stock price and re-issued the the option awards as of that date to meet the goals and objectives of the Company’s equity based compensation program. The amounts shown as Option Awards includes the additional fair value of the new options over the original grant.
Compensation Committee Report
Among the duties imposed on our Compensation Committee under its charter, is the direct responsibility and authority to review and approve the Company’s goals and objectives relevant to the compensation of the Company’s Chief Executive Officer and other executive officers, to evaluate the performance of such officers in accordance with the policies and principles established by the Compensation Committee and to determine and approve, either as a Committee, or (as directed by the Board) with the other “independent” Board members (as defined by the NYSE MKT listing standards), the compensation level of the Chief Executive Officer and the other executive officers. During 2016 the Compensation Committee was comprised of the two non-employee Directors named at the end of this report each of whom is “independent” as defined by the NYSE MKT listing standards.
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The Compensation Committee has reviewed and discussed with management the disclosures contained in the Compensation Discussion and Analysis section of this Item 11, as required by Item 402(b) of Regulation S-K. Based upon this review and our discussions, the Compensation Committee recommended to its Board of Directors that the Compensation Discussion and Analysis section be included in this annual report on Form 10-K for the fiscal year ended December 31, 2016.
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.
Compensation Committee Interlocks and Insider Participation
As of December 31, 2016, the Compensation Committee was comprised of two directors, Messrs. Rochford and McCabe, with Mr. Rochford acting as the chairman. Messrs. Rochford and McCabe are currently serving as the members of the Compensation Committee. Neither of our directors who currently serve as members of our Compensation Committee is, or has at any time in the past been, an officer or employee of the Company or any of its subsidiaries. The office space being leased by the Company in Tulsa, Oklahoma, is owned by Arenaco, LLC, a company that is 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 through December 31, 2016, the Company paid an aggregate of $180,000 to Arenaco, LLC.
None of our executive officers serves, or has served, during the last completed fiscal year, on the compensation committee or board of directors of any other company that has one or more executive officers serving on our Compensation Committee or Board.
| Item 12: | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
Securities Authorized for Issuance Under Equity Compensation Plan
The following table sets forth information concerning our executive stock compensation plans as of December 31, 2016.
| 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 | 3,358,250 | $ | 5.90 | 1,367,150 | ||||||||
| Equity compensation plans not approved by security holders | - | - | - | |||||||||
| Total | 3,358,250 | $ | 5.90 | 1,367,150 | ||||||||
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 14, 2017, of (i) each person who is known to us to be the beneficial owner of more than five 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 in the table below is our corporate headquarters. The percentage ownership is based on 49,116,554 shares outstanding at March 14, 2017.
| 44 |
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.
| Shares of Common Stock Beneficially Owned | ||||||||
| Name | Number | Percent | ||||||
| Kelly Hoffman | 672,546 | (1) | 1 | % | ||||
| David A. Fowler | 608,200 | (2) | 1 | % | ||||
| Daniel D. Wilson | 384,000 | (3) | 1 | % | ||||
| William R. Broaddrick | 219,000 | (4) | * | |||||
| Lloyd T. Rochford | 2,136,000 | (5) | 4 | % | ||||
| Stanley M. McCabe | 1,917,502 | (6) | 4 | % | ||||
| Anthony B. Petrelli | 166,000 | (7) | * | |||||
| Clayton E. Woodrum | 137,923 | (8) | * | |||||
| All directors and executive officers as a group (8 persons) | 6,241,171 | (9) | 13 | % | ||||
| * | Represents beneficial ownership of less than 1% |
| (1) | Includes 665,000 shares issuable upon the exercise of stock options that are currently exercisable. |
| (2) | Includes 433,000 shares issuable upon the exercise of stock options that are currently exercisable. |
| (3) | Includes 269,000 shares issuable upon the exercise of stock options that are currently exercisable. |
| (4) | Includes 119,000 shares issuable upon the exercise of stock options that are currently exercisable. |
| (5) | Includes (i) 126,000 shares issuable upon the exercise of stock options that are currently exercisable and (ii) 1,990,000 shares held by a family trust controlled by Mr. Rochford. |
| (6) | Includes (i) 126,000 shares issuable upon the exercise of stock options that are currently exercisable and (ii) 1,646,502 shares held by a family trust controlled by Mr. McCabe. |
| (7) | Includes 126,000 shares issuable upon the exercise of stock options that are currently exercisable. |
| (8) | Includes 126,000 shares issuable upon the exercise of stock options that are currently exercisable. |
| (9) | Includes 1,990,000 shares issuable upon the exercise of stock options that are currently exercisable. |
Changes in Control
There are no arrangements known to us, including any pledge by any person of our securities, the operation of which may at a subsequent date result in a change in control of the Company.
| Item 13: | Certain Relationships and Related Transactions, and Director Independence |
Transactions with Related Persons
The office space being leased by the Company in Tulsa, Oklahoma, is owned by Arenaco, LLC, a company that is owned by Mr. Rochford, Chairman of the Board of the Company, and Mr. McCabe, a Director of the Company. During the years ended December 31, 2016, 2015 and 2014, the Company paid an aggregate of $180,000 to Arenaco, LLC for the lease of the office space.
The Audit Committee reviews any related party transactions. Annually each Board member is required to submit an Independence Certificate, disclosing any affiliations or relationships for evaluation as related party transactions.
| 45 |
Review, Approval or Ratification of Transactions with Related Parties
The Board of Directors reviews and approves all relationships and transactions in which it and its directors, director nominees and executive officers and their immediate family members, as well as holders of more than 5% of any class of its voting securities and their family members, have a direct or indirect material interest. In approving or rejecting such proposed relationships and transactions, the Board shall consider the relevant facts and circumstances available and deemed relevant to this determination. In each case the standard applied in approving the transaction is the best interests of the Company without regard to the interests of the individual officer or director involved in the transaction. These procedures for reviewing and approving conflict of interest transactions are based on the Company’s past practice and are not contained in any written policy.
Director Independence
The standards relied upon by the Board in determining whether a director is “independent” are those set forth in the rules of the NYSE MKT. The NYSE MKT generally defines the term “independent director” as a person other than an executive officer or employee of a company, who does not have a relationship with the company that would interfere with the director’s exercise of independent judgment in carrying out the responsibilities of a director. Because the Board of Directors believes it is not possible to anticipate or provide for all circumstances that might give rise to conflicts of interest or that might bear on the materiality of a relationship between a director and the Company, the Board has not established specific objective criteria, apart from the criteria set forth in the NYSE MKT, LLC rules, to determine “independence”. In addition to such criteria, in making the determination of “independence”, the Board of Directors considers such other matters including (i) the business and non-business relationships that each independent director has or may have had with the Company and its other Directors and executive officers, (ii) the stock ownership in the Company held by each such Director, (iii) the existence of any familial relationships with any executive officer or Director of the Company, and (iv) any other relevant factors which could cause any such Director to not exercise his independent judgment.
Consistent with these standards, 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.
| 46 |
| Item 14: | Principal Accounting Fees and Services |
The Audit Committee selected Eide Bailly as its independent registered public accounting firm for the fiscal years ended December 31, 2014, 2015 and 2016. The Audit Committee has adopted a policy that requires advance approval of all audit, audit-related, tax services and other services performed by the independent auditor.
