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

FORM 10-K


(Mark One)

x Annual report under Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2015.

o Transition report under Section 13 or 15(d) of the Securities Exchange Act of 1934 (No fee required)
For the transition period from _______ to _______.

Commission file number: 000-53473

Torchlight Energy Resources, Inc.

(Exact name of registrant in its charter)

Nevada
74-3237581
(State or other jurisdiction of incorporation or
(I.R.S. Employer Identification No.)
Organization)
 

5700 W. Plano Parkway, Suite 3600
Plano, Texas 75093
(Address of principal executive offices)
 
(214) 432-8002
(Registrant’s telephone number, including area code)

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

Common Stock ($0.001 Par Value)
(Title of Each Class)

The NASDAQ Stock Market LLC
 (Name of each exchange on which registered)
 
Securities registered pursuant to 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 o No x

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

 
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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 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 o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the 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.  o
 
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. (Check one):

Large accelerated filer
o
Accelerated filer
o
Non-accelerated filer
o (Do not check if a smaller reporting company)
Smaller reporting company
x
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
 
The aggregate market value of the common stock held by non-affiliates of the registrant on June 30, 2015, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $2.24 on the Nasdaq Stock Market, was approximately $61,015,694.
 
At March 24, 2016, there were 35,050,806 shares of the registrant’s common stock outstanding (the only class of common stock).
 
DOCUMENTS INCORPORATED BY REFERENCE
None.
 
 
 
 
 

 
 
 
 
 
 




 
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NOTE ABOUT FORWARD-LOOKING STATEMENTS
 
This Annual Report on Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements include, among other things, statements regarding plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements, which are other than statements of historical facts. Forward-looking statements may appear throughout this report, including without limitation, the following sections: Item 1 “Business,” Item 1A “Risk Factors,” and Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Forward-looking statements generally can be identified by words such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will be,” “will continue,” “will likely result,” and similar expressions. These forward-looking statements are based on current expectations and assumptions that are subject to risks and uncertainties, which could cause our actual results to differ materially from those reflected in the forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed in this Annual Report on Form 10-K, and in particular, the risks discussed under the caption “Risk Factors” in Item 1A and those discussed in other documents we file with the Securities and Exchange Commission (“SEC”). Important factors that in our view could cause material adverse effects on our financial condition and results of operations include, but are not limited to, risks associated with the company's ability to obtain additional capital in the future to fund planned expansion, the demand for oil and natural gas, general economic factors, competition in the industry and other factors that may cause actual results to be materially different from those described herein as anticipated, believed, estimated or expected. We undertake no obligation to revise or publicly release the results of any revision to any forward-looking statements, except as required by law. Given these risks and uncertainties, readers are cautioned not to place undue reliance on such forward-looking statements.
 
As used herein, the “Company,” “Torchlight,” “we,” “our,” and similar terms include Torchlight Energy Resources, Inc. and its subsidiaries, unless the context indicates otherwise.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
 



 
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TABLE OF CONTENTS
 
PART I

     
Page
Item 1.
Business
 
5
Item 1A.
Risk Factors
 
12
Item 1B.
Unresolved Staff Comments
 
20
Item 2.
Properties
 
20
Item 3.
Legal Proceedings
 
30
Item 4.
Mine Safety Disclosures
 
30
       
       
PART II
       
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
 
31
Item 6.
Selected Financial Data
 
32
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
32
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
 
35
Item 8.
Financial Statements and Supplementary Data
 
36
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
 
55
Item 9A.
Controls and Procedures
 
55
Item 9B.
Other Information
 
55
       
PART III
       
Item 10.
Directors, Executive Officer, and Corporate Governance
 
56
Item 11.
Executive Compensation
 
58
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
 
61
Item 13.
Certain Relationships and Related Transactions, and Director Independence
 
63
Item 14.
Principal Accountant Fees and Services
 
63
Item 15.
Exhibits, Financial Statement Schedules
 
64
       
 
Signatures
 
66
 
 
 
 

 



 
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PART I

ITEM 1.     BUSINESS

Corporate History and Background

Torchlight Energy Resources, Inc. was incorporated in October 2007 under the laws of the State of Nevada as Pole Perfect Studios, Inc. (“PPS”).  
 
On November 23, 2010, we entered into and closed a Share Exchange Agreement (the “Exchange Agreement”) between the major shareholders of PPS and the shareholders of Torchlight Energy, Inc. (“TEI”).  As a result of the transactions effected by the Exchange Agreement, at closing TEI became our wholly-owned subsidiary, and the business of TEI became our sole business.  TEI is an energy company, incorporated under the laws of the State of Nevada in June 2010.  We are engaged in the acquisition, exploration, exploitation, and/or development of oil and natural gas properties in the United States.  In addition to TEI, we also operate our business through two other wholly-owned subsidiaries, Torchlight Energy Operating, LLC, a Texas limited liability company, and Hudspeth Oil Corporation, a Texas corporation.
 
On December 10, 2010, we effected a 4-for-1 forward split of our shares of common stock outstanding.  All owners of record at the close of business on December 10, 2010 (record date) received three additional shares for every one share they owned.  All share amounts reflected throughout this report take into account the 4-for-1 forward split.

Effective February 8, 2011, we changed our name to “Torchlight Energy Resources, Inc.”  In connection with the name change, our ticker symbol changed from “PPFT” to “TRCH.”

Business Overview

Our business model is to focus on drilling and working interest programs within the United States that have a short window of payback, a high internal rate of return, and proven and bookable reserves.  We have interests in four oil and gas projects, which projects are described in more detail below in the section titled “Current Projects.”  We anticipate being involved in multiple other oil and gas projects moving forward, pending adequate funding.  We anticipate acquiring exploration and development projects both as a non-operating working interest partner, participating in drilling activities primarily on a basis proportionate to the working interest, and acquiring properties we can operate.  We intend to spread the risk associated with drilling programs by entering into a variety of programs in different fields with differing economics.

Salient characteristics of the company include our industry relationships, leverage for prospect selection, anticipated diversity, both geologically and geographically, cost control, partnering, and protection of capital exposure.  Management believes opportunities exist to identify and pursue relatively low risk projects at very attractive entry prices.  These projects may be available from small operators in financial distress, larger companies that need to share costs, and large producers who are consolidating their activities in other areas.  Management believes attractive entry prices and tight cost control will result in returns that are superior to those achieved by major companies or small independents.  An integral part of this strategy is the partnering of major activities.  Such partnering will enable us to acquire the talents of proven industry veterans, as needed, without affecting our long-term fixed overhead costs.

Key Business Attributes

Experienced People.  We build on the expertise and experiences of our management team, including John Brda, Willard McAndrew, and Roger Wurtele.  We will also receive guidance from outside advisors as well as our Board of Directors and will align with high quality exploration and technical partners.  

Project Focus. We are focusing primarily on low risk exploitation projects by pursuing resources where commercial production has already been established but where opportunity for additional and nearby development is indicated.  

Lower Cost Structure.  We will attempt to maintain the lowest possible cost structure, enabling the greatest margins and providing opportunities for investment that would not be feasible for higher cost competitors for lower-risk, valuable projects.

Limit Capital Risks.  Limited capital exposure is planned initially to add value to a project and determine its economic viability. Projects are staged and have options before additional capital is invested. We will limit our exposure in any one project by participating at reduced working interest levels, thereby being able to diversify with limited capital. Management has experience in successfully managing risks of projects, finance, and value.

 
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ITEM 1.    BUSINESS - continued

Project Focus

Generally, we will focus on lower risk exploitation projects (primarily for oil, although gas projects will be considered if the economics are favorable).  Projects are first identified, evaluated, and followed by the engagement of third party operating or financial partners. Subject to overall availability of capital, our interest in large capital projects will be limited.  Each opportunity will be investigated on a standalone basis for both technical and financial merit.   High risk exploration prospects are less favored than low risk exploitation.  We will, however, consider high risk-high reward exploration in connection with exploitation opportunities in a project that would reduce the overall project economic risk.  We will consider such projects on their individual merits, and we expect them to be a minor part of our overall portfolio.

We will be actively seeking quality new investment opportunities to sustain our growth, and we believe we will have access to many new projects.  The sources of these opportunities will vary but all will be evaluated with the same criteria of technical and economic factors.  With a focus on development rather than higher risk exploration projects, it is expected that projects will come from the many small producers who find themselves under-funded or over-extended and therefore vulnerable to price volatility.  The financial ability to respond quickly to opportunities will ensure a continuous stream of projects and will enable us to negotiate from a stronger position to enhance value.  

With emphasis on acquisitions and development strategies, the types of projects in which we will be involved vary from increased production due to simple re-engineering of existing wellbores to step-out drilling, drilling horizontally, and extensions of known fields.  Recompletion of existing wellbores in new zones, development of deeper zones and detailing of structure, and stratigraphic traps with three-dimensional seismic and utilization of new technologies will all be part of our anticipated program. Our preferred type of projects are in-fills to existing production with nearly immediate cash flow and/or adjacent or on trend to existing production. We will prefer projects with moderate to low risk, unrecognized upside potential, and geographic diversity.  

Business Processes

We believe there are three principal business processes that we must follow to enable our operations to be profitable.  Each major business process offers the opportunity for a distinct partner or alliance as we grow. These processes are:

 
·
Investment Evaluation and Review;
 
·
Operations and Field Activities; and
 
·
Administrative and Finance Management.

Investment Evaluation and Review.  This process is the key ingredient to our success. Recognition of quality investment opportunities is the fuel that drives our engine.  Broadly, this process includes the following activities: prospect acquisition, regional and local geological and geophysical evaluations, data processing, economic analysis, lease acquisition and negotiations, permitting, and field supervision.  We expect these evaluation processes to be managed by our management team.  Expert or specific technical support will be outsourced as needed.  Only if a project is taken to development, and only then, will additional staff be hired.  New personnel will have very specific responsibilities.  We anticipate attractive investment opportunities to be presented from outside companies and from the large informal community of geoscientists and engineers. Building a network of advisors is key to the pipeline of high quality opportunities.  

Operations and Field Activities.   This process will begin following management approval of an investment.  Well site supervision, construction, drilling, logging, product marketing, and transportation are examples of some activities.  The present plan is that we will prefer to be the operator, but when operations are not possible, we will farm-out sufficient interests to third parties that will be responsible for these operating activities.  We will provide personnel to monitor these activities and associated costs.

Administrative and Finance Management.   This process will coordinate our initial structuring and capitalization, general operations and accounting, reporting, audit, banking and cash management, regulatory agencies reporting and interaction, timely and accurate payment of royalties, taxes, leases rentals, vendor accounts and performance management that includes budgeting and maintenance of financial controls, and interface with legal counsel and tax and other financial and business advisors.  

Current Projects

As of December 31, 2015 the Company had interests in four oil and gas projects: the Marcelina Creek Field Development in Wilson County, Texas, the Ring Energy Joint Venture in Southwest Kansas, Hunton wells in partnership with Husky Ventures in Central Oklahoma and the Orogrande Project in Hudspeth County, Texas.
 
 
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ITEM 1.    BUSINESS - continued

Marcelina Creek Field Development.

On July 6, 2010, TEI entered into a participation agreement with Bayshore Operating Corporation, LLC (“Bayshore”), which is currently the holder of an oil, gas, and mineral lease covering approximately 1,045 acres in Wilson County, Texas, known as the Marcelina Creek Field Development.  The Participation Agreement provides for the drilling of four wells. Three of the obligation wells have been drilled.  The first three wells include a horizontal re-entry well known as the Johnson-1-H, a vertical well known as the Johnson #4, and a lateral well known as the Johnson #2-H.  These three wells are presently producing a total of approximately 80 BOPD as of December 31, 2015.  The remaining well (Johnson #3) is to be a vertical development well at a location to be determined within the existing lease. Drilling is anticipated for midyear 2016.

The Company initiated a reentry project on the Johnson #4 well early in 2016 which has been completed. Initial production at completion was 2,920 barrels for the month of February. Production has declined to approximately 90 barrels per day. However additional work is underway which is expected to substantially restore the rate of production.

Additionally, work is being done on the Johnson #2 applying an acid treatment to increase production. This well is expected to be back in production near the beginning of second quarter, 2016.

The Marcelina Creek Field Development is located over the Austin Chalk, Buda, and Eagle Ford Formations, which formations are well known and established producers in central Texas.  Their production is controlled by vertical fracturing of the rock with high productivity in wells which encounter the greatest amount of fractures.  With the advent of horizontal drilling technology, numerous opportunities exist in areas and fields that were only drilled vertically.

