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

FORM 10-K/A
Amendment No. 1

(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, 2013.

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)

NASDAQ
(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

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
 
 
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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

At June 30, 2013, the aggregate market value of shares held by non-affiliates of the registrant (based upon 8,242,315 shares held by non-affiliates on June 30, 2013) was approximately $16,402,207.

At March 20, 2014, there were 18,270,408 shares of the registrant’s common stock outstanding (the only class of common stock).
 
DOCUMENTS INCORPORATED BY REFERENCE
None.
 
 

EXPLANATORY NOTE

Torchlight Energy Resources, Inc. is filing this Amendment No. 1 to its Annual Report on Form 10-K for the fiscal year ended December 31, 2013, originally filed with the Securities and Exchange Commission (the “SEC”) on March 31, 2014 (the “Original Report”).
 
This Amendment is being filed to (i) amend Item 1, including amendments to the subsections “Corporate History and Background,” “Smokey Hills Prospect, McPherson County, Kansas” and “Hunton Play, Central Oklahoma”; (ii) amend Item 1A; (iii) amend Item 2; (iv) amend Item 7, including amendments to the subsections “Historical Results for the Years Ended December 31, 2013 and 2012” and “Liquidity and Capital Resources”; (v) amend Item 8, including amendments to Note 1, Note 2, Note 7 and Note 11, and add the subsection “Unaudited Supplementary Information”; (vi) amend Item 9A; (vii) amend Item 11, including amendments to the subsection “Summary Executive Compensation Table” and add the subsection “Setting Executive Compensation”; (viii) amend Item 12; (ix) amend Item 13 (which disclosure was included in the previously filed Proxy Statement); and (x) amend Item 15. Pursuant to Rule 12b-15 promulgated under the Securities Exchange Act of 1934, as amended, this Amendment sets forth the complete text of each item as amended.
 
Except as expressly set forth above and certain minor punctuation and typographical corrections not referenced above, the Original Report has not been amended, updated or otherwise modified.  This Amendment does not reflect events occurring after the filing of the Original Report or update those disclosures regarding events that occurred subsequent to the end of the fiscal year ended December 31, 2013.  All other information is unchanged and reflects the disclosures made at the time of the filing of the Original Report.
 
 
 
 
 
 


 
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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,” “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
 
18
Item 2.
Properties
 
19
Item 3.
Legal Proceedings
 
26
Item 4.
Mine Safety Disclosures
 
26
       
       
PART II
       
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
 
27
Item 6.
Selected Financial Data
 
27
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
28
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
 
30
Item 8.
Financial Statements and Supplementary Data
 
31
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
 
45
Item 9A.
Controls and Procedures
 
45
Item 9B.
Other Information
 
46
       
PART III
       
Item 10.
Directors, Executive Officer, and Corporate Governance
 
47
Item 11.
Executive Compensation
 
50
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
 
53
Item 13.
Certain Relationships and Related Transactions, and Director Independence
 
54
Item 14.
Principal Accountant Fees and Services
 
55
Item 15.
Exhibits, Financial Statement Schedules
 
56
       
 
Signatures
 
58
 
 
 
 

 

 
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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”).  From its incorporation to November 2010, the company was primarily engaged in business start-up activities.

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 Torchlight Energy Operating, LLC, a Texas limited liability company and wholly-owned subsidiary.

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 currently have interests in  five 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 primarily as a non-operating working interest partner, participating in drilling activities primarily on a basis proportionate to the working interest.  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 Thomas Lapinski, John Brda, Willard McAndrew, and Roger Wurtele.  We will also receive guidance from outside advisors and will align with high quality exploration and technical partners.  

Project Focus. We are focusing 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.

Partnering for Excellence.  Partnering with highly select and experienced vendors provides ongoing access to external perspectives, new project opportunities, specialization, networks, operations support, and the ability to test continuously for more effective and cost efficient services.  
 
 
 
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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 then we will secure a third party operating or financial partner. 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.  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 not to be the operator; 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

We currently have interests in five oil and gas projects: the Marcelina Creek Field Development in Wilson County, Texas, the Coulter Field in Waller County, Texas, the Smokey Hills Prospect in McPherson County, Kansas, the Ring Energy Joint Venture in Southwest Kansas and the Hunton play in partnership with Husky Ventures in Central Oklahoma.