Fees and Independence
Audit Fees. Eide Bailly billed the Company an aggregage of $105,000 for professional services rendered for the review of the Company’s financial statements included in its Form 10-Q’s for 2015 and the audit of the Company’s financial statements for the year ended December 31, 2015 and an aggregate of $105,000 for professional services rendered for the review of the Company’s financial statements included in its Form 10-Q’s for 2016 and the audit of the Company’s financial statements for the year ended December 31, 2016.
Audit Related Fees. Eide Bailly billed the Company $19,100 and $21,325, respectively, for the years ended December 31, 2016 and 2015 for services related to the Company’s filing of registration statements and $27,467 in 2015 for property audits in relation to an acquisition.
Tax Fees. Eide Bailly billed the Company $18,250 and $10,000, respectively, for professional services rendered for tax compliance, tax advice and tax planning for the years ended December 31, 2016 and 2015.
All Other Fees. No other fees were billed by Eide Bailly to the Company during 2016 and 2015.
The Audit Committee of the Board of Directors has determined that the provision of services by Eide Bailly described above is compatible with maintaining Eide Bailly’s independence as the Company’s principal accountant. The policy of the Audit Committee and our Board, as applicable, is to pre-approve all services by our independent registered public accounting firm. The Audit Committee has adopted a pre-approval policy that provides guidelines for the audit, audit-related, tax and other non-audit services that may be provided by our independent registered public accounting firm. The policy (a) identifies the guiding principles that must be considered by the Audit Committee in approving services to ensure that the independent registered public accounting firm’s independence is not impaired; (b) describes the audit, audit-related, tax and other services that may be provided and the non-audit services that are prohibited; and (c) sets forth the pre-approval requirements for all permitted services. Under the policy, all services to be provided by our independent registered public accounting firm must be pre-approved by the Audit Committee.
| Item 15: | Exhibits, Financial Statement Schedules |
| (a) | Financial Statements |
The following financial statements are filed with this Annual Report:
| Report of Independent Registered Public Accounting Firm | |
| Balance Sheets at December 31, 2016 and 2015 | |
| Statements of Operations for the years ended December 31, 2016, 2015 and 2014 | |
| Statements of Stockholders’ Equity for the years ended December 31, 2016, 2015 and 2014 | |
| Statements of Cash Flows for the year ended December 31, 2016, 2015 and 2014 | |
| Notes to Financial Statements | |
| Supplemental Information on Oil and Gas Producing Activities |
| 47 |
| Incorporated by Reference | ||||||
| Exhibit | Filed | |||||
| Number | Exhibit Description | Form | File No. | Exhibit | Filing Date | Here-with |
| 2.1 | Stock for Stock Exchange Agreement dated May 3, 2012 | 8-K | 000-53920 | 2.1 | 7/5/12 | |
| 2.2 | Merger Agreement dated November 7, 2012 | 8-K | 000-53920 | 2.1 | 11/26/12 | |
| 3.1 | Articles of Incorporation (as amended) | 10-K | 000-53920 | 3.1 | 4/1/13 | |
| 3.2 | Current Bylaws | 8-K | 000-53920 | 3.2 | 1/24/13 | |
| 10.1 | Letter Agreement with Patriot Royalty & Land, LLC entered into on March 1, 2012 | 10-K | 000-53920 | 10.1 | 3/20/12 | |
| 10.2* | Ring Energy Inc. Long Term Incentive Plan, as Amended | 8-K | 000-53920 | 99.3 | 1/24/13 | |
| 10.3* | Form of Option Grant for Long-Term Incentive Plan | 10-Q | 000-53920 | 10.2 | 8/14/12 | |
| 10.4 | Executive Committee Charter | 10-K | 000-53920 | 3.1 | 4/1/13 | |
| 10.5 | Audit Committee Charter | 10-K | 000-53920 | 3.1 | 4/1/13 | |
| 10.6 | Compensation Committee Charter | 10-K | 000-53920 | 3.1 | 4/1/13 | |
| 10.7 | Nominating and Corporate Governance Committee Charter | 10-K | 000-53920 | 3.1 | 4/1/13 | |
| 10.8 | Credit Agreement dated July 1, 2014 with SunTrust Bank | 8-K | 001-36057 | 10.1 | 7/3/14 | |
| 10.9 | First Amendment to Credit Agreement with SunTrust Bank | 8-K | 001-36057 | 10.1 | 6/29/15 | |
| 10.10 | Second Amendment to Credit Agreement with SunTrust Bank | 8-K | 001-36057 | 10.1 | 7/29/15 | |
| 10.11 | Third Amendment to Credit Agreement with SunTrust Bank | 8-K | 001-36057 | 10.1 | 5/20/16 | |
| 10.12 | Development Agreement with Torchlight Energy Resources, Inc. | 8-K | 001-36057 | 10.1 | 10/18/13 | |
| 10.13 | Purchase and Sale Agreement, dated February 4, 2014, between Ring Energy, Inc. and Raw Oil & Gas, Inc., JDH Raw LC, and Smith Energy Company | 8-K | 001-36057 | 10.1 | 2/7/14 | |
| 10.14 | Purchase and Sale Agreement effective May 1, 2015, with Finley Production Co., LP, BDT Oil & Gas, LP, Metcalfe Oil, LP, Grasslands Energy, LP, Buffalo Oil & Gas, LP and Finley Resources, Inc. | 8-K | 001-36057 | 2.1 | 5/22/15 | |
| 14.1 | Code of Ethics | 8-K | 000-53920 | 14.1 | 1/24/13 | |
| 16.1 | Letter dated April 19, 2012, from Haynie & Company | 8-K | 000-53920 | 16.1 | 4/19/12 | |
| 23.1 | Consent of Cawley, Gillespie & Associated, Inc. | X | ||||
| 23.2 | Consent of Williamson Petroleum Consultants, Inc. | X | ||||
| 23.3 | 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 | ||||
| 99.2 | Reserve Report of William Petroleum Consultants, Inc. | X | ||||
| 101. INS | XBRL Instance Document | X |
| 101. SCH | XBRL Taxonomy Extension Schema Document | X |
| 101. CAL | XBRL Taxonomy Extension Calculation Linkbase Document | X |
| 101. DEF | XBRL Taxonomy Extension Definition Linkbase Document | X |
| 101. LAB | XBRL Taxonomy Extension Label Linkbase Document | X |
| 101. PRE | XBRL Taxonomy Extension Presentation Linkbase Document | X |
* Management contract
| 48 |
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 15, 2017 | ||
| By: | /s/ William R. Broaddrick | |
| Mr. William R. Broaddrick | ||
| Chief Financial Officer | ||
| Date: March 15, 2017 | ||
In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
| /s/ Lloyd T. Rochford | /s/ Anthony B. Petrelli | ||
| Mr. Lloyd T. Rochford | Mr. Anthony B. Petrelli | ||
| Director | Director | ||
| Date: March 15, 2017 | Date: March 15, 2017 | ||
| /s/ Stanley McCabe | /s/ David A. Fowler | ||
| Mr. Stanley McCabe | Mr. David A. Fowler | ||
| Director | Director | ||
| Date: March 15, 2017 | Date: March 15, 2017 | ||
| /s/ Clayton E. Woodrum | /s/ Kelly Hoffman | ||
| Mr. Clayton E. Woodrum | Mr. Kelly Hoffman | ||
| Director | Director | ||
| Date: March 15, 2017 | Date: March 15, 2017 |
| 49 |
RING ENERGY, INC.