The Ring Energy Joint Venture, Southwest Kansas

In October 2013, we entered into a Joint Venture agreement with Ring Energy.  The agreement called for us to provide for $6.2 million in drilling capital to, in effect, match Ring Energy’s expenditures for leasing.  In exchange for this commitment, we would receive a 50% interest in each well bore drilled and the acreage unit it held, until we had spent $6.2 million.  At such time, we would then receive a 50% Working Interest in the entire lease block consisting of 17,000 +/- acres.  We were to provide $3.1 million in advance of the program commencing, which would cover approximately 5 wells to be drilled and completed.  Once the initial five wells are completed, we and Ring would evaluate the program and the drilling activity and determine if another five wells are to be drilled.  Should we continue with the program, we would then deposit another $3.1 million with Ring for drilling and completion of the next five wells.

We have made the initial $3.1 million deposit and the first five well drilling program is completed. Drilling operations commenced in March, 2014. Seven wells have been drilled – three are producing, one can be converted to a salt water disposal well, one was not completed, and two were plugged and abandoned.  Based upon results from drilling, the participants elected to suspend further drilling and obtain seismic data to guide continuing development. The seismic data has been analyzed at the date of this filing and discussions with potential parties to further develop the property are in process.   As of December 31, 2015, the Company had invested approximately $5,500,000 in the Ring Joint Venture.  The company believes this project is still considered to be in the testing phase.

Hunton Play, Central Oklahoma
 
The initial Hunton acquisition included three Hunton wells, the Hancock, Robinson and Lenhart.  The Hancock and Robinson are producing wells but have small working interests of 1% and .25 of 1%, respectively. 
 
The Lenhart well was a 62% working interest and was planned for recompletion to return to production.
 
We identified a shallow sandstone that could potentially be productive and tested this formation, and although there were hydrocarbons present, they are not in sufficient quantities to be economic.   The Lenhart property was sold for $25,000 and buyer’s assumption of plugging liability in 2015.
 
During the second quarter of 2013, Torchlight entered into an agreement with Husky Ventures to participate in the drilling of wells to the Hunton Formation in central Oklahoma. We continued to expand this relationship with Husky Ventures on a monthly basis as we expand our lease acreage in the contracted Areas of Mutual Interest (AMI’s).
 
 
7

 

ITEM 1.    BUSINESS - continued
 
When Torchlight executed the agreement Husky had already drilled and completed 18 successful wells in the Hunton.  We estimated that Husky had spent, or caused to be spent, $125 million in what we considered a Research and Development project.  The results of Husky’s initial program lead them to develop certain drilling and completions techniques of which we could participate in and take advantage of.
 
The terms in our agreement with Husky are that we pay our proportionate costs of leases and operating expenses based on our working interest.   For leasing and drilling costs (the AFE), we carry Husky for 15% based on our working interest participation.  This is to compensate Husky for the initial program mentioned above and, additionally, the project coordination of the geological, leasing, legal and title opinions, survey and permitting, all drilling, frac design, completion and equipping, day to day operations, and accounting and filing all required monthly and annual reporting to all governmental agencies.

Torchlight believes this is an equitable agreement in that we have the benefit of the initial programs results while participating with a proven operator in areas that continue to provide us with outstanding results in a safe investment environment.

Management has announced that they are seeking to divest certain of our Hunton assets located in Logan and Kingfisher Counties, Oklahoma.  The Company is actively marketing these assets to potential buyers. These assets include lease rights and current production. As of March 30, 2016 negotiations and documentation of the sale of the Company’s Cimarron assets in Oklahoma is nearing completion.

Cimarron AMI
 
Specifically, we were able to negotiate a 15% working interest in approximately 3,700 acres in the Cimarron Area of Logan County in May 2013.  Leasing continued monthly which resulted in the total acreage in which the Company has an interest increasing to 5,200 as of December 31, 2015 (Net undeveloped acres = 160). Detail of developed and undeveloped acreage positions at December 31, 2015, Drilling Activity, and Cumulative Well Status are presented in Tables in Item 2 of this filing. Our net cumulative investment through December 31, 2015 in undeveloped acres in the Cimarron AMI was $759,724.

Chisholm Trail AMI
 
In the third quarter of 2013, we acquired from a third party for stock, a 15.3% working interest in 5011+/- acres in the Chisolm Trail AMI with Husky Ventures Inc. as the operator. Leasing also continued monthly in this AMI increasing the total acreage in which the Company had an interest.

The Chisholm Trail properties were sold to Husky Ventures during fourth quarter, 2015 who then combined them with the Husky interests in Chisholm Trail and entered into a sale agreement with Gastar Exploration Inc. for the combined Torchlight and Husky interests. The estimated final sale price to Torchlight pending final review by Gastar of lease classification, is $4,150,000. Sale proceeds were applied to reduce Torchlight’s Joint Interest payable to Husky of $2,830,161 with the balance to be received in cash. The Company received $900,000 in cash and has recorded an account receivable as of December 31, 2015 of $419,839. Receipt of the balance of the sale proceeds was subject to final determination of lease classification and was to occur by February 28, 2016. Proceeds have not been received at date of this filing.

Viking AMI
 
In the fourth quarter of 2013 we entered into our third Area of Mutual Interest (AMI) with Husky Ventures, the Viking Prospect.  This AMI covers four townships in size. We acquired a 25% interest in 3,945 acres in the Viking. We subsequently acquired an additional 5% in May, 2014.   Leasing is continuing monthly so that we had an interest in 8,800 total acres in which the Company has an interest as of December 31, 2015. (Net undeveloped acres = 2,600) Husky drilled the first two wells in the AMI in second quarter, 2014. Detail of developed and undeveloped acreage positions at December 31, 2014, Drilling activity, and Cumulative Well Status are presented in Tables in Item 2 of this filing. Our net cumulative investment through December 31, 2015 in undeveloped acres in the Viking AMI was $1,389,846.

R4 AMI

In January of 2014, we again elected to continue to expand in the Hunton Play with Husky Ventures.  We contracted for a 25% Working Interest in approximately 5,000 acres in the R4 AMI consisting of eight townships in South Central Oklahoma. We subsequently acquired an additional 5% in May, 2014.  Leasing is continuing monthly so that the Company had an interest in 11,600 total acres as of December 31, 2015 (Net undeveloped acres = 3,500). Detail of developed and undeveloped acreage positions at December 31, 2015 is presented in the Table in Item 2 of this filing. Our cumulative investment through December 31, 2015 in the R4 AMI was $2,834,514.
 
 
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ITEM 1.    BUSINESS - continued
 
Prairie Grove – Judy Well

In February of 2014, we acquired a 10% Working Interest in a well in the Prairie Grove AMI from a non-consenting third party who elected not to participate in the well.

T4 AMI

In July of 2014, we elected to further expand in the Hunton Play with Husky Ventures.  We contracted for a 25% Working Interest in the T4 AMI.  There is an active ongoing leasing program in this AMI so that the total acres in which the Company has an interest at December 31, 2015 totals 4,300 acres (Net undeveloped acres = 1,100). Detail of developed and undeveloped acreage positions at December 31, 2015 is presented in the Table in Item 2 of this filing. Our cumulative investment through December 31, 2015 in the T4 AMI was $949,530.

As of December 31, 2015, we are actively producing from ten wells in Cimarron, one in Viking, and one in Prairie Grove.
 
Salt Water Disposal Facility

The initial acquisition also included a 22.5% net royalty on a salt water disposal facility in Seminole, Oklahoma.  No value was placed on the facility due to operational uncertainty.  The facility which was newly commissioned in January 2013 as a state of the art disposal facility which could handle 20,000 barrels of produced and injected fluids per day.  Oil and gas wells produce large quantities of saltwater that must be trucked and disposed of at a cost to the producer This SWD facility was considered non-core and was sold on April 1, 2015 for $300,000.
 
Orogrande Project, West Texas

On August 7, 2014, we entered into a Purchase Agreement with Hudspeth Oil Corporation (“Hudspeth”), McCabe Petroleum Corporation (“MPC”), and Greg McCabe. Mr. McCabe was the sole owner of both Hudspeth and MPC. Under the terms and conditions of the Purchase Agreement, at closing, we purchased 100% of the capital stock of Hudspeth which holds certain oil and gas assets, including a 100% working interest in 172,000 mostly contiguous acres in the Orogrande Basin in West Texas. This acreage is in the primary term under five-year leases that carry additional five-year extension provisions. As consideration, at closing we issued 868,750 shares of our common stock to Mr. McCabe and paid a total of $100,000 in geologic origination fees to third parties.  Additionally, Mr. McCabe will have an optional 10% working interest back-in after payout and a reversionary interest if drilling obligations are not met, all under the terms and conditions of a participation and development agreement.  Closing of the transactions contemplated by the Purchase Agreement occurred on September 23, 2014.
 
Of the 172,000 acres, 40,154 were scheduled for renewal in December, 2014.  The Company renewed the leases for the 40,154 acres during second quarter, 2015. Prior to March 31, 2015, the Company had the obligation to begin drilling its first well in order to hold the acreage block. The well was permitted and spudded and drilling began by March 31, 2015.

The Company finalized an agreement to sell a 5% working interest in the Orogrande acreage on June 30, 2015 with an effective date of April 1, 2015. Sale proceeds were $500,000 which were received in April, 2015. In addition, the Company issued 250,000 three year warrants with an exercise price of $.50 to the purchaser.

On September 23, 2015, our subsidiary, Hudspeth Oil Corporation (“HOC”), entered into a Farmout Agreement by and between HOC, Pandora Energy, LP (“Pandora”), Founders Oil & Gas, LLC (“Founders”), McCabe Petroleum Corporation and Greg McCabe (McCabe Petroleum Corporation and Greg McCabe are parties to the Farmout Agreement for limited purposes) for the entire Orogrande Project in Hudspeth County, Texas.  The Farmout Agreement provides for Founders to earn from HOC and Pandora (collectively, the “Farmor”) an undivided 50% of the leasehold interest in the Orogrande Project by Founder’s spending a minimum of $45 million on actual drilling operations on the Orogrande Project in the next two years.  Founders is to pay Farmor a total cost reimbursement of $5,000,000 in multiple installments as follows: (1) $1,000,000 at the signing of the Farmout Agreement, the balance of which was received on September 24, 2015; (2) within 90 days from the closing, Founders will frac and complete the Rich A-11 No. 1 Well; and (3) within five days of the spudding of each of the next eight wells drilled by Founders, Founders will pay to Farmor $500,000 resulting in the payment of the remaining amount; provided that, in the event that within 90 days after the fracing of the Rich Well, Founders notifies Farmor of its election not to drill any additional wells, Founders shall have no further obligation to make further payment.  Upon payment of the first $1,000,000, Farmor assigned to Founders an undivided 50% of the leasehold interest and a 37.5% net revenue interest in the leases subject to the terms of the Farmout Agreement (including obligations to re-assign to HOC and Pandora if the 50% interest in the entire Orogrande Project is not earned) and a proportionate share of the McCabe 10% BIAPO (back in after pay out) interest; provided, however, that for each well that Founders drills prior to earning the acreage, it will be assigned a 50% working interest in the wellbore and in the lease on which it sits.
 
 
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ITEM 1.    BUSINESS - continued
 
Under a joint operating agreement (on A.A.P.L. Form 610 – 1989 Model Form Operating Agreement with COPAS 2005 Accounting Procedures) (“JOA”) also entered into on September 23, 2015, Founders Oil & Gas Operating, LLC is designated as operator of the leases.  Any variance to the operating plan will be determined by a Development Committee, which committee will be made up of members from Founders and Farmor, or their designees, to discuss and recommend the location of the drill wells, data to be gathered and the form of same.  As contemplated under the Farmout Agreement, starting within 90 days of the completion of the fracing on the Rich Well, and at all times subject to the 90 day continuous drilling clause, Founders has the option, but not the obligation, to retain the assigned interest as follows: (1) if Founders spends a minimum of $45 million on actual drilling operations while maintaining compliance with the continuous drilling clause, subject to reasonable delays resulting from reasonable Force Majeure conditions, Founders will have fulfilled its farmout obligations and will be entitled to retain the assigned interests. If Founders does not meet such obligations, it will reassign to Farmor the assigned interest except it will be entitled to retain its interest in the leases covering all wells drilled by Founders and the sections in which such wells are located. Additionally, Founders will resign as operator of the JOA as to all lands reassigned; and (2) Farmor will be carried in all drilling operations during the first two years and/or $45 million in drilling operations, whichever comes last, subject to Founders’ right to recoup certain expenses on “Gap Wells.”  After three years and after Founders has earned its working interest, either party may elect to market the acreage as an entire block, including operatorship.  Should an acceptable bid arise, and both parties agree, the block will be sold 100% working interest to that third party bidder.  However, if only one party wants to accept the outside offer, the other party (the party who wishes not to sell) has the right to purchase the working interest from the selling party.
 