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

 
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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 150 BOPD.  The remaining well is to be a vertical development well at a location to be determined within the existing lease.

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.

Coulter Field

In January 2012, we entered into a farm-in agreement, titled the “Coulter Limited Partnership Agreement” (the “Coulter Agreement”), with La Sal Energy, LLC (“La Sal”).  La Sal owns a 100% working interest and a 75% net revenue interest in approximately 940 acres of oil, gas, and mineral leases in Waller County, Texas, on which the well known as “John Coulter #1-R” is located. This well is adjacent to the Katy Field, located on its northwestern updip edge, which produces primarily from the Wilcox Sparks formation.

Pursuant to the Coulter Agreement, we acquired a 34% working interest and a 25.5% net revenue interest from La Sal’s interest in the John Coulter #1-R for the purchase price of $350,000, which was to be applied to 100% of the costs of a fracture stimulation treatment on the well.  Under the agreement, we had options to purchase additional working interests up to a total of 45%.  We exercised the first option and purchased an additional 6% for $50,000, bringing our working interest to 40% and our net revenue interest to 30%.  Our option to purchase an additional 5% working interest can be exercised by the payment of $50,000 within 30 days of first commercial production from the well.  If commercial production is established, the net revenue split will be 80% to us and 20% to La Sal until net revenue totals $437,500, after which the net revenue will be split according to the interests in the well.  Expenses above the initial $350,000 will be split according to the working interests in the well.  Our total investment in the project, including fracture stimulation, subsequent testing, purchase of additional interests and capitalized interest, amounted to $639,609 as of December 31, 2013.

The Coulter #1-R was a replacement well drilled by La Sal for the Coulter #1 which had mechanical problems caused by split casing.  In February 2012 the well was fracture stimulated.  The results were encouraging and the well appears to be capable of commercial gas production.  However, the well is still recovering fluid and has not yet been hooked up to a nearby pipeline for production.  The source of the fluid has not been conclusively determined.  It may be recovery of drilling and/or fracture stimulation fluid or may be entering the wellbore from one or more downhole formations or an adjacent wellbore in the field.  We are continuing to flow fluid from the well and the well is periodically shut–in for pressure build up tests.  We have cemented off the split casing in the Coulter #1 well and are conducting tests to determine productivity.   We have begun discussions with the gas gatherer in the area and are working on completing the gas contract and the well.  No activity has occurred in the fourth quarter as we continue to explore our options for this property.

Smokey Hills Prospect, McPherson County, Kansas

In April 2013, we entered into an agreement to acquire certain assets of Xtreme Oil & Gas, Inc. of Plano, Texas (“Xtreme”).  Included in that agreement were the Smokey Hills Prospect in McPherson County, Kansas, the Cimarron Area Hunton Project in Logan County, Oklahoma,  and an interest in a salt water disposal facility in Seminole, Oklahoma.  Total consideration for all the properties was $1.6 million.

The Smokey Hills acquisition included approximately 16,000 gross acres and a well, the Hoffman 1-H within the greater Lindsborg Field area.  Our working interest is nearly 18%.  Wells had been drilled vertically in the 1960’s to present at depths of less than 4,000 feet looking for production from Mississippian carbonated fractured reservoirs.  The Hoffman well was drilled laterally 4,200 feet and fracking had not been completed at the time of our acquisition of the project.  Core analysis and logs indicated good porosity at 14 to 22%. Following our acquisition, the well was hydraulically fractured, but the results were disappointing.  We presently are evaluating our next efforts to monetize the investment of approximately $1,056,844 as of December 31, 2013.  Allocated costs are high due to the large acreage position.   
 
Since development did not continue due to the need for analysis after the Hoffman well experience, the acreage position declined from approximately 16,000 acres at acquisition to approximately 11,752 at December 31, 2013.  We are planning to drill a ten well program in late Q2 or early Q3, 2014 to evaluate the possibility of producing the formation in a traditional vertical method.  Of the 800 wells of interest in the area, all were produced vertically and in economic quantities.