INDEX TO FINANCIAL STATEMENTS
| F-1 |
To the Board of Directors
and
Stockholders of Ring Energy, Inc.
We have audited the accompanying balance sheets of Ring Energy, Inc. (Ring Energy) as of December 31, 2016, and 2015, and the related statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2016. We also have audited Ring Energy’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Ring Energy’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these 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 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 financial statements included 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, 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 financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
www.eidebailly.com
5 Triad Center, Ste. 750 | Salt Lake City, UT 84180-1128 | T 801.532.2200 | F 801.532.7944 | EOE
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Ring Energy as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2016, 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, 2016, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
| /s/ EideBailly LLP | |
| Salt Lake City, Utah | |
| March 15, 2017 |
www.eidebailly.com
5 Triad Center, Ste. 750 | Salt Lake City, UT 84180-1128 | T 801.532.2200 | F 801.532.7944 | EOE
BALANCE SHEETS
| As of December 31, | 2016 | 2015 | ||||||
| ASSETS | ||||||||
| Current Assets | ||||||||
| Cash | $ | 71,086,381 | $ | 4,431,350 | ||||
| Accounts receivable | 3,453,238 | 2,507,858 | ||||||
| Joint interest billing receivable | 454,461 | 1,629,165 | ||||||
| Prepaid expenses and retainers | 226,835 | 146,118 | ||||||
| Total Current Assets | 75,220,915 | 8,714,491 | ||||||
| Properties and Equipment | ||||||||
| Oil and natural gas properties subject to amortization | 250,133,965 | 269,590,374 | ||||||
| Inventory for property development | 1,582,427 | - | ||||||
| Fixed assets subject to depreciation | 1,549,311 | 1,539,991 | ||||||
| Total Properties and Equipment | 253,265,703 | 271,130,365 | ||||||
| Accumulated depreciation, depletion and amortization | (41,347,152 | ) | (29,863,838 | ) | ||||
| Net Properties and Equipment | 211,918,551 | 241,266,527 | ||||||
| Deferred Income Taxes | 20,051,908 | 64,323 | ||||||
| Deferred Financing Costs | 406,025 | 820,904 | ||||||
| Total Assets | $ | 307,597,399 | $ | 250,866,245 | ||||
| LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||
| Current Liabilities | ||||||||
| Accounts payable | $ | 9,099,391 | $ | 11,023,269 | ||||
| Other accured liabilities | - | 309,898 | ||||||
| Total Current Liabilities | 9,099,391 | 11,333,167 | ||||||
| Revolving line of credit | - | 45,900,000 | ||||||
| Asset retirement obligations | 7,957,035 | 7,401,950 | ||||||
| Total Liabilities | 17,056,426 | 64,635,117 | ||||||
| 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; 49,113,063 shares and 30,391,942 shares | ||||||||
| issued and outstanding, respectively | 49,113 | 30,392 | ||||||
| Additional paid-in capital | 335,197,845 | 193,269,034 | ||||||
| Retained earnings (accumulated deficit) | (44,705,985 | ) | (7,068,298 | ) | ||||
| Total Stockholders' Equity | 290,540,973 | 186,231,128 | ||||||
| Total Liabilities and Stockholders' Equity | $ | 307,597,399 | $ | 250,866,245 | ||||
The accompanying notes are an integral part of these financial statements.
| F-4 |
STATEMENTS OF OPERATIONS
| For the years ended December 31, | 2016 | 2015 | 2014 | |||||||||
| Oil and Gas Revenues | $ | 30,850,248 | $ | 31,013,892 | $ | 38,089,443 | ||||||
| Costs and Operating Expenses | ||||||||||||
| Oil and gas production costs | 9,867,800 | 9,958,380 | 4,993,166 | |||||||||
| Oil and gas production taxes | 1,504,620 | 1,468,073 | 1,760,206 | |||||||||
| Depreciation, depletion and amortization | 11,483,314 | 15,175,791 | 11,807,794 | |||||||||
| Ceiling test impairment | 56,513,016 | 9,312,203 | - | |||||||||
| Asset retirement obligation accretion | 487,182 | 418,384 | 154,973 | |||||||||
| General and administrative expense | 8,027,077 | 7,995,395 | 6,803,029 | |||||||||
| Total Costs and Operating Expenses | 87,883,009 | 44,328,226 | 25,519,168 | |||||||||
| Income (Loss) from Operations | (57,032,761 | ) | (13,314,334 | ) | 12,570,275 | |||||||
| Other Income (Expense) | ||||||||||||
| Interest income | 56,498 | 6,984 | 85,964 | |||||||||
| Interest expense | (649,009 | ) | (749,134 | ) | - | |||||||
| Net Other Income (Expense) | (592,511 | ) | (742,150 | ) | 85,964 | |||||||
| Income (Loss) Before Provision for Income Taxes | (57,625,272 | ) | (14,056,484 | ) | 12,656,239 | |||||||
| (Provision for) Benefit from Income Taxes | 19,987,585 | 5,003,713 | (4,235,739 | ) | ||||||||
| . | ||||||||||||
| Net Income (Loss) | $ | (37,637,687 | ) | $ | (9,052,771 | ) | $ | 8,420,500 | ||||
| Basic Earnings (Loss) per share | $ | (0.97 | ) | $ | (0.32 | ) | $ | 0.34 | ||||
| Diluted Earnings (Loss) per share | $ | (0.97 | ) | $ | (0.32 | ) | $ | 0.33 | ||||
The accompanying notes are an integral part of these financial statements.
| F-5 |
STATEMENTS OF STOCKHOLDERS’ EQUITY
| Additional | Retained Earnings | Total | ||||||||||||||||||
| Common Stock | Paid-in | (Accumulated | Stockholders' | |||||||||||||||||
| Shares | Amount | Capital | Deficit) | Equity | ||||||||||||||||
| 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 | |||||||||||||||
| Options exercised (cashless exercise) | 68,547 | 68 | (68 | ) | - | - | ||||||||||||||
| Options exercised | 70,000 | 70 | 214,930 | - | 215,000 | |||||||||||||||
| 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 | |||||||||||||||
| Common stock issued as consideration | ||||||||||||||||||||
| in property acquisitions | 14,606 | 15 | 182,354 | - | 182,369 | |||||||||||||||
| Net income | - | - | - | 8,420,500 | 8,420,500 | |||||||||||||||
| Balance, December 31, 2014 | 25,734,467 | $ | 25,734 | $ | 140,532,323 | $ | 1,984,473 | $ | 142,542,530 | |||||||||||
| Share-based compensation | - | - | 2,566,716 | - | 2,566,716 | |||||||||||||||
| Options exercised (cashless exercise) | 16,875 | 17 | (17 | ) | - | - | ||||||||||||||
| Options exercised | 40,000 | 41 | 134,759 | - | 134,800 | |||||||||||||||
| Common stock issued for cash, net | 4,600,000 | 4,600 | 50,035,253 | - | 50,039,853 | |||||||||||||||
| Net loss | - | - | - | (9,052,771 | ) | (9,052,771 | ) | |||||||||||||
| Balance, December 31, 2015 | 30,391,342 | $ | 30,392 | $ | 193,269,034 | $ | (7,068,298 | ) | $ | 186,231,128 | ||||||||||
| Share-based compensation | - | - | 2,267,053 | - | 2,267,053 | |||||||||||||||
| Options exercised (cashless exercise) | 734 | - | - | - | - | |||||||||||||||
| Options exercised | 25,600 | 26 | 112,474 | - | 112,500 | |||||||||||||||
| Common stock issued for cash, net | 18,695,387 | 18,695 | 139,549,284 | - | 139,567,979 | |||||||||||||||
| Net loss | - | - | - | (37,637,687 | ) | (37,637,687 | ) | |||||||||||||
| Balance, December 31, 2016 | 49,113,063 | $ | 49,113 | $ | 335,197,845 | $ | (44,705,985 | ) | $ | 290,540,973 | ||||||||||
The accompanying notes are an integral part of these financial statements.