The Rich A-11 well that was drilled by Torchlight in second quarter, 2015 has been evaluated and numerous scientific tests were performed to provide key data for the field development thesis. During the testing process a poor cement bond was identified preventing a cost effective production test for the primary pay zones. Repair to the well bore necessary for a subsequent frac procedure was determined to be economically unfeasible. With the Rich A-11 designed as a test well rather than commercial target, a decision to begin plans for drilling the next well(s) with larger casing that utilized for future commercial production was made.
 
Torchlight Energy and Founders have elected to move forward on planning the next phase of drilling in the Orogrande Project. The project operator plans to permit three new wells starting with the University Founders B-19 #1 well. The new wells would be   drilled vertically for test purposes and would have sufficient casing size to support lateral entry into any pay zone(s) encountered once the well is tested vertically. Torchlight and the project operator would then run a battery of tests on each well to gain information for future development of the field.

Industry and Business Environment
 
Currently, we are experiencing a time of lower oil prices caused by lower demand, higher US Supply, and OPEC’s policies on production.  This has caused oil prices to plummet over the last year from the highs of $105 plus oil per barrel, to reaching lows of below $30 per barrel.  Unfortunately, this is the cyclical nature of the oil and gas industry.  We experience highs and lows that seem to come in cycles.  Fortunately, advances in technology drive the US market and we feel this will drive the prices down on exploration and drilling programs over time.
 
Competition

The oil and natural gas industry is intensely competitive, and we will compete with numerous other companies engaged in the exploration and production of oil and gas.  Some of these companies have substantially greater resources than we have.  Not only do they explore for and produce oil and natural gas, but also many carry on midstream and refining operations and market petroleum and other products on a regional, national, or worldwide basis.  The operations of other companies may be able to pay more for exploratory prospects and productive oil and natural gas properties.  They may also have more resources to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit.
 
Our larger or integrated competitors may have the resources to be better able to absorb the burden of current and future federal, state, and local laws and regulations more easily than we can, which would adversely affect our competitive position.  Our ability to locate reserves and acquire interests in properties in the future will be dependent upon our ability and resources to evaluate and select suitable properties and consummate transactions in this highly competitive environment.  In addition, we may be at a disadvantage in producing oil and natural gas properties and bidding for exploratory prospects because we have fewer financial and human resources than other companies in our industry.  Should a larger and better financed company decide to directly compete with us, and be successful in its efforts, our business could be adversely affected.

Marketing and Customers
 
The market for oil and natural gas that we will produce depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels, and the effects of state and federal regulation.  The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial, and individual consumers.
 
Our oil production is expected to be sold at prices tied to the spot oil markets.  Our natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices.  We will rely on our operating partners to market and sell our production.

Governmental Regulation and Environmental Matters
 
Our operations are subject to various rules, regulations, and limitations impacting the oil and natural gas exploration and production industry as a whole.
 
 
10

 

ITEM 1.    BUSINESS - continued
 
Regulation of Oil and Natural Gas Production
 
Our oil and natural gas exploration, production, and related operations, when developed, will be subject to extensive rules and regulations promulgated by federal, state, tribal, and local authorities and agencies.  Certain states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging, and abandonment of such wells.  Failure to comply with any such rules and regulations can result in substantial penalties.  The regulatory burden on the oil and gas industry will most likely increase our cost of doing business and may affect our profitability.  Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.  Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations.
 
Environmental Matters
 
Our operations and properties are and will be subject to extensive and changing federal, state, and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation, and discharge of materials into the environment, and relating to safety and health.  The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue.  These laws and regulations may:
 
·           require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;
·           limit or prohibit construction, drilling, and other activities on certain lands lying within wilderness and other protected areas;
·           impose substantial liabilities for pollution resulting from operations; or
·           restrict certain areas from fracking and other stimulation techniques.

The permits required for our operations may be subject to revocation, modification, and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we are and will be in substantial compliance with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on our company, as well as the oil and natural gas industry in general.
 
The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict, joint, and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites.  It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.  The Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products.  In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements.

The Endangered Species Act (“ESA”) seeks to ensure that activities do not jeopardize endangered or threatened animal, fish, and plant species, nor destroy or modify the critical habitat of such species.  Under ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat.  ESA provides for criminal penalties for willful violations of the Act.  Other statutes that provide protection to animal and plant species and that may apply to our operations include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act.  Although we believe that our operations will be in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject our company to significant expenses to modify our operations or could force our company to discontinue certain operations altogether.
 
Climate Change
 
Significant studies and research have been devoted to climate change and global warming, and climate change has developed into a major political issue in the United States and globally.  Certain research suggests that greenhouse gas emissions contribute to climate change and pose a threat to the environment.  Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to oil and natural gas exploration and production.  Many states and the federal government have enacted legislation directed at controlling greenhouse gas emissions, and future legislation and regulation could impose additional restrictions or requirements in connection with our drilling and production activities and favor use of alternative energy sources, which could affect operating costs and demand for oil products.  As such, our business could be materially adversely affected by domestic and international legislation targeted at controlling climate change.
 
 
11

 

ITEM 1.    BUSINESS - continued
 
Employees

We currently have six full time employees and no part time employees.  We anticipate adding additional employees, when adequate funds are available, and using independent contractors, consultants, attorneys, and accountants as necessary to complement services rendered by our employees.  We presently have independent technical professionals under consulting agreements who are available to us on an as needed basis.

Research and Development

We did not spend any funds on research and development activities during years ended December 31, 2015 and 2014.
 
ITEM 1A.  RISK FACTORS
 
An investment in us involves a high degree of risk and is suitable only for prospective investors with substantial financial means who have no need for liquidity and can afford the entire loss of their investment in us.  Prospective investors should carefully consider the following risk factors, in addition to the other information contained in this report.

Risks Related to the Company and the Industry

We have a limited operating history, and may not be successful in developing profitable business operations.

We have a limited operating history.  Our business operations must be considered in light of the risks, expenses and difficulties frequently encountered in establishing a business in the oil and natural gas industries.  As of the date of this report, we have generated limited revenues and have limited assets.  We have an insufficient history at this time on which to base an assumption that our business operations will prove to be successful in the long-term.  Our future operating results will depend on many factors, including:

 
·
our ability to raise adequate working capital;
 
·
the success of our development and exploration;
 
·
the demand for natural gas and oil;
 
·
the level of our competition;
 
·
our ability to attract and maintain key management and employees; and
 
·
our ability to efficiently explore, develop, produce or acquire sufficient quantities of marketable natural gas or oil in a highly competitive and speculative environment while maintaining quality and controlling costs.

To achieve profitable operations in the future, we must, alone or with others, successfully manage the factors stated above, as well as continue to develop ways to enhance our production efforts, when commenced.  Despite our best efforts, we may not be successful in our exploration or development efforts, or obtain required regulatory approvals.  There is a possibility that some, or all, of the wells in which we obtain interests may never produce oil or natural gas.

We have limited capital and will need to raise additional capital in the future.
 
We do not currently have sufficient capital to fund both our continuing operations and our planned growth.  We will require additional capital to continue to grow our business via acquisitions and to further expand our exploration and development programs.  We may be unable to obtain additional capital when required.  Future acquisitions and future exploration, development, production and marketing activities, as well as our administrative requirements (such as salaries, insurance expenses and general overhead expenses, as well as legal compliance costs and accounting expenses) will require a substantial amount of additional capital and cash flow.
 
We may pursue sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing, or other means.  We may not be successful in identifying suitable financing transactions in the time period required or at all, and we may not obtain the capital we require by other means.  If we do not succeed in raising additional capital, our resources may not be sufficient to fund our planned operations.

 

 
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ITEM 1A. RISK FACTORS - continued
 
Our ability to obtain financing, if and when necessary, may be impaired by such factors as the capital markets (both generally and in the oil and gas industry in particular), our limited operating history, the location of our oil and natural gas properties and prices of oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us, if any) and the departure of key employees.  Further, if oil or natural gas prices on the commodities markets decline, our future revenues, if any, will likely decrease and such decreased revenues may increase our requirements for capital.  If the amount of capital we are able to raise from financing activities, together with our revenues from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our operations), we may be required to cease our operations, divest our assets at unattractive prices or obtain financing on unattractive terms.

Any additional capital raised through the sale of equity may dilute the ownership percentage of our stockholders.  Raising any such capital could also result in a decrease in the fair market value of our equity securities because our assets would be owned by a larger pool of outstanding equity.  The terms of securities we issue in future capital transactions may be more favorable to our new investors, and may include preferences, superior voting rights and the issuance of other derivative securities, and issuances of incentive awards under equity employee incentive plans, which may have a further dilutive effect.

We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs.  We may also be required to recognize non-cash expenses in connection with certain securities we may issue, which may adversely impact our financial condition. 

Our auditor has indicated that certain factors raise substantial doubt about our ability to continue as a going concern.
 
The financial statements included with this report are presented under the assumption that we will continue as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business over a reasonable length of time. We had a net loss of approximately $43.2 million for the year ended December 31, 2015 and an accumulated deficit in aggregate of approximately $74.9 million at year end.  We are not generating sufficient operating cash flows to support continuing operations, and expect to incur further losses in the development of our business.

In our financial statements for the year ended December 31, 2015, our auditor indicated that certain factors raised substantial doubt about our ability to continue as a going concern.  These factors included our accumulated deficit, as well as the fact that we were not generating sufficient cash flows to meet our regular working capital requirements.  Our ability to continue as a going concern is dependent upon our ability to generate future profitable operations and/or to obtain the necessary financing to meet our obligations and repay our liabilities arising from normal business operations when they come due. Management's plan to address our ability to continue as a going concern includes: (1) obtaining debt or equity funding from private placement or institutional sources; (2) obtaining loans from financial institutions, where possible, or (3) participating in joint venture transactions with third parties. Although management believes that it will be able to obtain the necessary funding to allow us to remain a going concern through the methods discussed above, there can be no assurances that such methods will prove successful. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As a non-operator, our development of successful operations relies extensively on third-parties who, if not successful, could have a material adverse effect on our results of operation.
 
We expect to primarily participate in wells operated by third-parties.   As a result, we will not control the timing of the development, exploitation, production and exploration activities relating to leasehold interests we acquire.  We do, however, have certain rights as granted in our Joint Operating Agreements that allow us a certain degree of freedom such as, but not limited to, the ability to propose the drilling of wells.    If our drilling partners are not successful in such activities relating to our leasehold interests, or are unable or unwilling to perform, our financial condition and results of operation could have an adverse material effect.  

Further, financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person.  We could be held liable for the joint activity obligations of the operator or other working interest owners such as nonpayment of costs and liabilities arising from the actions of the working interest owners.  In the event the operator or other working interest owners do not pay their share of such costs, we would likely have to pay those costs.  In such situations, if we were unable to pay those costs, there could be a material adverse effect to our financial position.

Because of the speculative nature of oil and gas exploration, there is risk that we will not find commercially exploitable oil and gas and that our business will fail.
 
The search for commercial quantities of oil and natural gas as a business is extremely risky. We cannot provide investors with any assurance that any properties in which we obtain a mineral interest will contain commercially exploitable quantities of oil and/or gas.  The exploration expenditures to be made by us may not result in the discovery of commercial quantities of oil and/or gas.  Problems such as unusual or unexpected formations or pressures, premature declines of reservoirs, invasion of water into producing formations and other conditions involved in oil and gas exploration often result in unsuccessful exploration efforts. If we are unable to find commercially exploitable quantities of oil and gas, and/or we are unable to commercially extract such quantities, we may be forced to abandon or curtail our business plan, and as a result, any investment in us may become worthless.


 
13

 

ITEM 1A. RISK FACTORS - continued

Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.
  
Our ability to successfully acquire oil and gas interests, to build our reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will depend on developing and maintaining close working relationships with industry participants and our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment.  These realities are subject to change and our inability to maintain close working relationships with industry participants or continue to acquire suitable property may impair our ability to execute our business plan.
 
To continue to develop our business, we will endeavor to use the business relationships of our management to enter into strategic relationships, which may take the form of joint ventures with other private parties and contractual arrangements with other oil and gas companies, including those that supply equipment and other resources that we will use in our business.  We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them.  In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to in order to fulfill our obligations to these partners or maintain our relationships.  If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

The price of oil and natural gas has historically been volatile.  If it were to decrease substantially, our projections, budgets, and revenues would be adversely affected, potentially forcing us to make changes in our operations.