The results of the ten well program will drive the continuing development of the Smokey Hills acreage. Based on the economic success of the first ten wells and the geological analysis of the acreage, a drilling program will continue at an initial planned pace of four wells each month which will hold 640 additional acres per month. The leases are beyond their primary term and in their two year extension period. The leases are scheduled to expire over the period from third quarter 2014 through third quarter 2015.

 
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As continued drilling generates economic success we plan to increase the pace of drilling sufficient to develop 100% of the acreage prior to expiration of any of the acreage undeveloped as of December 31, 2013.
 
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 currently underway.

Hunton Play, Central Oklahoma

The Xtreme transaction also included the acquisition of 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 is a 62% working interest and was being prepared for a fracture stimulation when it was previously damaged, prior to our acquisition, by the service contractor.  The well bore at the Hunton level has an irretrievable pipe in the hole and cannot be used to produce from the Hunton.  Although Xtreme won the litigation against the contractor, he failed to pay for the replacement of the well bore, and Xtreme was responsible for costs primarily to Baker-Hughes for work done on the well.  We took responsibility for those charges and negotiated a settlement of approximately $600,000.

Subsequent to the above, we have identified a shallow sandstone that could potentially be productive.  As previously planned, we tested this formation, and although there were hydrocarbons present, they are not in sufficient quantities to be economic. Therefore, we have elected to plug and abandon this well bore.
 
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 continue 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).
 
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 dollars 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.  However, for the 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.
 
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 our acreage increasing to 5,061 by December 31, 2013. Within a week the Boeckman #1-H well was spud and was subsequently completed and fracture stimulated in July.  At present, the Boeckman well continues to produce at a rate of 85 barrels of oil per day and 450 thousand cubic feet of gas per day. We acquired a working interest in the Boeckman #1-H well and subsequently sold part of our ownership in the Boeckman well for $990,000. The purchaser executed a promissory note dated May 1, 2013 for the purchase. We have collected the balance in full as of the date of these financial statements. We agreed to a preferential payout to the purchaser equal to 50% of his acquired interest.  The agreement was amended in the first quarter of 2014 to include our agreement to advance funds under a note receivable from the purchaser to be repaid from the purchaser’s revenue preference subsequent to October, 2014.  Revenue payable to the investor based on revenue to December 31, 2013 has been accrued in the accompanying financial statements.

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 our acreage to 8,665 as of December 31, 2013. This acquisition will allow us to participate in 60+ gross wells in the coming two years.  This acquisition along with the previous acreage position in the Cimarron Trail will give us 80+ drilling locations in the entire play.  It is our intention to continue to increase this position through advanced leasing and forced pooling.

 
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At the end of November 2013, in addition to the producing Boeckman well, our operator Husky Ventures Inc. was actively drilling four wells in which we owned an interest.  Two of these wells, we financed by a third party, whereby they paid 100% of the costs and we retained a small ORRI and a small working interest.  The second two, we paid our AFE directly and we are participating in these wells based on our pro-rated working interest.

In the fourth quarter of 2013 we entered into our 3rd 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.   Leasing is continuing monthly so that we had an interest in 4,326 acres as of December 31, 2013. Husky recently spud the first two wells in the AMI. 

In January of 2014, we again elected to continue to expand in the Hunton Play with Husky Ventures.  We again contracted for a 25% Working Interest in an AMI consisting of eight townships in South Central Oklahoma.  There is an active leasing program in this AMI as well with over 5,000 acres under lease.  We expect to spud our first well in this AMI by July of 2014.  Lastly, in February of 2014, we picked up a 10% Working Interest in a well in the Prairie Grove AMI that is currently drilling.  We picked up this interest from a non-consenting third party who elected not to participate in the well.  Currently, we are actively producing, drilling, fracking, or flowing back in twenty-two wells across all of our AMI’s with Husky Ventures.

Salt Water Disposal Facility

As part of the Xtreme transaction we also acquired 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 is a state of the art disposal facility which can 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.  During the second quarter, the facility averaged only approximately 2,000 barrels of fluids per day. But with increasing activity in the area, we anticipate that volume increasing in the future.  With only a royalty, we have no working interest and are therefore not responsible for any operating expenses.  We do however have the right to a working interest of 37.5% when the original investors in the facility receive a payout of their investment.