| F-6 |
STATEMENTS OF CASH FLOWS
| For the Years Ended December 31, | 2016 | 2015 | 2014 | |||||||||
| Cash Flows From Operating Activities | ||||||||||||
| Net income (loss) | $ | (37,637,687 | ) | $ | (9,052,771 | ) | $ | 8,420,500 | ||||
| Adjustments to reconcile net income (loss) to net cash | ||||||||||||
| provided by (used in) operating activities: | ||||||||||||
| Depreciation, depletion and amortization | 11,483,314 | 15,175,791 | 11,807,794 | |||||||||
| Ceiling test impairment | 56,513,016 | 9,312,203 | - | |||||||||
| Accretion expense | 487,182 | 418,384 | 154,973 | |||||||||
| Share-based compensation | 2,267,053 | 2,566,716 | 2,517,211 | |||||||||
| Stock issued for services | - | - | 87,050 | |||||||||
| Deferred income tax expense (benefit) | (19,987,585 | ) | (5,003,713 | ) | 4,235,739 | |||||||
| Changes in assets and liabilities: | ||||||||||||
| Accounts receivable | 229,324 | 2,163,440 | (2,412,061 | ) | ||||||||
| Prepaid expenses | 334,162 | (806,422 | ) | (94,549 | ) | |||||||
| Accounts payable | (2,233,776 | ) | (4,929,884 | ) | 9,031,408 | |||||||
| Settlement of asset retirement obligation | (240,606 | ) | (446,192 | ) | (39,316 | ) | ||||||
| Net Cash Provided by Operating Activities | 11,214,397 | 9,397,552 | 33,708,749 | |||||||||
| Cash Flows From Investing Activities | ||||||||||||
| Payments to purchase oil and natural gas properties | (10,193,927 | ) | (77,902,553 | ) | (15,054,649 | ) | ||||||
| Payments to develop oil and natural gas properties | (26,554,171 | ) | (31,430,355 | ) | (90,160,236 | ) | ||||||
| Purchase of inventory for development | (1,582,427 | ) | - | - | ||||||||
| Purchase of equipment, vehicles and leasehold improvements | (9,320 | ) | (330,182 | ) | (951,898 | ) | ||||||
| Net Cash Used in Investing Activities | (38,339,845 | ) | (109,663,090 | ) | (106,166,783 | ) | ||||||
| Cash Flows From Financing Activities | ||||||||||||
| Proceeds from revolving line of credit | 7,000,000 | 45,900,000 | - | |||||||||
| Proceeds from issuance of common stock | 139,567,979 | 50,039,853 | 28,514,686 | |||||||||
| Principal payments on revolving line of credit | (52,900,000 | ) | - | - | ||||||||
| Proceeds from option exercise | 112,500 | 134,800 | 215,000 | |||||||||
| Net Cash Provided by Financing Activities | 93,780,479 | 96,074,653 | 28,729,686 | |||||||||
| Net Increase (Decrease) in Cash | 66,655,031 | (4,190,885 | ) | (43,728,348 | ) | |||||||
| Cash at Beginning of Period | 4,431,350 | 8,622,235 | 52,350,583 | |||||||||
| Cash at End of Period | $ | 71,086,381 | $ | 4,431,350 | $ | 8,622,235 | ||||||
| Supplemental Cash Flow Information | ||||||||||||
| Cash paid for interest | $ | 649,010 | $ | 426,742 | $ | - | ||||||
| Noncash Investing and Financing Activities | ||||||||||||
| Stock issued as consideration in property acquisition | $ | - | $ | - | $ | 182,369 | ||||||
| Asset retirement obligation acquired | - | 3,361,634 | 575,977 | |||||||||
| Asset retirement obligation incurred during development | 308,509 | 171,635 | 2,022,445 | |||||||||
The accompanying notes are an integral part of these financial statements.
| F-7 |
NOTES TO FINANCIAL STATEMENTS
NOTE 1 – ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Nature of Operations – Ring Energy, Inc. is a Nevada corporation. Ring Energy, Inc. is referred to herein as the “Company.” The Company owns interests in oil and 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.
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 Values of Financial Instruments – The carrying amounts reported for the revolving line of credit approximates fair value because the underlying instruments are at interest rates which approximate current market rates. The carrying amounts of receivables and accounts payable and other current assets and liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities.
Fair Value of Non-financial Assets and Liabilities – The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on managements’ expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows or third-party offers or prices of comparable assets with consideration of current market conditions to value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy.
Concentration of Credit Risk and Accounts Receivable – Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and accounts receivable. The Company has cash in excess of federally insured limits of $4,181,350 and $70,836,381 at December 31, 2015 and 2016, respectively. The Company places its cash with a high credit quality financial institution.
Substantially all of the Company’s accounts receivable is from purchasers of oil and 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, 2016 and 2015. 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.
| F-8 |
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 offset to the capitalized costs to be amortized. The following table shows total depletion and depletion per barrel-of-oil-equivalent rate, for the years ended December 31, 2016, 2015 and 2014.
| For the Years Ended December 31, | ||||||||||||
| 2016 | 2015 | 2014 | ||||||||||
| Depletion | $ | 11,179,858 | $ | 14,889,487 | $ | 11,680,537 | ||||||
| Depletion rate, per barrel-of-oil-equivalent (BOE) | $ | 12.73 | $ | 20.03 | $ | 25.20 | ||||||
In addition, capitalized costs less accumulated amortization and related deferred income taxes shall not exceed an amount (the full cost ceiling) equal to the sum of:
1) the present value of estimated future net revenues discounted ten percent computed in compliance with SEC guidelines;
2) plus the cost of properties not being amortized;
3) plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized;
4) less income tax effects related to differences between the book and tax basis of the properties.
For the years ended December 31, 2016 and 2015, the Company took write downs on oil and gas properties as a result of the ceiling test in the amount of $56,513,016 and $9,312,203, respectively. No impairment was recorded for the year ended December 31, 2014.