Our future financial condition, results of operations and the carrying value of any oil and natural gas interests we acquire will depend primarily upon the prices paid for oil and natural gas production. Oil and natural gas prices historically have been volatile and likely will continue to be volatile in the future, especially given current world geopolitical conditions. Our cash flows from operations are highly dependent on the prices that we receive for oil and natural gas. This price volatility also affects the amount of our cash flows available for capital expenditures and our ability to borrow money or raise additional capital. The prices for oil and natural gas are subject to a variety of additional factors that are beyond our control. These factors include:
 
 
·
the level of consumer demand for oil and natural gas;
 
·
the domestic and foreign supply of oil and natural gas;
 
·
the ability of the members of the Organization of Petroleum Exporting Countries ("OPEC") to agree to and maintain oil price and production controls;
 
·
the price of foreign oil and natural gas;
 
·
domestic governmental regulations and taxes;
 
·
the price and availability of alternative fuel sources;
 
·
weather conditions;
 
·
market uncertainty due to political conditions in oil and natural gas producing regions, including the Middle East; and
 
·
worldwide economic conditions.
 
These factors as well as the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements with any certainty. Declines in oil and natural gas prices affect our revenues, and could reduce the amount of oil and natural gas that we can produce economically.  Accordingly, such declines could have a material adverse effect on our financial condition, results of operations, oil and natural gas reserves and the carrying values of our oil and natural gas properties. If the oil and natural gas industry experiences significant price declines, we may be unable to make planned expenditures, among other things. If this were to happen, we may be forced to abandon or curtail our business operations, which would cause the value of an investment in us to decline in value, or become worthless.

If oil or natural gas prices remain depressed or drilling efforts are unsuccessful, we may be required to record write downs of our oil and natural gas properties.

If oil or natural gas prices remain depressed or drilling efforts are unsuccessful, we could be required to write down the carrying value of certain of our oil and natural gas properties.  Write downs may occur when oil and natural gas prices are low, or if we have downward adjustments to our estimated proved reserves, increases in our estimates of operating or development costs, deterioration in drilling results or mechanical problems with wells where the cost to re drill or repair is not supported by the expected economics.

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization.  Should capitalized costs exceed this ceiling, an impairment would be recognized.

 
14

 

ITEM 1A. RISK FACTORS - continued
 
At December 31, 2014, we performed an impairment review using prices that reflect an average of 2014’s monthly prices as prescribed pursuant to the SEC’s guidelines.  These average prices used in the December 31, 2014 impairment review were significantly higher than the actual and currently forecasted prices in 2015.  As lower average monthly pricing is reflected in the trailing 12-month average pricing calculation, the present value of our future net revenues would decline and impairment would be recognized. Since this significantly lower pricing environment persisted into 2015 we were required to write down the value of our oil and gas properties.    
 
The Company recognized impairment of $22,438,114 on its oil and gas properties at June 30, 2015 and an additional Impairment adjustment of $3,236,009 was made at December 31, 2015 for a total Impairment Adjustment of $25,674,123 for the year 2015. 
 
Because of the inherent dangers involved in oil and gas operations, there is a risk that we may incur liability or damages as we conduct our business operations, which could force us to expend a substantial amount of money in connection with litigation and/or a settlement.

The oil and natural gas business involves a variety of operating hazards and risks such as well blowouts, pipe failures, casing collapse, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, spills, pollution, releases of toxic gas and other environmental hazards and risks. These hazards and risks could result in substantial losses to us from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties and suspension of operations. In addition, we may be liable for environmental damages caused by previous owners of property purchased and leased by us. In recent years, there has also been increased scrutiny on the environmental risk associated with hydraulic fracturing, such as underground migration and surface spillage or mishandling of fracturing fluids including chemical additives. As a result, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of our properties and/or force us to expend substantial monies in connection with litigation or settlements. We currently have no insurance to cover such losses and liabilities, and even if insurance is obtained, there can be no assurance that it will be adequate to cover any losses or liabilities. We cannot predict the availability of insurance or the availability of insurance at premium levels that justify our purchase. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and operations. We may elect to self-insure if management believes that the cost of insurance, although available, is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations, which could lead to any investment in us becoming worthless.

The market for oil and gas is intensely competitive, and competition pressures could force us to abandon or curtail our business plan.

The market for oil and gas exploration services is highly competitive, and we only expect competition to intensify in the future. Numerous well-established companies are focusing significant resources on exploration and are currently competing with us for oil and gas opportunities.  Other oil and gas companies may seek to acquire oil and gas leases and properties that we have targeted.  Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors.  Competitors include larger companies which, in particular, may have access to greater resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage.  Actual or potential competitors may be strengthened through the acquisition of additional assets and interests.  Additionally, there are numerous companies focusing their resources on creating fuels and/or materials which serve the same purpose as oil and gas, but are manufactured from renewable resources.

As a result, there can be no assurance that we will be able to compete successfully or that competitive pressures will not adversely affect our business, results of operations, and financial condition. If we are not able to successfully compete in the marketplace, we could be forced to curtail or even abandon our current business plan, which could cause any investment in us to become worthless.
 
We may not be able to successfully manage our growth, which could lead to our inability to implement our business plan.

Our growth may place a significant strain on our managerial, operational and financial resources, especially considering that we currently only have a small number of executive officers, employees and advisors. Further, as we enter into additional contracts, we will be required to manage multiple relationships with various consultants, businesses and other third parties. These requirements will be exacerbated in the event of our further growth or in the event that the number of our drilling and/or extraction operations increases. There can be no assurance that our systems, procedures and/or controls will be adequate to support our operations or that our management will be able to achieve the rapid execution necessary to successfully implement our business plan. If we are unable to manage our growth effectively, our business, results of operations and financial condition will be adversely affected, which could lead to us being forced to abandon or curtail our business plan and operations
 

 
15

 

ITEM 1A. RISK FACTORS - continued
 
Our operations are heavily dependent on current environmental regulation, changes in which we cannot predict.

Oil and natural gas activities that we will engage in, including production, processing, handling and disposal of hazardous materials, such as hydrocarbons and naturally occurring radioactive materials (if any), are subject to stringent regulation. We could incur significant costs, including cleanup costs resulting from a release of hazardous material, third-party claims for property damage and personal injuries fines and sanctions, as a result of any violations or liabilities under environmental or other laws. Changes in or more stringent enforcement of environmental laws could force us to expend additional operating costs and capital expenditures to stay in compliance.

Various federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact our operations and costs. These regulations include, among others, (i) regulations by the Environmental Protection Agency and various state agencies regarding approved methods of disposal for certain hazardous and non-hazardous wastes; (ii) the Comprehensive Environmental Response, Compensation, and Liability Act, Federal Resource Conservation and Recovery Act and analogous state laws which regulate the removal or remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators), property contamination (including groundwater contamination), and remedial plugging operations to prevent future contamination; (iii) the Clean Air Act and comparable state and local requirements which may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations; (iv) the Oil Pollution Act of 1990 which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States; (v) the Resource Conservation and Recovery Act which is the principal federal statute governing the treatment, storage and disposal of hazardous wastes; and (vi) state regulations and statutes governing the handling, treatment, storage and disposal of naturally occurring radioactive material.
  
Management believes that we will be in substantial compliance with applicable environmental laws and regulations. To date, we have not expended any amounts to comply with such regulations, and management does not currently anticipate that future compliance will have a materially adverse effect on our consolidated financial position, results of operations or cash flows. However, if we are deemed to not be in compliance with applicable environmental laws, we could be forced to expend substantial amounts to be in compliance, which would have a materially adverse effect on our financial condition. If this were to happen, any investment in us could be lost.

Government regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Vast quantities of natural gas, natural gas liquids and oil deposits exist in deep shale and other unconventional formations. It is customary in our industry to recover these resources through the use of hydraulic fracturing, combined with horizontal drilling. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in deep underground formations using water, sand and other additives pumped under high pressure into the formation. As with the rest of the industry, our third-party operating partners use hydraulic fracturing as a means to increase the productivity of most of the wells they drill and complete. These formations are generally geologically separated and isolated from fresh ground water supplies by thousands of feet of impermeable rock layers.

We believe our third-party operating partners follow applicable legal requirements for groundwater protection in their operations that are subject to supervision by state and federal regulators.  Furthermore, we believe our third-party operating partners’ well construction practices are specifically designed to protect freshwater aquifers by preventing the migration of fracturing fluids into aquifers.

Hydraulic fracturing is typically regulated by state oil and gas commissions. Some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, and/or well construction requirements on hydraulic fracturing operations.  For example, Pennsylvania is currently considering proposed regulations applicable to surface use at oil and gas well sites, including new secondary containment requirements and an abandoned and orphaned well identification program that would require operators to remediate any such wells that are damaged during current hydraulic fracturing operations.  New York has placed a permit moratorium on high volume fracturing activities combined with horizontal drilling pending the results of a study regarding the safety of hydraulic fracturing. And certain communities in Colorado have also enacted bans on hydraulic fracturing.
 
In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. There are also certain governmental reviews either underway or being proposed that focus on deep shale and other formation completion and production practices, including hydraulic fracturing. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate such activities. Certain environmental and other groups have also suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process.
 

 
16

 

ITEM 1A. RISK FACTORS - continued
 
Further, the EPA has asserted federal regulatory authority over hydraulic fracturing involving “diesel fuels” under the SWDA’s UIC Program. In February 2014, the EPA released its final guidance on the use of diesel additives in hydraulic fracturing operations. The EPA is also engaged in a study of the potential impacts of hydraulic fracturing activities on drinking water resources in these states where the EPA is the permitted authority, including Pennsylvania, with a progress report released in late 2012 and a draft report released in June 2015. It concluded that hydraulic fracturing activities have not led to widespread systematic impacts on drinking water resources in the U.S., but there are above and below ground mechanisms by which hydraulic fracturing could affect drinking water resources. In addition, in March 2015, the Bureau of Land Management (“BLM”) issued a final rule to regulate hydraulic fracturing on federal and Indian land; however, enforcement of the rule has been delayed pending a decision in a legal challenge in the U.S. District Court of Wyoming. Further, the EPA issued an Advanced Notice of Proposed Rulemaking in May 2014 seeking comments relating to the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and mechanisms for obtaining this information. These actions, in conjunction with other analyses by federal and state agencies to assess the impacts of hydraulic fracturing could spur further action toward federal and/or state legislation and regulation of hydraulic fracturing activities.
 
We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit.  Restrictions on hydraulic fracturing could make it prohibitive for our third-party operating partners to conduct operations, and also reduce the amount of oil, natural gas liquids and natural gas that we are ultimately able to produce in commercial quantities from our properties.  If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and process prohibitions.

Our estimates of the volume of reserves could have flaws, or such reserves could turn out not to be commercially extractable. As a result, our future revenues and projections could be incorrect.

Estimates of reserves and of future net revenues prepared by different petroleum engineers may vary substantially depending, in part, on the assumptions made and may be subject to adjustment either up or down in the future. Our actual amounts of production, revenue, taxes, development expenditures, operating expenses, and quantities of recoverable oil and gas reserves may vary substantially from the estimates.  Oil and gas reserve estimates are necessarily inexact and involve matters of subjective engineering judgment. In addition, any estimates of our future net revenues and the present value thereof are based on assumptions derived in part from historical price and cost information, which may not reflect current and future values, and/or other assumptions made by us that only represent our best estimates. If these estimates of quantities, prices and costs prove inaccurate, we may be unsuccessful in expanding our oil and gas reserves base with our acquisitions. Additionally, if declines in and instability of oil and gas prices occur, then write downs in the capitalized costs associated with any oil and gas assets we obtain may be required. Because of the nature of the estimates of our reserves and estimates in general, we can provide no assurance that reductions to our estimated proved oil and gas reserves and estimated future net revenues will not be required in the future, and/or that our estimated reserves will be present and/or commercially extractable. If our reserve estimates are incorrect, the value of our common stock could decrease and we may be forced to write down the capitalized costs of our oil and gas properties.

Decommissioning costs are unknown and may be substantial.  Unplanned costs could divert resources from other projects.

We may become responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which we use for production of oil and natural gas reserves.  Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.”  We accrue a liability for decommissioning costs associated with our wells, but have not established any cash reserve account for these potential costs in respect of any of our properties.  If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs.  The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.

We may have difficulty distributing production, which could harm our financial condition.
 
In order to sell the oil and natural gas that we are able to produce, if any, the operators of the wells we obtain interests in may have to make arrangements for storage and distribution to the market.  We will rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate.  This situation could be particularly problematic to the extent that our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities. These factors may affect our and potential partners’ ability to explore and develop properties and to store and transport oil and natural gas production, increasing our expenses.
  


 
17

 

ITEM 1A. RISK FACTORS - continued
 
Furthermore, weather conditions or natural disasters, actions by companies doing business in one or more of the areas in which we will operate, or labor disputes may impair the distribution of oil and/or natural gas and in turn diminish our financial condition or ability to maintain our operations.