Project Prospects

We have an ongoing process to identify specific projects that we will consider investing in, pending our ability to obtain adequate funding.  We have not yet conducted thorough due diligence on any project prospect, nor had we made any significant commitments on any new projects as of December 31, 2013, beyond the continued involvement and expansion of our current projects with our partners.  There is no assurance we will choose to invest in any of these projects, if and when adequate funding becomes available.

Industry and Business Environment

Our industry and its business environment have been altered during the last decade and in particular since Torchlight was founded in early 2010.  Population in the US has increased by nearly 40 million people in the last decade.  Yet our demand for crude oil has remained relatively constant at slightly less than 20 million barrels per day. When Torchlight was founded in 2010, over one-half of US crude oil daily requirements were imported; with a significant amount from non-North American sources.  The industry was also just beginning to see production from shale resource plays make an impact and a “land rush” to acquire mineral leases was exploding.  The “Shale Gale” as some in the industry call it was just starting to gain momentum.  In particular resource plays in the Bakken formation of North Dakota, the Eagle Ford formation in Texas and the Marcelius of the Eastern U.S. drew industry attention.  Acreage costs skyrocketed and huge deals such as the Marathon Oil-Hillcorp acquisition made headlines.

Since then, the industry has steadily increased the number of wells drilled and improved completion techniques, increasing production, and lowered capital requirements.  The Bakken formation and the Eagle Ford formation now each produce 1 million barrels of oil per day to add to our domestic supply.  With additional secure domestic supply this has allowed the US to significantly reduce its reliance on non-North American crude sources, namely the Middle East.

Industry sources that look at long term planning forecast that the “Shale Gale” could provide secure domestic supplies well into the mid 21st century and further reduce our need to import non-North American crude. Added to this is the Keystone Pipeline Project from Canada which is under construction in several states.  It will bring crude oil extracted from tar sands in Alberta Province to US refineries.  Federal approval is needed however to make the international link between the US and Canada. This flood of activity in the resource plays provides opportunities to Torchlight.  The conventional plays, or exploitation plays such as our Hunton projects are avoided by the resource players creating a vacuum into which we can selectively locate and exploit at reasonable costs.  Projects in plays where production has previously been proven, infrastructure exists, and entry costs are modest will provide Torchlight a platform for additional growth in the future.  Our projects in the Hunton in Oklahoma, the Mississippian formations in Kansas, and the Marcelina Creek block in Texas are examples of such opportunities. Additional opportunities come as leases that had not been drilled come available.  With the land rush by companies to acquire lease several years ago not all could be drilled and converted to production, they will create an inventory of leases from which to select. As for natural gas, Torchlight’s focus has been on liquids-rich projects, but should the opportunity present itself for a gas project it will be considered.  Natural gas resource plays such as the Marcelius in the Eastern US provide huge resource potential in the densely populated area.  Gas prices parallel weather and with the cold winter of 2013 and the subsequent very cold weather of early 2014, gas prices have escalated to unprecedented amounts. Longer-term gas production will be increasing as the resource plays are drilled.  There is now the opportunity for the industry to develop an export strategy for the gas which would receive a short-term spike in prices since world gas prices are more than  50 percent greater than domestic gas prices.  However we believe that in the longer term prices will stabilize much as they are now with spikes in prices based on weather. In summary, we believe that demand in the US will show only slight growth as more efficient auto engines and alternative fuels offset population growth.  Prices for crude oil will be reasonably stable but subject to external international incidents.  Increased gas markets, such as exports may create opportunities for small gas projects in which Torchlight could participate.  As the larger plays keep their focus on the resource plays the opportunities in conventional plays will remain, providing Torchlight with a pipeline of projects to evaluate.  Lastly, should the opportunity to expand into the resource plays we will have the benefit, without the cost, of the experience the industry has gained in the last years.
 
 
 
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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.
 
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.

 

 
 
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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.

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, 2013 and 2012.

 
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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.
 
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. 