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:
| Buildings and improvements | 30 years | |
| Office equipment and software | 5-7 years | |
| Machinery and equipment | 5-7 years |
Depreciation expense was $303,456, $286,304 and $127,257 for the years ended December 31, 2016, 2015 and 2014, 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, 2013 through 2016 remain subject to examination. The Company’s franchise tax returns in Texas remain subject to examination for 2012 through 2016. The Company currently believes that all significant filing positions are highly certain and that all of its significant income tax filing positions and deductions would be sustained upon audit. Therefore, the Company has no significant reserves for uncertain tax positions and no adjustments to such reserves were required by generally accepted accounting principles. No interest or penalties have been levied against the Company and none are anticipated; therefore, no interest or penalty has been included in our provision for income taxes in the statements of operations.
| F-9 |
Earnings (Loss) Per Share – Basic earnings (loss) per share is computed by dividing net income by the weighted-average number of common shares outstanding during the year. Diluted earnings (loss) per share are calculated to give effect to potentially issuable dilutive common shares.
Major Customers – During the year ended December 31, 2016, sales to two customers represented 50% and 42%, respectively of total oil and gas revenues. At December 31, 2016, these two customers made up 59% and 32%, respectively, of accounts receivable. During the year ended December 31, 2015, sales to three customers represented 48%, 23% and 20%, respectively of total sales. At December 31, 2015, these three customers made up 30%, 53% and 0%, respectively, of accounts receivable. During the year ended December 31, 2014, sales to two customers represented 75% and 18% of total sales, respectively. At December 31, 2014, these two customers made up 45% and 37%, respectively, of accounts receivable. The loss of any of our customers would not have a material adverse effect on the Company as there is an available market for its crude oil and natural gas production from other purchasers.
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, 2016, 2015 and 2014 was $2,267,053, $2,566,716 and $2,517,211, respectively.
Reclassifications – Certain reclassifications of amounts previously reported have been made to the accompanying financial statements to maintain consistency between periods presented. The reclassifications had no impact on net income (loss) or shareholders’ equity.
Recently Adopted Accounting Pronouncement – In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40.) Its objective is to provide guidance about management’s responsibility to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern. Certain disclosures are required should substantial doubt exist. This evaluation is performed each annual and interim reporting period to assess conditions or events within one year after the date that the financial statements are issued. This ASU was effective for Ring beginning with the year ended December 31, 2016; however, no additional disclosures as contemplated by this ASU were warranted.
Recently Issued Accounting Pronouncement – In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718.) The guidance seeks to simplify the accounting for share-based compensation. The new standard requires all excess tax benefits and reductions from differences between the deduction for tax purposes and the compensation cost recorded for financial reporting purposes be recognized as income tax expense or benefit in the Statement of Operations and not recognized as additional paid-in capital. The new standard also requires all excess tax benefits and deficiencies to be classified as operating activity included with income tax cash flows. Ring adopted this ASU as of January 1, 2017. For recording periods following adoption, Ring will make certain income tax presentation changes, most notably prospectively presenting excess tax benefits as income tax expense in the statements of operations and as operating cash flows in the statements of cash flows. The adoption of this guidance will not have a material impact on the Company’s statement of cash flows.
In August 2016, the FASB issued Accounting Standards Update (ASU) 2016-15, Statement of Cash Flows (Topic 230). ASU 2016-15 seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The adoption of this guidance will not have a material impact on the Company’s statement of cash flows.
In February 2016, FASB issued ASU No. 2016-02, Leases (Topic 841). For lessees, the amendments in this update require that for all leases not considered to be short term, a company recognize both a lease liability and right-of-use asset on its balance sheet, representing the obligation to make payments and the right to use or control the use of a specified asset for the lease term. The amendments in this update are effective for annual periods beginning after December 15, 2018. Upon adoption the Company will begin reflect long-term future lease payments as both an asset and a liability on its balance sheet. The adoption of this guidance will not have a material impact on the Company’s financial statements.
In May 2014, the FASB and the International Accounting Standards Board (IASB) issued a joint revenue recognition standard, ASU 2014-09. The new standard removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers, and increases disclosure requirements. The codification was amended through additional ASUs and, as amended, requires companies to recognize revenue to depict the transfer of goods or services to customers in amounts that reflect the consideration to which the company expects to be entitled in exchange for those goods or services. The guidance is effective for annual and interim periods beginning after December 15, 2017. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Company will adopt the new standard utilizing the modified retrospective approach. Upon preliminary evaluation, the Company does not expect the adoption of this ASU to have a material impact on its financial statements.
| F-10 |
In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. The guidance assists in determining whether a transaction should be accounted for as an acquisition or disposal of assets or as a business. This ASU provides a screen that when substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets, the set will not be considered a business. If the screen is not met, a set must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered a business. This ASU is effective for annual and interim periods beginning in 2018 and is required to be adopted using a prospective approach, with early adoption permitted for transactions not previously reported in issued financial statements. The Company does not plan on early adopting the standard. The adoption of this guidance will not have a material impact on the Company’s financial statements.
NOTE 2 – EARNINGS (LOSS) PER SHARE INFORMATION
| For the years ended December 31, | 2016 | 2015 | 2014 | |||||||||
| Net Income (Loss) | $ | (37,637,687 | ) | $ | (9,052,771 | ) | $ | 8,420,500 | ||||
| Basic Weighted-Average Shares Outstanding | 38,710,626 | 28,176,924 | 24,739,795 | |||||||||
| Effect of dilutive securities: | ||||||||||||
| Stock options | - | - | 1,150,490 | |||||||||
| Diluted Weighted-Average Shares Outstanding | 38,710,626 | 28,176,924 | 25,890,285 | |||||||||
| Basic Earnings (Loss) per Share | $ | (0.97 | ) | $ | (0.32 | ) | $ | 0.34 | ||||
| Diluted Earnings (Loss) per Share | $ | (0.97 | ) | $ | (0.32 | ) | $ | 0.33 | ||||
Stock options to purchase 3,358,250, 2,881,150 and 455,500 shares of common stock were excluded from the computation of diluted earnings (loss) per share during the years ended December 31, 2016, 2015 and 2014, respectively, as their effect would have been anti-dilutive.
NOTE 3 – ACQUISITIONS
In June 2015, Ring completed the acquisition of oil and gas assets and properties in the Ford West Field and Ford Geraldine Unit in Reeves and Culberson Counties, Texas. The acquired properties consist of 19,983 gross (19,679 net) acres and include a 98% average working interest and a 79% average net revenue interest. Consideration given by the Company consisted of cash payments totaling $75,000,000 and the assumption of accounts receivable of approximately $286,563 and accounts payable of approximately $742,332. The Company incurred approximately $129,896 in acquisition related costs, which were recognized in general and administrative expense during the year ended December 31, 2015.