Our business will suffer if we cannot obtain or maintain necessary licenses.
 
Our operations will require licenses, permits and in some cases renewals of licenses and permits from various governmental authorities.  Our ability to obtain, sustain or renew such licenses and permits on acceptable terms is subject to change in regulations and policies and to the discretion of the applicable governments, among other factors.  Our inability to obtain, or our loss of or denial of extension of, any of these licenses or permits could hamper our ability to produce revenues from our operations.

Challenges to our properties may impact our financial condition.
 
Title to oil and gas interests is often not capable of conclusive determination without incurring substantial expense.  While we intend to make appropriate inquiries into the title of properties and other development rights we acquire, title defects may exist.  In addition, we may be unable to obtain adequate insurance for title defects, on a commercially reasonable basis or at all.  If title defects do exist, it is possible that we may lose all or a portion of our right, title and interests in and to the properties to which the title defects relate.  If our property rights are reduced, our ability to conduct our exploration, development and production activities may be impaired.  To mitigate title problems, common industry practice is to obtain a title opinion from a qualified oil and gas attorney prior to the drilling operations of a well.

We rely on technology to conduct our business, and our technology could become ineffective or obsolete.

We rely on technology, including geographic and seismic analysis techniques and economic models, to develop our reserve estimates and to guide our exploration, development and production activities.  We and our operator partners will be required to continually enhance and update our technology to maintain its efficacy and to avoid obsolescence.  The costs of doing so may be substantial and may be higher than the costs that we anticipate for technology maintenance and development.  If we are unable to maintain the efficacy of our technology, our ability to manage our business and to compete may be impaired.  Further, even if we are able to maintain technical effectiveness, our technology may not be the most efficient means of reaching our objectives, in which case we may incur higher operating costs than we would were our technology more efficient.

The loss of key personnel would directly affect our efficiency and profitability.
 
Our future success is dependent, in a large part, on retaining the services of our current management team.  Our executive officers possess a unique and comprehensive knowledge of our industry and related matters that are vital to our success within the industry.  The knowledge, leadership and technical expertise of these individuals would be difficult to replace.  The loss of one or more of our officers could have a material adverse effect on our operating and financial performance, including our ability to develop and execute our long term business strategy.  We do not maintain key-man life insurance with respect to any employees.  We do have employment agreements with each of our executive officers.  There can be no assurance, however, that any of our officers will continue to be employed by us.

Our officers and directors control a significant percentage of our current outstanding common stock and their interests may conflict with those of our stockholders.

As of the date of this report, our executive officers and directors collectively and beneficially own approximately 23.73% of our outstanding common stock (see Item 12 of this report for an explanation of how this number is computed).  This concentration of voting control gives these affiliates substantial influence over any matters which require a stockholder vote, including without limitation the election of directors and approval of merger and/or acquisition transactions, even if their interests may conflict with those of other stockholders.  It could have the effect of delaying or preventing a change in control or otherwise discouraging a potential acquirer from attempting to obtain control of us.  This could have a material adverse effect on the market price of our common stock or prevent our stockholders from realizing a premium over the then prevailing market prices for their shares of common stock.

In the future, we may incur significant increased costs as a result of operating as a public company, and our management may be required to devote substantial time to new compliance initiatives.
 
In the future, we may incur significant legal, accounting, and other expenses as a result of operating as a public company. The Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), as well as new rules subsequently implemented by the SEC, have imposed various requirements on public companies, including requiring changes in corporate governance practices. Our management and other personnel will need to devote a substantial amount of time to these new compliance initiatives. Moreover, these rules and regulations will increase our legal and financial compliance costs and will make some activities more time-consuming and costly. For example, we expect these new rules and regulations to make it more difficult and more expensive for us to obtain director and officer liability insurance, and we may be required to incur substantial costs to maintain the same or similar coverage.

 
 
18

 

ITEM 1A. RISK FACTORS - continued
 
In addition, the Sarbanes-Oxley Act requires, among other things, that we maintain effective internal controls for financial reporting and disclosure controls and procedures. In particular, we are required to perform system and process evaluation and testing on the effectiveness of our internal controls over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act. In performing this evaluation and testing, management concluded that our internal control over financial reporting is effective as of December 31, 2015.  We are performing ongoing updates of our policies and procedures in an effort to ensure our internal control remains effective. Our compliance with Section 404, will require that we incur substantial accounting expense and expend significant management efforts. We currently do not have an internal audit group, and we will need to engage independent professional assistance. Moreover, if we are not able to comply with the requirements of Section 404 in a timely manner, or if in the future we or our independent registered public accounting firm identifies deficiencies in our internal controls over financial reporting that are deemed to be material weaknesses, the market price of our stock could decline, and we could be subject to sanctions or investigations by the SEC or other regulatory authorities, which would require additional financial and management resources.

Certain Factors Related to Our Common Stock

There presently is a limited market for our common stock, and the price of our common stock may be volatile.
 
Our common stock is currently quoted on The NASDAQ Stock Market LLC.  Our shares, however, are very thinly traded, and we have a very limited trading history.  There could be volatility in the volume and market price of our common stock moving forward.  This volatility may be caused by a variety of factors, including the lack of readily available quotations, the absence of consistent administrative supervision of “bid” and “ask” quotations, and generally lower trading volume. In addition, factors such as quarterly variations in our operating results, changes in financial estimates by securities analysts, or our failure to meet our or their projected financial and operating results, litigation involving us, factors relating to the oil and gas industry, actions by governmental agencies, national economic and stock market considerations, as well as other events and circumstances beyond our control could have a significant impact on the future market price of our common stock and the relative volatility of such market price.
 
We have received a notice of failure to satisfy a continued listing requirement of NASDAQ

On February 22, 2016, we received a letter from the Listing Qualifications Staff (the “Staff”) of The NASDAQ Stock Market advising us that the Staff has determined that for the last 30 consecutive business days, we no longer meet the requirement of Listing Rule 5550(a)(2) which requires us to maintain a minimum bid price of $1 per share.  The Listing Rules provide us with a compliance period of 180 calendar days in which to regain compliance.  Accordingly, we will regain compliance if at any time during this 180 day period the closing bid price of our common stock is at least $1 for a minimum of ten consecutive business days.

In the event we do not regain compliance by the end of the 180 day compliance period on August 22, 2016, we may be eligible for additional time.  To qualify, we will be required to meet the continued listing requirement for market value of publicly held shares and all other initial listing standards for The Nasdaq Capital Market, with the exception of the bid price requirement, and will need to provide written notice of our intention to cure the deficiency during the second compliance period, by effecting a reverse stock split, if necessary.  If we meet these requirements, the Staff will inform us that we have been granted an additional 180 calendar days.  However, if it appears to the Staff that we will not be able to cure the deficiency, or if we are otherwise not eligible, the Staff will provide us notice that our common stock will be subject to delisting.  At that time, we may appeal the delisting determination to a Hearings Panel.

We are currently reviewing our options to regain compliance with the NASDAQ Listing Rules.  If we are unable to regain compliance and are ultimately delisted from NASDAQ, this may have a material adverse impact on our stockholders.
 
Offers or availability for sale of a substantial number of shares of our common stock may cause the price of our common stock to decline.

Our stockholders could sell substantial amounts of common stock in the public market, including shares sold upon the filing of a registration statement that registers such shares and/or upon the expiration of any statutory holding period under Rule 144 of the Securities Act of 1933 (the “Securities Act”), if available, or upon the expiration of trading limitation periods.  Such volume could create a circumstance commonly referred to as a market “overhang” and in anticipation of which the market price of our common stock could fall. Additionally, we have a large number of warrants that are presently exercisable, and in June and September of 2016 a large number of shares of preferred stock will mandatorily convert into shares of common stock.  The conversion or exercise of a large amount of these securities followed by the subsequent sale of the underlying stock in the market would likely have a negative effect on our common stock’s market price.  The existence of an overhang, whether or not sales have occurred or are occurring, also could make it more difficult for us to secure additional financing through the sale of equity or equity-related securities in the future at a time and price that we deem reasonable or appropriate.
 
 

 
19

 

ITEM 1A. RISK FACTORS - continued
 
Our directors and officers have rights to indemnification.

Our Bylaws provide, as permitted by governing Nevada law, that we will indemnify our directors, officers, and employees, whether or not then in service as such, against all reasonable expenses actually and necessarily incurred by him or her in connection with the defense of any litigation to which the individual may have been made a party because he or she is or was a director, officer, or employee of the company.  The inclusion of these provisions in the Bylaws may have the effect of reducing the likelihood of derivative litigation against directors and officers, and may discourage or deter stockholders or management from bringing a lawsuit against directors and officers for breach of their duty of care, even though such an action, if successful, might otherwise have benefited us and our stockholders.

We do not anticipate paying any cash dividends.

We do not anticipate paying cash dividends on our common stock for the foreseeable future.  The payment of dividends, if any, would be contingent upon our revenues and earnings, if any, capital requirements, and general financial condition.  The payment of any dividends will be within the discretion of our Board of Directors.  We presently intend to retain all earnings, if any, to implement our business strategy; accordingly, we do not anticipate the declaration of any dividends in the foreseeable future.
 
ITEM 1B.  UNRESOLVED STAFF COMMENTS

Not Applicable.
 
ITEM 2.     PROPERTIES

Our principal executive offices are located at 5700 W. Plano Parkway, Suite 3600, Plano, Texas 75093. We currently lease this office space which totals approximately 3,181 square feet.  We believe that the condition and size of our offices are adequate for our current needs.

Investment in oil and gas properties for 2015 is detailed as follows:

   
2015
   
2014
 
Property acquisition costs
  $ -     $ 7,222,793  
Development costs
  $ 4,518,239     $ 11,368,536  
Exploratory costs
  $ -0-     $ -0-  
                 
Totals
  $ 4,518,239     $ 18,591,329  
 
Oil and Natural Gas Reserves

Reserve Estimates

SEC Case. The following tables sets forth, as of December 31, 2015, our estimated net proved oil and natural gas reserves, the estimated present value (discounted at an annual rate of 10%) of estimated future net revenues before future income taxes (PV-10) and after future income taxes (Standardized Measure) of our proved reserves and our estimated net probable oil and natural gas reserves, each prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with assumptions prescribed by the Securities and Exchange Commission (“SEC”).  All of our reserves are located in the United States.

The PV-10 value is a widely used measure of value of oil and natural gas assets and represents a pre-tax present value of estimated cash flows discounted at ten percent. PV-10 is considered a non-GAAP financial measure as defined by the SEC. We believe that our PV-10 presentation is relevant and useful to our investors because it presents the estimated discounted future net cash flows attributable to our proved reserves before taking into account the related future income taxes, as such taxes may differ among various companies.  We believe investors and creditors use PV-10 as a basis for comparison of the relative size and value of our proved reserves to the reserve estimates of other companies. PV-10 is not a measure of financial or operating performance under GAAP and neither it nor the Standardized Measure is intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

Our PV-10 at December 31, 2015 and 2014 is materially reconciled to our Standardized Measure of discounted cash flows at those dates by reducing the PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2015 and 2014, respectively, were $4,892,262 and $678,904.

The estimates of our proved reserves and the PV-10 set forth herein reflect estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions at December 31, 2015. For purposes of determining prices, we used the average of prices received for each month within the 12-month period ended December 31, 2015, adjusted for quality and location differences, which was $41.59 per barrel of oil and $2.59 per MCF of gas.  This average historical price is not a prediction of future prices. The amounts shown do not give effect to non-property related expenses, such as corporate general administrative expenses and debt service, future income taxes or to depreciation, depletion and amortization.

 
20

 

ITEM 2.    PROPERTIES – continued

   
December 31, 2015
   
December 31, 2015
 
   
Reserves
   
Future Net Revenue (M$)
 
                           
Present Value Discounted
 
Category
 
Oil (Bbls)
   
Gas (Mcf)
   
Total (BOE)
   
Total
   
at 10%
 
                               
Proved Producing
    14,210       34,400       19,943     $ 322     $ 280  
Proved Nonproducing
    40,170       0       40,170     $ 860     $ 763  
Total Proved
    54,380       34,400       60,113     $ 1,182     $ 1,043  
                                         
Standardized Measure of Future Net Cash Flows Related to Proved Oil and Gas Properties
            $ 5,935  
Probable Undeveloped
    0       0       0     $ -     $ -  

   
December 31, 2014
   
December 31, 2014
 
   
Reserves
 
Future Net Revenue (M$)
 
                           
Present Value Discounted
 
Category
 
Oil (Bbls)
   
Gas (Mcf)
   
Total (BOE)
   
Total
   
at 10%
 
                               
Proved Producing
    120,000       687,000       234,500     $ 9,909     $ 7,670  
Proved Nonproducing
    794,400       3,104,000       1,311,733     $ 32,585     $ 16,026  
Total Proved
    914,400       3,791,000       1,546,233       42,494       23,696  
                                         
Standardized Measure of Future Net Cash Flows Related to Proved Oil and Gas Properties
            $ 23,019  
Probable Undeveloped
    912.400       0       912,400     $ 22,779     $ 8,558  

BOE equivalents are determined by combining barrels of oil with MCF of gas divided by six.
 