The acquisition was recognized as a business combination whereby Ring recorded the assets acquired and the liabilities assumed at their fair values as of May 1, 2015, which is the date the Company obtained control of the properties and was the acquisition date for financial reporting purposes. The estimated fair value of the acquired properties approximated the consideration paid, which the Company concluded approximated the fair value that would be paid by a typical market participant. The following table summarizes the fair values of the assets acquired and the liabilities assumed:
| Assets acquired | ||||
| Proved oil and natural gas properties | $ | 78,361,634 | ||
| Accounts receivable | 400,629 | |||
| Liabilities assumed | ||||
| Accounts payable | (1,562,147 | ) | ||
| Asset retirement obligations | (3,361,634 | ) | ||
| Total Identifiable Net Assets | $ | 73,838,482 |
The following unaudited pro forma information is presented to reflect the operations of the Company as if the Ford West Field and Ford Geraldine Unit acquisition had been completed on January 1, 2015 and 2014, respectively.
| For the years ended December 31, | 2015 | 2014 | ||||||
| Oil and Gas Revenues | $ | 37,253,437 | $ | 74,303,242 | ||||
| Net Income (Loss) | $ | (9,097,288 | ) | $ | 18,186,433 | |||
| Basic Earnings (Loss) per Share | $ | (0.32 | ) | $ | 0.34 | |||
| Diluted Earnings (Loss) per Share | $ | (0.32 | ) | $ | 0.33 | |||
| F-11 |
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, | 2016 | 2015 | ||||||
| Proved oil and natural gas properties | $ | 250,133,965 | $ | 269,590,374 | ||||
| Inventory for property development | 1,582,427 | - | ||||||
| Office equipment | 1,549,311 | 1,539,991 | ||||||
| Total capitalized costs | 253,265,703 | 271,130,365 | ||||||
| Accumulated depletion, depreciation and amortization | (41,347,152 | ) | (29,863,838 | ) | ||||
| Net Capitalized Costs | $ | 211,918,551 | $ | 241,266,527 | ||||
| Net Costs Incurred in Oil and Gas Producing Activities | ||||||||
| For the years Ended December 31, | 2016 | 2015 | ||||||
| Acquisition of proved properties | $ | 10,193,927 | $ | 81,264,187 | ||||
| Development costs | 26,862,680 | 31,601,990 | ||||||
| Total Net Costs Incurred | $ | 37,056,607 | $ | 112,866,177 | ||||
NOTE 5 – REVOLVING LINE OF CREDIT
On July 1, 2014, the Company entered into a Credit Agreement with SunTrust Bank, as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (“Administrative Agent”), which was amended on May 18, 2016, June 26, 2015 and July 24, 2014 (as amended, the “Credit Facility”). The Credit Facility provides for a senior secured revolving credit facility with a maximum borrowing amount of $500 million. The Credit Facility matures on June 26, 2020, and is secured by substantially all of the Company’s assets.
In May 2016, the borrowing base (the “Borrowing Base”) was reduced from the initial $100 million to $60 million. The Borrowing Base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The Borrowing Base will be redetermined semi-annually on each May 1 and November 1, beginning November 1, 2015. The Borrowing Base will also be reduced in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and cancellation of certain hedging positions.
The Credit Facility allows for Eurodollar Loans and Base Rate Loans (each as defined in the Credit Facility). The interest rate on each Eurodollar Loan will be the adjusted LIBOR for the applicable interest period plus a margin between 1.75% and 2.75% (depending on the then-current level of borrowing base usage). The annual interest rate on each Base Rate Loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the federal funds rate plus 0.5% per annum or the (iii) adjusted LIBOR determined on a daily basis for an interest period of one-month, plus 1.00% per annum, plus (b) a margin between 2.75% and 3.75% (depending on the then-current level of borrowing base usage).
The Credit Facility contains certain covenants, which, among other things, require the maintenance of (i) a total leverage ratio 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, 2016, the Company was in compliance with all covenants contained in the Credit Facility, and no amounts were outstanding on the Credit Facility.
| F-12 |
NOTE 6 – ASSET RETIREMENT OBLIGATION
A reconciliation of the asset retirement obligation for the years ended December 31, 2014, 2015 and 2016 is as follows:
| 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 | ||
| Liabilities acquired | 3,361,634 | |||
| Liabilities incurred | 171,635 | |||
| Liabilities settled | (446,192 | ) | ||
| Accretion expense | 418,384 | |||
| Balance, December 31, 2015 | $ | 7,401,950 | ||
| Liabilities incurred | 308,509 | |||
| Liabilities settled | (240,606 | ) | ||
| Accretion expense | 487,182 | |||
| Balance, December 31, 2016 | $ | 7,957,035 |
NOTE 7 – STOCKHOLDERS’ EQUITY
The Company is authorized to issue 150,000,000 common shares, with a par value of $0.001 per share and 50,000,000 shares of Preferred Stock.
Common Stock Issued in Private Offering – 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.
Common Stock Issued in Public Offering –
In June 2015, the Company closed an underwritten public offering of 4,500,000 shares of its common stock at $11.50 per share for gross proceeds of $51,750,000. In July 2015, the Company closed on the over-allotment associated with this offering, resulting in the issuance of an additional 100,000 shares of common stock at $11.50 per share, for gross proceeds of $1,150,000. Total net proceeds from the offering were $50,039,853, after deducting commissions and offering expenses payable by the Company of approximately $2,860,147.
In April 2016, the Company closed on an underwritten public offering of 11,500,000 shares of its common stock, including 1,500,000 shares sold pursuant to the full exercise of an over-allotment option, at $5.60 shares for fross processed of $64,400,000. Total net proceeds from the offering were $61,063,497, after deducting underwriting commissions and offering expenses payable by the Company of $3,336,503.
In December 2016, the Company closed on an underwritten public offering of 7,195,387 shares of its common stock, including 670,387 shares sold pursuant to the partial exercise of an over-allotment option, at $11.50 shares for fross processed of $82,746,951. Total net proceeds from the offering were $78,485,787, after deducting underwriting commissions and offering expenses payable by the Company of $4,261,164.
Common Stock Issued for Services – In July 2014, the Company issued 5,000 shares of common stock, valued at $87,050, or $17.41 per share, as compensation for services provided.
Common Stock Issued for option exercises – During 2014 the Company issued a total of 138,547 shares of common stock as a result of option exercises. Of these shares, 68,547 were the result of cashless exercises of 79,000 options. The Company withheld an aggregate of 10,543 shares as a part of the exercise. The remaining 70,000 options were the result of cash exercises for which the Company received the exercise price of $215,000.
During 2015, the Company issued a total 56,875 shares of common stock as a result of operation exercises. Of these shares, 16,875 were the result of cashless exercises of 25,000 options. The Company withheld an aggregate of 8,125 shares as a part of the exercise. The remaining 40,000 options were the result of cash exercises for which the Company received the exercise price of $134,800.
During 2016, the Company issued a total of 26,334 shares of common stock as a result of option exercises. Of these shares, 734 were the result of cashless exercises of 900 options. The Company withheld an aggregate of 166 shares as a part of the exercise. The remaining 25,600 options were the result of cash exercises for which the Company received the exercise price of $112,500.
| F-13 |
Common Stock Issued as Consideration for Property Acquisitions – 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 were 1,367,150 shares eligible for grant, either as options or as restricted stock, at December 31, 2016.