The decrease of 1,271,563 BOE (998,333 for our Hunton Project and 273,230 for our Marcelina Project) in proved  nonproducing reserves comes from the third party engineering studies of the Cimarron and Chisholm Trail AMI's in Oklahoma and engineering studies for our Marcelina Project. 
 
No reserve value for the Ring Project is included in 2014 reserve tables presented above since the company believes this project is still considered to be in the testing phase.
 
 

 
21

 

ITEM 2.    PROPERTIES - continued

Standardized Measure of Oil & Gas Quantities - Volume Rollforward
Years Ended December 31, 2015 and 2014
                         
The following table sets forth the Company’s net proved reserves, including changes, and proved developed reserves:
       
                         
   
2015
   
2014
 
   
Oil (Bbls)
   
Gas (Mcf)
   
Oil (Bbls)
   
Gas (Mcf)
 
TOTAL PROVED RESERVES:
                       
Beginning of period
    914,400       3,790,650       1,043,161       3,139,594  
Acquisition
    -       -       -       -  
Extensions and discoveries
    -       -       312,579       -  
Divestiture of reserves
    (394,400 )     (2,483,950 )     -       -  
Revisions of previous estimates
    (441,413 )     (1,176,999 )     (388,485 )     821,150  
Production
    (24,207 )     (95,301 )     (52,855 )     (170,094 )
End of period
    54,380       34,400       914,400       3,790,650  
                                 
                                 
PROVED DEVELOPED RESERVES
                               
Proved  producing
    14,210       34,400       102,479       488,410  
Proved nonproducing
    40,170       -       17,521       198,710  
Total
    54,380       34,400       120,000       687,120  
                                 
Total PUD
    -       -       794,400       3,103,530  

The decrease attributable to divestiture of reserves is from the sale of Oklahoma properties - the Chisholm Trail properties in fourth quarter, 2015 and the pending sale of the Cimarron properties in first quarter, 2016. The pending sale of the Cimarron resulted in no reserve value recorded at December 31, 2015 for the Cimarron properties.
 
The downward revisions of previous estimates of 441,413 Bbls and 1,176,999 MCF results primarily from 2015 reserve report calculations for the Company’s properties driven by industry conditions, particularly the decline in product prices, which further causes future development of properties to be uneconomic resulting in no PUD value for 2015.
 

 
 
 
 
 
 

 

 
22

 

ITEM 2.    PROPERTIES - continued
 
Standardized Measure of Oil & Gas Quantities
Year Ended December 31, 2015 & 2014
             
The standardized measure of discounted future net cash flows relating
           
to proved oil and natural gas reserves is as follows :
 
2015
   
2014
 
             
Future cash inflows
  $ 2,410,202     $ 106,027,440  
Future production costs
    (1,169,591 )     (30,383,390 )
Future development costs
    (58,575 )     (33,148,780 )
Future income tax expense
    5,818,722       (978,776 )
Future net cash flows
    7,000,758       41,516,494  
10% annual discount for estimated
               
timing of cash flows
    (1,065,570 )     (18,497,528 )
Standardized measure of discounted future
               
net cash flows related to proved reserves
  $ 5,935,188     $ 23,018,966  
                 
                 
A summary of the changes in the standardized measure of discounted
               
future net cash flows applicable to proved oil and natural gas reserves
               
is as follows :
               
                 
Balance, beginning of year
  $ 23,018,966     $ 19,690,598  
Sales and transfers of oil and gas produced during the period
    (762,423 )     (4,310,813 )
Net change in sales and transfer prices and in production (lifting) costs related to future production
    (18,010,821 )     (9,497,301 )
Net change due to sales of reserves
    (14,026,302 )     -  
Net change due to purchases of minerals in place
    -       -  
Net change due to extensions and discoveries
    -       14,340,815  
Changes in estimated future development costs
    19,563,576       (13,990,412 )
Previously estimated development costs incurred during the period
    357,033       15,980,816  
Net change due to revisions in quantity estimates
    (11,062,826 )     (12,814,002 )
Other
    (858,606 )     2,487,713  
Accretion of discount
    2,146,235       4,715,661  
Net change in income taxes
    5,570,356       6,415,891  
Balance, end of year
  $ 5,935,188     $ 23,018,966  

Due to the inherent uncertainties and the limited nature of reservoir data, both proved and probable reserves are subject to change as additional information becomes available. The estimates of reserves, future cash flows, and present value are based on various assumptions, including those prescribed by the SEC, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

In estimating probable reserves, it should be noted that those reserve estimates inherently involve greater risk and uncertainty than estimates of proved reserves. While analysis of geoscience and engineering data provides reasonable certainty that proved reserves can be economically producible from known formations under existing conditions and within a reasonable time, probable reserves involve less certainty than reserves with a higher classification due to less data to support their ultimate recovery. Probable reserves have not been discounted for the additional risk associated with future recovery.  Prospective investors should be aware that as the categories of reserves decrease with certainty, the risk of recovering reserves at the PV-10 calculation increases.  The reserves and net present worth discounted at 10% relating to the different categories of proved and probable have not been adjusted for risk due to their uncertainty of recovery and thus are not comparable and should not be summed into total amounts.


 
23

 

ITEM 2.    PROPERTIES - continued

Reserve Estimation Process, Controls and Technologies
 
The reserve estimates, including PV-10 estimates, set forth above were prepared by Crest Engineering Services Inc. with respect to the Company’s Marcelina Creek Project in Texas, and PeTech Enterprises, Inc. for the Company’s properties in Oklahoma.  A copy of their full reports with regard to our reserves is attached as Exhibit 99.1 to this annual report on Form 10-K.  These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards.

We do not have any employees with specific reservoir engineering qualifications in the company.  Our Chairman and Chief Executive Officer worked closely with Crest Engineering Services Inc. and PeTech Enterprises Inc. in connection with their preparation of our reserve estimates, including assessing the integrity, accuracy, and timeliness of the methods and assumptions used in this process.
 
CREST Engineering Services, Inc. (CREST) is an independent petroleum engineering company specializing in the evaluation and appraisal of oil and gas reserves. CREST has been employed as an independent provider of these services specifically to provide the appraisal on behalf of us. Neither CREST, nor any of its individual engineers or consultants,  own an interest in either the Company, or any of the properties subject to this evaluation and does not anticipate any future ownership. Waterson Calhoun, P.E. is a petroleum engineer registered with the Texas State Board of Professional Engineers with over 20 years of industry experience providing evaluation services. Mr. Calhoun is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. Mr. Calhoun founded CREST Engineering Services Inc. in 1995 providing evaluation services on behalf of individuals, client companies and lending institutions.

PeTech Enterprises, Inc. (“PeTech”), who provided reserve estimates for our Oklahoma Properties, is a Texas based profitable, family owned oil and gas production and Investment Company that provides reservoir engineering, economics and valuation support to energy banks, energy companies and law firms as an expert witness.  The company has been in business since 1982.  Amiel David is the President of PeTech and the primary technical person in charge of the estimates of reserves and associated cash flow and economics on behalf of the company for the results presented in its reserves report to us.  He has a PhD in Petroleum Engineering from Stanford University.   He is a registered Professional Engineer in the state of Texas (PE #50970), granted in 1982, a member of the Society of Petroleum Engineers and a member of the Society of Petroleum Evaluation Engineers.

Proved Nonproducing Reserves

As of December 31, 2015, our proved nonproducing reserves totaled 40,170 barrels of oil equivalents compared to 1,311,733 as of December 31, 2014, a decrease of 1,271,563.  These proved nonproducing reserves at December 31, 2015 were associated with our Marcelina Creek Field property (which decreased by 273,230) and our Hunton projects (which account for the decrease of 998,333). These numbers are taken from the third party reserves studies by CREST Engineering Services, Inc. and PeTech.
 
This decrease of 998,333 BOE in proved nonproducing reserves attributable to our Hunton projects comes from the third party engineering studies from PeTech of the Hunton in Oklahoma.  The net reserves change associated with these properties is a decrease of approximately 481,000 Bbls of oil and a decrease of approximately 3,104 MMcf of gas, or 998,333 BOE calculated with a gas-oil equivalency factor of six.  
 
With respect to our Marcelina Project, the decrease in proved nonproducing reserves of 273,230 BOE in Texas is due to a combination of factors.  This reduction was based on analysis by CREST Engineering Services, Inc.
 
We made various investments and progress during 2015 to convert proved nonproducing reserves to proved developed reserves.  Limitations on our ability to develop proved nonproducing reserves in 2015 were due to restraints on our capital availability and depressed industry conditions.  
 
Our current drilling plans, subject to sufficient capital resources and the periodic evaluation of interim drilling results and other potential investment opportunities, include drilling substantially all of the Buda wells in our proved nonproducing reserves during 2016 and 2017.  We do not currently have plans to drill the Eagle Ford shale wells in the next year.  The area of the Marcelina Creek Field is an active area of Eagle Ford shale development, and we intend to actively explore our options with regard to these proved nonproducing locations and other potential Eagle Ford drilling locations on our acreage. 
 
 
24

 

ITEM 2.    PROPERTIES - continued
 
Production, Price, and Production Cost History

During the year ended December 31, 2015, we produced and sold 27,981 barrels of oil net to our interest at an average sale price of $46.03 per bbl.  We produced and sold 113,229 MCF of gas net to our interest at an average sales price of $3.00 per MCF. Our average production cost including lease operating expenses and direct production taxes was $17.38 per bbl.  Our depreciation, depletion, and amortization expense was $19.87 per bbl.

During the year ended December 31, 2014, we produced and sold 56,915 barrels of oil net to our interest at an average sale price of $90.58 per bbl. We produced and sold 170,094 MCF of gas net to our interest at an average sales price of $5.89 per MCF.  Our average production cost including lease operating expenses and direct production taxes was $14.63 per BOE.  Our depreciation, depletion, and amortization expense was $30.43 per BOE.

Our production was from properties concentrated in central Oklahoma and in southern Texas. Reserves from each of these areas comprise more than 15% of total reserves. For 2015, approximately 7,896 BOE was produced at Marcelina Creek and approximately 36,472 BOE in Oklahoma, or 17% from Marcelina Creek and 78% from Oklahoma.
 
Quarterly Revenue and Production by State for 2015 and 2014 are detailed as follows:
 
Property
 
Quarter
   
Oil Production {BBLS}
   
Gas Production {MCF}
   
Oil Revenue
   
Gas Revenue
   
Total Revenue
 
                                     
Marcelina
  Q1 - 2015       2,425       0     $ 98,787     $ -     $ 98,787  
Oklahoma
  Q1 - 2015       5,931       37,226     $ 277,574     $ 117,521     $ 395,095  
Kansas
  Q1 - 2015       979       0     $ 40,680     $ -     $ 40,680  
Total Q1-2015
          9,335       37,226       417,041       117,521       534,562  
                                               
Marcelina
  Q2 - 2015       1,957       0     $ 101,291     $ -     $ 101,291  
Oklahoma
  Q2 - 2015       5,495       32,348     $ 290,540     $ 97,374     $ 387,914  
Kansas
  Q2 - 2015       889       0     $ 19,060     $ -     $ 19,060  
Total Q2-2015
          8,341       32,348     $ 410,891     $ 97,374     $ 508,265  
                                               
Marcelina
  Q3 - 2015       2,177       0     $ 86,845     $ -     $ 86,845  
Oklahoma
  Q3 - 2015       4,550       31,275     $ 212,156     $ 87,791     $ 299,947  
Kansas
  Q3 - 2015       370       0     $ 13,238     $ -     $ 13,238  
Total Q3-2015
          7,097       31,275     $ 312,239     $ 87,791     $ 400,030  
                                               
Marcelina
  Q4 - 2015       1,337       0     $ 44,391     $ -     $ 44,391  
Oklahoma
  Q4 - 2015       1,624       12,380     $ 93,864     $ 37,349     $ 131,213  
Kansas
  Q4 - 2015       247       0     $ 9,573     $ -     $ 9,573  
Total Q4-2015
          3,208       12,380     $ 147,828     $ 37,349     $ 185,177  
                                               
Year Ended 12/31/15
          27,981       113,229     $ 1,287,999     $ 340,035     $ 1,628,034  

 

 
25

 

ITEM 2.    PROPERTIES - continued
 
Property
 
Quarter
   
Oil Production {BBLS}
   
Gas Production {MCF}
   
Oil Revenue
   
Gas Revenue
   
Total Revenue
 
                                     
Marcelina
 
Q1 - 2014
     
3,888
     
-
   
$
360,074
   
$
-
   
$
360,074
 
Oklahoma
 
Q1 - 2014
     
2,326
     
7,366
   
$
233,686
   
$
49,210
   
$
282,896
 
Total Q1-2014
         
6,214
     
7,366
   
$
593,760
   
$
49,210
   
$
642,970
 
                                               
Marcelina
 
Q2 - 2014
     
4,546
     
-
   
$
368,937
   
$
-
     
368,937
 
Oklahoma
 
Q2 - 2014
     
9,660
     
33,584
   
$
899,709
   
$
189,073
     
1,088,782
 
Kansas
 
Q2 - 2014
     
2,059
     
-
   
$
172,316
   
$
-
     
172,316
 
Total Q2-2014
         
16,265
     
33,584
   
$
1,440,962
   
$
189,073
   
$
1,630,035
 
                                               
Marcelina
 
Q3 - 2014
     
3,189
     
-
   
$
289,230
   
$
-
   
$
289,230
 
Oklahoma
 
Q3 - 2014
     
13,900
     
35,951
   
$
1,346,858
   
$
185,830
   
$
1,532,688
 
Kansas
 
Q3 - 2014
     
1,257
     
-
   
$
119,797
   
$
-
   
$
119,797
 
Total Q3-2014
         
18,346
     
35,951
   
$
1,755,885
   
$
185,830
   
$
1,941,715
 
                                               
Marcelina
 
Q4 - 2014
     
2,768
     
-
   
$
118,132
   
$
-
   
$
118,132
 
Oklahoma
 
Q4 - 2014
     
12,578
     
93,193
   
$
663,053
   
$
429,960
   
$
1,093,013
 
Kansas
 
Q4 - 2014
     
744
     
-
   
$
29,690
   
$
-
   
$
29,690
 
Total Q3-2014
         
16,090
     
93,193
     
810,875
     
429,960
     
1,240,835
 
                                               
Year Ended 12/31/14
     
56,915
     
170,094
   
$
4,601,482
   
$
854,073
   
$
5,455,555
 

Drilling Activity and Productive Wells

Marcelina Creek Project - Texas

During the year ended December 31, 2010, the Company participated in drilling operations of one re-entry and horizontal extension to an existing well bore (50% working interest).  This well was recompleted in 2012 as a successful producing oil well.

During the year ended December 31, 2011, the Company drilled one well (75% working interest).  This well was successfully completed as an oil well.

During the year ended December 31, 2012, the Company participated in another re-entry and horizontal extension to the same well drilled in 2010 (50% working interest).  This operation was successful and the well is currently a producing oil well.  We also participated in a re-entry and horizontal extension of another well (40% working interest), the Coulter #1.  This well is currently testing as described above.  For 2012, in Marcelina Creek the Company had a total of three producing wells at year end

During the year ended December 31, 2013, the Company drilled one well in the Marcelina Project (75% working interest). This well was successfully completed as an oil well.

As of December 31, 2015, we had three productive wells in the Marcelina Creek Field (2.00 net wells) and one well in the Coulter Field (.40 net well).  Net wells consist of the sum of our fractional working interests in these wells.

Central Oklahoma Projects

During the year ended December 31, 2013, the Company began participating in development wells in the Hunton Play. Two producing wells were acquired and three wells were drilled and completed in 2013.  During 2014 the Company increased its participation by expanding its lease positions and drilling in the Cimarron, Chisholm Trail, Prairie Grove, and Viking AMI’s. As of December 31, 2014, 10 wells were producing in the Cimarron, 11 wells in the Chisholm Trail, one in Prairie Grove, and one in the Viking. One additional well in the Viking was completing at the end of 2014.

During the year ended December 31, 2015, the Company continued to produce the wells in Oklahoma but did not significantly expand development due to capital constraints and industry conditions. The production and leases in the Chisholm Trail AMI were sold in November, 2015 and the Company was actively seeking buyers for the Cimarron AMI as well. A sale of the Cimarron AMI is expected to close first quarter, 2016.

 
26

 

ITEM 2.    PROPERTIES - continued
 
Combined Well Status

The following table summarizes drilling activity and Well Status at December 31, 2015:
 
  Drilling Activity/  
Cumulative Well Status
   
Wells Acquired
   
Acquired
   
Acquired
 
Well Status
 
at 12/31/2015
   
(Sold) 2015
   
2014
   
2013
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
                                                 
Development Wells:
                                               
Productive -Texas
    3.00       2.00       0.00       0.00       0.00       0.00       1.00       0.75  
Productive - Okla
    9.00       1.35       (10.00 )     (0.51 )     18.00       1.64       1.00       0.21  
Productive - Kansas
    2.00       1.00       (3.00 )     (1.90 )     5.00       2.90       0.00       0.00  
Dry
    0.00       0.00       0.00       0.00       0.00       0.00       0.00       0.00  
                                                                 
Exploration Wells:
                                                               
Productive
    0.00       0.00       0.00       0.00       0.00       0.00       0.00       0.00  
Dry
    0.00       0.00       0.00       0.00       0.00       0.00       0.00       0.00  
                                                                 
                                                                 
Total Drilled Wells:
                                                               
Productive -Texas
    3.00       2.00       0.00       0.00       0.00       0.00       1.00       0.75  
Productive - Okla
    9.00       1.35       (10.00 )     (0.51 )     18.00       1.64       1.00       0.21  
Productive - Kansas
    2.00       1.00       (3.00 )     (1.90 )     5.00       2.90       0.00       0.00  
Dry
    0.00       0.00       0.00       0.00       0.00       0.00       0.00       0.00  
                                                                 
                                                                 
Acquired Wells:
                                                               
Productive -Texas
    1.00       0.50       0.00       0.00       0.00       0.00       0.00       0.00  
Productive - Okla
    4.00       0.25       (1.00 )     (0.14 )     2.00       0.18       3.00       0.21  
Productive - Kansas
    0.00       0.00       0.00       0.00       0.00       0.00       0.00       0.00  
                                                                 
                                                                 
Total Wells:
                                                               
Productive -Texas
    4.00       2.50       0.00       0.00       0.00       0.00       1.00       0.75  
Productive - Okla
    13.00       1.60       -11.00       -0.65       20.00       1.82       4.00       0.42  
Productive - Kansas
    2.00       1.00       -3.00       -1.90       5.00       2.90       0.00       0.00  
                                                                 
Total
    19.00       5.09       -14.00       -2.55       25.00       4.72       5.00       1.17  
                                                                 
Well Type:
                                                               
Oil
    5.00       3.00       -3.00       -1.90       5.00       2.90       1.00       0.75  
Gas
    1.00       0.50       0.00       0.00       0.00       0.00       0.00       0.00  
Combination -Oil and Gas
    13.00       1.60       -11.00       -0.65       20.00       1.82       4.00       0.42  
                                                                 
Total
    19.00       5.09       -14.00       -2.55       25.00       4.72       5.00       1.17  
                                                                 


 
27

 

ITEM 2.    PROPERTIES - continued
 
Our acreage positions at December 31, 2015 are summarized as follows:
 
                   
TRCH Interest
   
TRCH Interest
 
       
Total Acres
   
Developed Acres
   
Undeveloped Acres
 
Leasehold Interests - 12/31/2015
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
                                         
Texas -
                                     
 
Marcelina Creek
      1,045       714       360       230       685       484  
 
Orogrande
      163,400       163,400       0       0       163,400       163,400  
 
Coulter Field
      940       376       940       376       0       0  
                                                     
Oklahoma -
                                                 
 
Cimarron
      5,208       781       4,169       411       1,039       370  
 
Viking
      8,800       2,600       240       55       8,560       2,545  
  R4       11,745       3,524       0       0       11,745       3,524  
 
Prairie Grove
      640       64       640       64       0       0  
  T4       4,300       1,100       0       0       4,300       1,100  
                                                     
Kansas -
                                                 
 
Ring JV
      1,320       1,320       1,320       1,320       0       0  
                                                     
Total
      197,398       173,879       7,669       2,456       189,729       171,423  
 
Marcelina Creek

The Marcelina Creek Project consists of 1,045 gross acres all of which are held by production.

Orogrande

On August 7, 2014, we entered into a Purchase Agreement with Hudspeth Oil Corporation (“Hudspeth”), McCabe Petroleum Corporation (“MPC”), and Greg McCabe. Mr. McCabe was the sole owner of both Hudspeth and MPC. Under the terms and conditions of the Purchase Agreement, at closing, we purchased 100% of the capital stock of Hudspeth which holds certain oil and gas assets, including a 100% working interest in 172,000 mostly contiguous acres in the Orogrande Basin in West Texas. This acreage is in the primary term under five-year leases that carry additional five-year extension provisions. As consideration, at closing we issued 868,750 shares of our common stock to Mr. McCabe and paid a total of $100,000 in geologic origination fees to third parties.  Additionally, Mr. McCabe will have an optional 10% working interest back-in after payout and a reversionary interest if drilling obligations are not met, all under the terms and conditions of a participation and development agreement.  Closing of the transactions contemplated by the Purchase Agreement occurred on September 23, 2014.
 
Of the 172,000 acres, 40,154 were scheduled for renewal in December, 2014.  The Company renewed the leases for the 40,154 acres during second quarter, 2015. Prior to March 31, 2015, the Company had the obligation to begin drilling its first well in order to hold the acreage block. The well was permitted and spudded and drilling began by March 31.

The Company finalized an agreement to sell a 5% working interest in the Orogrande acreage on June 30, 2015 with an effective date of April 1, 2015. Sale proceeds were $500,000 which were received in April, 2015. In addition, the Company issued 250,000 three year warrants with an exercise price of $.50 to the purchaser.
 
 
28

 

ITEM 2.    PROPERTIES - continued
 
On September 23, 2015, our subsidiary, Hudspeth Oil Corporation (“HOC”), entered into a Farmout Agreement by and between HOC, Pandora Energy, LP (“Pandora”), Founders Oil & Gas, LLC (“Founders”), McCabe Petroleum Corporation and Greg McCabe (McCabe Petroleum Corporation and Greg McCabe are parties to the Farmout Agreement for limited purposes) for the entire Orogrande Project in Hudspeth County, Texas.  The Farmout Agreement provides for Founders to earn from HOC and Pandora (collectively, the “Farmor”) an undivided 50% of the leasehold interest in the Orogrande Project by Founder’s spending a minimum of $45 million on actual drilling operations on the Orogrande Project in the next two years.  Founders is to pay Farmor a total cost reimbursement of $5,000,000 in multiple installments as follows: (1) $1,000,000 at the signing of the Farmout Agreement, the balance of which was received on September 24, 2015; (2) within 90 days from the closing, Founders will frac and complete the Rich A-11 No. 1 Well; and (3) within five days of the spudding of each of the next eight wells drilled by Founders, Founders will pay to Farmor $500,000 resulting in the payment of the remaining amount; provided that, in the event that within 90 days after the fracing of the Rich Well, Founders notifies Farmor of its election not to drill any additional wells, Founders shall have no further obligation to make further payment.  Upon payment of the first $1,000,000, Farmor assigned to Founders an undivided 50% of the leasehold interest and a 37.5% net revenue interest in the leases subject to the terms of the Farmout Agreement (including obligations to re-assign to HOC and Pandora if the 50% interest in the entire Orogrande Project is not earned) and a proportionate share of the McCabe 10% BIAPO (back in after pay out) interest; provided, however, that for each well that Founders drills prior to earning the acreage, it will be assigned a 50% working interest in the wellbore and in the lease on which it sits.

Under a joint operating agreement (on A.A.P.L. Form 610 – 1989 Model Form Operating Agreement with COPAS 2005 Accounting Procedures) (“JOA”) also entered into on September 23, 2015, Founders Oil & Gas Operating, LLC is designated as operator of the leases.  Any variance to the operating plan will be determined by a Development Committee, which committee will be made up of members from Founders and Farmor, or their designees, to discuss and recommend the location of the drill wells, data to be gathered and the form of same.  As contemplated under the Farmout Agreement, starting within 90 days of the completion of the fracing on the Rich Well, and at all times subject to the 90 day continuous drilling clause, Founders has the option, but not the obligation, to retain the assigned interest as follows: (1) if Founders spends a minimum of $45 million on actual drilling operations while maintaining compliance with the continuous drilling clause, subject to reasonable delays resulting from reasonable Force Majeure conditions, Founders will have fulfilled its farmout obligations and will be entitled to retain the assigned interests. If Founders does not meet such obligations, it will reassign to Farmor the assigned interest except it will be entitled to retain its interest in the leases covering all wells drilled by Founders and the sections in which such wells are located. Additionally, Founders will resign as operator of the JOA as to all lands reassigned; and (2) Farmor will be carried in all drilling operations during the first two years and/or $45 million in drilling operations, whichever comes last, subject to Founders’ right to recoup certain expenses on “Gap Wells.”  After three years and after Founders has earned its working interest, either party may elect to market the acreage as an entire block, including operatorship.  Should an acceptable bid arise, and both parties agree, the block will be sold 100% working interest to that third party bidder.  However, if only one party wants to accept the outside offer, the other party (the party who wishes not to sell) has the right to purchase the working interest from the selling party.
 