Employee Stock Options – Following is a table reflecting the issuances during 2014, 2015 and 2016 and their related exercise prices:
| Grant date | # of options | Exercise price | ||||||
| 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 | ||||||
| April 1, 2015 | 3,750 | $ | 10.89 | |||||
| December 9, 2015 | 291,000 | 8.25 | ||||||
| January 13, 2016 (1) | 241,000 | $ | 5.25 | |||||
| May 3, 2016 | 15,000 | 6.42 | ||||||
| December 13, 2016 | 582,500 | 11.75 | ||||||
| 1,501,750 | ||||||||
(1) On December 9, 2015, Ring issued option awards to its named executive officers and directors. On January 13, 2016, upon the recommendation of the Compensation Committee, Ring rescinded the option awards granted to its employees and directors (other than Messrs McCabe and Rochford, who are the members of the Compensation Committee) as the result of a significant decline in the stock price and re-issued the the option awards as of that date to meet the goals and objectives of the Company’s equity based compensation program. The amounts shown as Option Awards includes the additional fair value of the new options over the original grant.
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, 2016, 2015 and 2014 and changes during the years ended December 31, 2016, 2015 and 2014 is as follows:
| F-14 |
| 2016 | 2015 | 2014 | ||||||||||||||||||||||
| Options | Weighted-Average Exercise Price | Options | Weighted-Average Exercise Price | Options | Weighted-Average Exercise Price | |||||||||||||||||||
| Outstanding at beginning of the year | 2,881,750 | $ | 5.07 | 2,684,500 | $ | 4.67 | 2,647,500 | $ | 4.01 | |||||||||||||||
| Issued | 838,500 | 9.79 | 294,750 | 8.28 | 368,500 | 9.15 | ||||||||||||||||||
| Forfeited or rescinded | (331,400 | ) | 8.62 | (32,500 | ) | 4.47 | (177,500 | ) | 5.62 | |||||||||||||||
| Exercised | (26,500 | ) | 4.41 | (65,000 | ) | 3.46 | (154,000 | ) | 2.90 | |||||||||||||||
| Outstanding at end of year | 3,362,350 | $ | 5.90 | 2,881,750 | $ | 5.07 | 2,684,500 | $ | 4.67 | |||||||||||||||
| Exercisable at end of year | 1,722,850 | $ | 4.01 | 1,214,000 | $ | 3.85 | 728,000 | $ | 3.22 | |||||||||||||||
| Weighted average fair value of | ||||||||||||||||||||||||
| options granted during the year | $ | 9.72 | $ | 6.55 | $ | 7.55 | ||||||||||||||||||
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, 2016, 2015 and 2014. 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, 2016, 2015 and 2014:
| Risk free interest rate | Expected life (years) | Dividend yield | Volatility | |||||||||||||
| 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 | % | ||||||||||
| April 1, 2015 | 1.32 | % | 6.5 | - | 103 | % | ||||||||||
| December 9, 2015 | 1.64 | % | 6.5 | - | 100 | % | ||||||||||
| January 13, 2016 | 1.51 | % | 6.5 | - | 100 | % | ||||||||||
| May 3, 2016 | 1.25 | % | 6.5 | - | 99 | % | ||||||||||
| December 13, 2016 | 1.92 | % | 6.5 | - | 96 | % | ||||||||||
As of December 31, 2016, there was $7,246,547 of unrecognized compensation cost related to stock options that will be recognized over a weighted average period of 2.8 years. The aggregate intrinsic value of options vested and expected to vest at December 31, 2016 was $23,872,914. The aggregate intrinsic value of options exercisable at December 31, 2016 was $15,477,634. The year end intrinsic values are based on a December 31, 2016 closing price of $12.99.
Options exercised of 26,500 in 2016, 65,000 in 2015 and 154,000 in 2014 had an aggregate intrinsic value on the date of exercise of $65,089, $476,642 and $2,159,330, respectively.
| F-15 |
The following table summarizes information related to the Company’s stock options outstanding at December 31, 2016:
| Options Outstanding | ||||||||||||||
| Exercise price | Number Outstanding | Weighted- Average Remaining Contractual Life (in years) | Number Exercisable | |||||||||||
| 2.00 | 694,100 | 4.92 | 694,100 | |||||||||||
| 4.50 | 1,340,000 | 5.99 | 810,000 | |||||||||||
| 5.50 | 25,000 | 6.20 | 15,000 | |||||||||||
| 7.50 | 29,000 | 6.48 | 17,000 | |||||||||||
| 10.00 | 90,000 | 6.96 | 54,000 | |||||||||||
| 14.54 | 20,000 | 7.73 | 8,000 | |||||||||||
| 8.00 | 285,000 | 7.92 | 114,000 | |||||||||||
| 10.89 | 3,750 | 8.25 | 750 | |||||||||||
| 8.25 | 50,000 | 8.94 | 10,000 | |||||||||||
| 5.25 | 228,000 | 9.03 | - | |||||||||||
| 6.42 | 15,000 | 9.34 | - | |||||||||||
| 11.75 | 582,500 | 9.95 | - | |||||||||||
| 3,362,350 | 6.93 | 1,722,850 | ||||||||||||
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, 2016, 2015 or 2014.
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, 2016, 2015 and 2014, the Company paid $60,000, $60,000 and $60,000, respectively, to this company.
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 $280,000 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 office lease payments for periods subsequent to December 31, 2015. The leases pertain to approximately 15,000 square feet 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 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 expenses of $527,582, $526,658 and $167,120 for the years ended December 31, 2016, 2015 and 2014, respectively. The following table reflects the future minimum lease payments under the operating lease as of December 31, 2016.
| Year | Lease Obligation | |||
| 2017 | $ | 552,335 | ||
| 2018 | 159,300 | |||
| $ | 711,635 | |||
| F-16 |
NOTE 11 – INCOME TAXES
For the years ended December 31, 2016, 2015 and 2014, components of our provision for income taxes are as follows:
| Provision for Income Taxes | 2016 | 2015 | 2014 | |||||||||
| Deferred taxes | $ | (19,987,585 | ) | $ | (5,003,713 | ) | $ | 4,235,739 | ||||
| Provision for (Benefit from) Income Taxes | $ | (19,987,585 | ) | $ | (5,003,713 | ) | $ | 4,235,739 | ||||
The following is a reconciliation of income taxes computed using the U.S. federal statutory rate to the provision for income taxes:
| Rate Reconciliation | 2016 | 2015 | 2014 | |||||||||
| Tax at federal statutory rate (34%) | $ | (19,592,592 | ) | $ | (4,779,205 | ) | $ | 4,303,121 | ||||
| Non-deductible expenses | 2,558 | 6,599 | 4,465 | |||||||||
| Excess tax benefit from stock option exercises | 15,055 | (89,597 | ) | (595,322 | ) | |||||||
| Adjust prior estimates to tax return | 167,526 | - | 396,061 | |||||||||
| States taxes, net of Federal benefit | (580,131 | ) | (141,510 | ) | 127,414 | |||||||
| Effect of tax rates lower than statutory rate | - | - | - | |||||||||
| Provision for (Benefit from) Income Taxes | $ | (19,987,585 | ) | $ | (5,003,713 | ) | $ | 4,235,739 | ||||
The net deferred taxes consisted of the following at December 31, 2016 and 2015:
| Deferred Taxes: | 2016 | 2015 | ||||||
| Deferred tax liabilities | ||||||||
| Property and equipment | $ | 10,092,289 | $ | 24,398,458 | ||||
| Deferred tax assets | ||||||||
| Stock-based compensation | 3,814,909 | 3,066,518 | ||||||
| Operating loss and IDC carryforwards | 26,329,288 | 21,396,263 | ||||||
| Deferred tax assets | 30,144,197 | 24,462,781 | ||||||
| Net deferred income tax liability (asset) | $ | (20,051,908 | ) | $ | (64,323 | ) | ||
As of December 31, 2016, the Company had net operating loss carry forwards for federal income tax reporting purposes of approximately $77.4 million which, if unused, will begin to expire in 2027 and fully expire in 2036.