The Rich A-11 well that was drilled by Torchlight in second quarter, 2015 has been evaluated and numerous scientific tests were performed to provide key data for the field development thesis. During the testing process a poor cement bond was identified preventing a cost effective production test for the primary pay zones. Repair to the well bore necessary for a subsequent frac procedure was determined to be economically unfeasible. With the Rich A-11 designed as a test well rather than commercial target, a decision to begin plans for drilling the next well(s) with larger casing that utilized for future commercial production was made.
 
Torchlight Energy and Founders have elected to move forward on planning the next phase of drilling in the Orogrande Project. The project operator plans to permit three new wells starting with the University Founders B-19 #1 well. The new wells would be   drilled vertically for test purposes and would have sufficient casing size to support lateral entry into any pay zone(s) encountered once the well is tested vertically. Torchlight and the project operator would then run a battery of tests on each well to gain information for future development of the field.
 
Central Oklahoma Projects

The production and leases in the Chisholm Trail AMI were sold in November, 2015 and the Company was actively seeking buyers for the Cimarron AMI as well, although the Cimarron is owned as of December 31, 2015. A sale of the Cimarron AMI is expected to close first quarter, 2016. The Company retains the acreage in the remaining three AMI’s and the Judy well in the Prairie Grove AMI as of December 31, 2015.
 
Ring Energy Project

In October 2013, we entered into a Joint Venture agreement with Ring Energy. The agreement called for us to provide for $6.2 million in drilling capital to, in effect, match Ring Energy’s expenditures for leasing. In exchange for this commitment, we would receive a 50% interest in each well bore drilled and the acreage unit it held, until we had spent $6.2 million.  At such time, we would then receive a 50% Working Interest in the entire lease block consisting of 17,000 +/- acres.  We were to provide $3.1 million in advance of the program commencing, which would cover approximately 5 wells to be drilled and completed.  Once the initial five wells are completed, we and Ring would evaluate the program and the drilling activity and determine if another five wells are to be drilled.  Should we continue with the program, we would then deposit another $3.1 million with Ring for drilling and completion of the next five wells.
 
We made the initial $3.1 million deposit and the first five well drilling program is currently underway. Well locations were selected and drilling operations commenced in March, 2014. Seven wells were drilled – three are producing, one can be converted to a salt water disposal well, one was not completed, and two were plugged and abandoned. 3-D seismic data has been acquired to assist the selection of future drill sites.

As of December 30, 2015, the Company had invested approximately $5,500,000 in the Ring Joint Venture.
 
 
29

 
 
ITEM 3.     LEGAL PROCEEDINGS

On February 16, 2012, we filed a lawsuit against Hockley Energy, Inc. and Frank O. Snortheim in the District Court of Harris County, Texas in connection with farmout agreements we entered into with Hockley Energy in November 2011.  The Company sued Hockley Energy and Snortheim for breach of contract, fraudulent inducement, promissory estoppel pertaining to failure to perform two farmout agreements entered into on November 4, 2011, the first relating to the Marcelina Creek prospect and the second relating to the East Stockdale prospect.  Under the Marcelina Farmout, Hockley Energy had an obligation to fund $2,231,250.00 no later than November 18, 2011.  They did not perform as promised.  On February 23, 2015, the Company obtained a summary judgment against Hockley Energy in the amount of $16,400,000 in damages and $21,877.77 in attorney fees.  We are currently seeking to enforce the judgment, but it is doubtful that any substantial portion of the judgment is recoverable from Hockley Energy.  The remaining claims against Snortheim have been set for trial on March 31, 2016.  There are no counterclaims pending.  Management is open to settlement discussions.  Because there are no counterclaims, the possibility of an adverse outcome is remote.

ITEM 4.     MINE SAFETY DISCLOSURES

Not Applicable.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
 
30

 

 
PART II
 
ITEM 5.    MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is quoted on The NASDAQ Stock Market LLC under the symbol, “TRCH.”  Trading in our common stock in the over-the-counter market has historically been limited and occasionally sporadic and the quotations set forth below are not necessarily indicative of actual market conditions.  The high and low sales prices for the common stock for each quarter of the fiscal years ended December 31, 2015 and 2014, according to NASDAQ, were as follows:
 
Quarter Ended
  High     Low  
             
12/31/2015
  $ 1.87     $ 0.93  
9/30/2015
  $ 2.44     $ 0.48  
6/30/2015
  $ 2.40     $ 0.25  
3/31/2015
  $ 0.83     $ 0.22  
12/31/2014
  $ 3.59     $ 0.64  
9/30/2014
  $ 4.20     $ 3.25  
6/30/2014
  $ 5.41     $ 3.10  
3/31/2014
  $ 5.41     $ 4.15  

Record Holders

As of March 24, 2016, there were approximately 216 stockholders of record holding a total of 35,050,806 shares of common stock.  Because many of our shares of common stock are held by brokers and other institutions on behalf of stockholders, we are unable to estimate the total number of stockholders represented by these record holders.

The holders of the common stock are entitled to one vote for each share held of record on all matters submitted to a vote of stockholders. Holders of the common stock have no preemptive rights and no right to convert their common stock into any other securities. There are no redemption or sinking fund provisions applicable to the common stock.

Dividends

We have not declared any cash dividends on our common stock since inception and do not anticipate paying any dividends in the foreseeable future. The payment of dividends is within the discretion of the Board of Directors and will depend on our earnings, capital requirements, financial condition, and other relevant factors. There are no restrictions that currently limit our ability to pay dividends on our common stock other than those generally imposed by applicable state law. The Company issued preferred stock in 2015 on which dividends are being paid.

Equity Compensation Plan Information

The following table sets forth all equity compensation plans as of December 31, 2015:
 
     
Number of
     
securities
     
remaining
     
available
     
for future
 
Number of
 
issuance
 
securities to
Weighted-
under
 
be issued
average
equity
 
upon
exercise
compensation
 
exercise of
price of
plans
 
outstanding
outstanding
(excluding
 
options,
options,
securities
 
warrants
warrants
reflected in
Plan Category
and rights
and rights
column (a))
       
Equity compensation plans approved
     
      by security holders
7,950,000
$              1.58
550,000

 
31

 
 
ITEM 5.    MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES - continued
 
Sales of Unregistered Securities

Other than the sale below, all equity securities that we have sold during the period covered by this report that were not registered under the Securities Act have previously been included in a Quarterly Report on Form 10-Q or in a Current Report on Form 8-K.
 
On July 1, 2015, we issued an investor 500,000 three-year warrants as part of the final terms and conditions of its purchase of a working interest in certain of our oil and gas properties.  Of these warrants, 250,000 warrants became exercisable on September 30, 2015 and the remaining 250,000 warrants became exercisable on December 31, 2015.  The warrants have an exercise price of $2.31 per share.

During the three months ended December 31, 2015, we issued a total of 328,438 shares of common stock to consultants as compensation for services.

During the three months ended December 31, 2015, we issued a total of 257,750 shares of common stock to holders of our Series A Convertible Preferred Stock as payment of the dividend due December 31, 2015.

In November 2015, we issued to each of John A. Brda, our President and Chief Executive Officer, Willard G. McAndrew, our Chief Operating Officer, and Roger N. Wurtele, our Chief Financial Officer, 10,000 shares of common stock (a total of 30,000 shares) in exchange for $13,300 in accrued and unpaid compensation (a total of $39,900) at a price of $1.33 per share.

During the three months ended December 31, 2015, three warrant holders exercised warrants, purchasing a total of 65,000 shares of common stock at an exercise price of $1.75 per share.

In October 2015, we issued 1,250,000 three-year warrants to purchase common stock at an exercise price of $2.03 per share to a consultant as compensation for services.

In December 2015, we issued 40,000 three-year warrants to purchase common stock at an exercise price of $2.29 per share to Eunis L. Shockey, our director, as consideration for extending a loan.

In December 2015, we issued 15,000 warrants to purchase common stock at an exercise price of $3.50 per share to a consultant as compensation for services.  The warrants expire in October 2019.

All of the above sales of securities described in this Item 2 were sold under the exemption from registration provided by Section 4(a)(2) of the Securities Act of 1933 and the rules and regulations promulgated thereunder.  The issuances of securities did not involve a “public offering” based upon the following factors: (i) the issuances of securities were isolated private transactions; (ii) a limited number of securities were issued to a limited number of purchasers; (iii) there were no public solicitations; (iv) the investment intent of the purchasers; and (v) the restriction on transferability of the securities issued.
 
ITEM 6.  SELECTED FINANCIAL DATA

Not Applicable.

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Information set forth and discussed in this Management’s Discussion and Analysis and Results of Operations is derived from our historical financial statements and the related notes thereto which are included in this Form 10-K. The following information and discussion should be read in conjunction with such financial statements and notes. Additionally, this Management’s Discussion and Analysis and Plan of Operations contain certain statements that are not strictly historical and are “forward-looking” statements within the meaning of the Private Securities Litigation Reform Act of 1995 and involve a high degree of risk and uncertainty. Actual results may differ materially from those projected in the forward-looking statements due to other risks and uncertainties that exist in our operations, development efforts, and business environment, and due to other risks and uncertainties relating to our ability to obtain additional capital in the future to fund our planned expansion, the demand for oil and natural gas, and other general economic factors.

All forward-looking statements included herein are based on information available to us as of the date hereof, and we assume no obligation to update any such forward-looking statements.

Basis of Presentation of Financial Information

On November 23, 2010, the Share Exchange Agreement (the “Exchange Agreement” or “Transaction”) between Pole Perfect Studios, Inc. (“PPS”) and Torchlight Energy, Inc. (“TEI”) was entered into and closed, through which the former shareholders of TEI became shareholders of PPS. At closing, PPS abandoned its previous business. Consequently, as a result of the Transaction, the business of TEI became our sole business.

 

 
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ITEM 7.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - continued
 
Summary of Key Results

Overview

We are engaged in the acquisition, exploration, exploitation, and/or development of oil and natural gas properties in the United States.

The following discussion of our financial condition and results of operations should be read in conjunction with our audited financial statements included herewith for the year ended December 31, 2015.  This discussion should not be construed to imply that the results discussed herein will necessarily continue into the future, or that any conclusion reached herein will necessarily be indicative of actual operating results in the future.  Such discussion represents only the best present assessment by our management.

We had no active operations prior to the inception of TEI on June 25, 2010 and had limited revenues prior to the year ended December 31, 2012.  
 
Historical Results for the Years Ended December 31, 2015 and 2014
 
For the year ended December 31, 2015, we had a net loss of $43,252,878 compared to a net loss of $15,809,603 for the year ended December 31, 2014.
 
Revenues and Cost of Revenues

For the year ended December 31, 2015, we had production revenue of $1,628,034 compared to $5,455,555 of production revenue for the year ended December 31, 2014. Refer to the table of production and revenue for 2015 included below.  Our cost of revenue, consisting of lease operating expenses and production taxes, was $814,078, and $1,253,090 for the years ended December 31, 2015 and 2014, respectively. Production and Revenue are detailed as follows:

Property
 
Quarter
   
Oil Production {BBLS}
   
Gas Production {MCF}
   
Oil Revenue
   
Gas Revenue
   
Total Revenue
 
                                     
Marcelina
  Q1 - 2015       2,425       0     $ 98,787     $ -     $ 98,787  
Oklahoma
  Q1 - 2015       5,931       37,226     $ 277,574     $ 117,521     $ 395,095  
Kansas
  Q1 - 2015       979       0     $ 40,680     $ -     $ 40,680  
Total Q1-2015
          9,335       37,226       417,041       117,521       534,562  
                                               
Marcelina
  Q2 - 2015       1,957       0     $ 101,291     $ -     $ 101,291  
Oklahoma
  Q2 - 2015       5,495       32,348     $ 290,540     $ 97,374     $ 387,914  
Kansas
  Q2 - 2015       889       0     $ 19,060     $ -     $ 19,060  
Total Q2-2015