NOTE 12 – QUARTERLY FINANCIAL DATE (UNAUDITED)
| 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 | 1,804,352 | 4,459,373 | 2,724,204 | 3,582,346 | ||||||||||||
| Net Income | 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 | ||||||||||||
| 2015 | ||||||||||||||||
| Three Months Ended | ||||||||||||||||
| March 31 | June 30 | September 30 | December 31 | |||||||||||||
| Revenues | $ | 6,045,701 | $ | 8,976,790 | $ | 8,629,007 | $ | 7,362,394 | ||||||||
| Operating Income (Loss) | (1,549,389 | ) | 1,019,686 | (1,473,514 | ) | (11,311,117 | ) | |||||||||
| Net Income (Loss) | (975,624 | ) | 534,167 | (1,138,268 | ) | (7,473,046 | ) | |||||||||
| Basic Net Income (Loss) Per Share | $ | (0.04 | ) | $ | 0.02 | $ | (0.04 | ) | $ | (0.25 | ) | |||||
| Diluted New Income (Loss) Per Share | (0.04 | ) | 0.02 | (0.04 | ) | (0.25 | ) | |||||||||
| F-17 |
| 2016 | ||||||||||||||||
| Three Months Ended | ||||||||||||||||
| March 31 | June 30 | September 30 | December 31 | |||||||||||||
| Revenues | $ | 6,092,388 | $ | 7,104,609 | $ | 7,822,543 | $ | 9,830,709 | ||||||||
| Operating Income (Loss) | (23,833,480 | ) | (25,516,087 | ) | (9,121,201 | ) | 1,438,007 | |||||||||
| Net Income (Loss) | (15,275,044 | ) | (15,941,500 | ) | (5,944,137 | ) | (477,006 | ) | ||||||||
| Basic Net Income (Loss) Per Share | $ | (0.50 | ) | $ | (0.41 | ) | $ | (0.14 | ) | $ | (0.01 | ) | ||||
| Diluted New Income (Loss) Per Share | (0.50 | ) | (0.41 | ) | (0.14 | ) | (0.01 | ) | ||||||||
NOTE 13 – SUBSEQUENT EVENTS
We have evaluated subsequent events after the balance sheet date of December 31, 2016 through the time of filing with the SEC on March 14, 2017, which is the date the financial statements were issued.
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, | 2016 | 2015 | 2014 | |||||||||
| Oil and gas sales | $ | 30,850,248 | $ | 31,013,392 | $ | 38,089,443 | ||||||
| Production costs | (9,867,800 | ) | (9,958,380 | ) | (4,993,167 | ) | ||||||
| Production taxes | (1,504,620 | ) | (1,468,073 | ) | (1,760,206 | ) | ||||||
| Depreciation, depletion, amortization and accretion | (11,970,496 | ) | (15,594,175 | ) | (11,962,766 | ) | ||||||
| Ceiling test impairment | (56,513,016 | ) | (9,312,203 | ) | - | |||||||
| General and administrative (exclusive of corporate overhead) | (1,082,360 | ) | (1,242,524 | ) | (660,862 | ) | ||||||
| Results of Oil and Gas Producing Operations | $ | (50,088,044 | ) | $ | (6,561,963 | ) | $ | 18,712,442 | ||||
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-18 |
| For the Year Ended December 31, | 2016 | 2015 | ||||||||||||||
| Oil (1) | Natural Gas (1) | Oil (1) | Natural Gas (1) | |||||||||||||
| Proved Developed and Undeveloped Reserves | ||||||||||||||||
| Beginning of year | 22,312,450 | 12,539,600 | 10,242,291 | 988,310 | ||||||||||||
| Purchases of minerals in place | - | - | 5,561,276 | 8,775,407 | ||||||||||||
| Improved recovery and extensions | 3,714,442 | 2,366,395 | 8,959,617 | 3,688,462 | ||||||||||||
| Sale of minerals in place | - | - | - | - | ||||||||||||
| Production | (728,051 | ) | (900,089 | ) | (664,611 | ) | (472,508 | ) | ||||||||
| Revision of previous estimate | (299,741 | ) | 2,448,943 | (1,786,123 | ) | (440,071 | ) | |||||||||
| End of year | 24,999,100 | 16,454,849 | 22,312,450 | 12,539,600 | ||||||||||||
| Proved Developed at end of year | 7,309,800 | 9,437,000 | 6,701,300 | 8,416,800 | ||||||||||||
1 Oil reserves are stated in barrels; gas reserves are stated in thousand cubic feet.
| Standardized Measure of Discounted Cash Flows | ||||||||
| December 31, | 2016 | 2015 | ||||||
| Future cash flows | $ | 1,019,179,570 | $ | 1,110,056,990 | ||||
| Future production costs | (318,378,291 | ) | (361,838,780 | ) | ||||
| Future development costs | (140,511,904 | ) | (127,293,170 | ) | ||||
| Future income taxes | (150,765,686 | ) | (177,647,356 | ) | ||||
| Future net cash flows | 409,523,689 | 443,277,684 | ||||||
| 10% annual discount for estimated timing of cash flows | (249,728,651 | ) | (270,591,243 | ) | ||||
| Standardized Measure of Discounted Cash Flows | $ | 159,795,038 | $ | 172,686,441 | ||||
| Changes in Standardized Measure of Discounted Future Net Cash Flows |
| 2016 | 2015 | |||||||
| Beginning of the year | $ | 172,686,441 | $ | 196,344,992 | ||||
| Purchase of minerals in place | - | 121,753,192 | ||||||
| Extensions, discoveries and improved recovery, less related costs | 42,388,078 | 215,074,627 | ||||||
| Development costs incurred during the year | 43,085,217 | 28,653,794 | ||||||
| Sales of oil and gas produced, net of production costs | (19,477,828 | ) | (20,502,195 | ) | ||||
| Sales of minerals in place | - | - | ||||||
| Accretion of discount | 11,995,583 | 27,688,579 | ||||||
| Net changes in price and production costs | (59,100,870 | ) | (308,347,796 | ) | ||||
| Net change in estimated future development costs | (13,064,453 | ) | 14,823,882 | |||||
| Revision of previous quantity estimates | 1,619,437 | (28,297,019 | ) | |||||
| Revision of estimated timing of cash flows | (30,342,680 | ) | (137,051,390 | ) | ||||
| Net change in income taxes | 10,006,113 | 62,545,775 | ||||||
| End of the Year | $ | 159,795,038 | $ | 172,686,441 | ||||
| F-19 |