 

 
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We have not yet achieved profitable operations, have significant accumulated losses since our inception, and expect to incur further losses in the development of our business
 
At December 31, 2013, we had not yet achieved profitable operations, had accumulated losses of $15,840,959 since our inception, and expect to incur further losses in the development of our business.  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.

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:
 
 
 
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·
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.

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.
 
 
 
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We may not be able to successfully manage our growth, which could lead to our inability to implement our business plan.

Our growth is expected to 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.
 
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.
 
 
 
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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.

Further, the EPA has asserted federal regulatory authority over hydraulic fracturing involving “diesel fuels” under the SWDA’s UIC Program and has released final guidance regarding the process for obtaining a permit for hydraulic fracturing involving diesel fuel. The EPA also has commenced a study of the potential impacts of hydraulic fracturing activities on drinking water resources, with a progress report released in late 2012 and a final draft report expected to be released for public comment and peer review in late 2014. The EPA’s guidance, including its interpretation of the meaning of “diesel fuel,” the EPA’s pending study, and other analyses by federal and state agencies to assess the impacts of hydraulic fracturing could each 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.
  
 
16

 
 
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 43% of our outstanding common stock.  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.
 
 
 
17

 
 
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 not effective as of December 31, 2013.  We are, however, addressing the issue and performing a final update of our policies and procedures.  Upon finalizing these policies and procedures and ensuring they are effectively applied, we believe our internal control will be deemed effective.  Correcting this issue, and thereafter our continued 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 hire additional accounting and financial staff with appropriate public company experience and technical accounting knowledge. Moreover, if we are not able to correct our internal control issues and 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.

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 convertible promissory notes that are presently convertible and warrants that are presently exercisable.  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.

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.
 
 
 
18

 

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 2013 is detailed as follows:

   
2013
   
2012
 
Property acquisition costs
 
$
6,274,154
   
$
529,184
 
Development costs
   
3,885,730
     
323,955
 
Exploratory costs
 
$
-0-
   
$
-0-
 

Oil and Natural Gas Reserves

Reserve Estimates

SEC Case. The following tables sets forth, as of December 31, 2013, 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, 2013 and 2012 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, 2013 and 2012, respectively, were $7,093,985 and $499,433.

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, 2013. For purposes of determining prices, we used the average of prices received for each month within the 12-month period ended December 31, 2013, adjusted for quality and location differences, which was $97.08 per barrel of oil and $5.85 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.
 
   
December 31, 2013
 
December 31, 2013
 
   
Reserves
 
Future Net Revenue (M$)
 
                       
Present Value Discounted
 
Category
 
Oil (Bbls)
   
Gas (Mcf)
   
Total (BOE)
 
Total
 
at 10%
 
                           
Proved Developed
    113,092       313,251       165,301     $ 8,861     $ 6,117  
Proved Undeveloped
    930,069       2,826,344       1,401,126     $ 44,699     $ 20,408  
Total Proved
    1,043,161       3,139,595       1,566,427     $ 53,560     $ 26,525  
                                         
Standardized Measure of Future Net Cash Flows Related to Proved Oil and Gas Properties
    $ 19,691  
                                         
Probable Undeveloped
    657,800       0       657,800     $ 33,571     $ 16,253  
 
 
 
19

 
 
BOE equivalents are determined by combining barrels of oil with MCF of gas divided by six.
 
   
December 31, 2012
   
December 31, 2012
 
   
Reserves
   
Future Net Revenue (M$)
 
                           
Present Value Discounted
 
Category
 
Oil (Bbls)
   
Gas (Mcf)
   
Total (BOE)
   
Total
   
at 10%
 
                               
Proved Developed Producing
    24,800       0       24,800     $ 1,397     $ 1,169  
Proved Undeveloped
    392,700       0       392,700     $ 8,538     $ 2,131  
Total Proved
    417,500       0       417,500       9,935       3,300  
                                         
Standardized Measure of Future Net Cash Flows Related to Proved Oil and Gas Properties
    $ 2,909  
Probable Undeveloped
    937,100       0       937,100     $ 30,986     $ 12,237  
 
For the year ended December 31, 2012 all of the Company’s Oil and Gas properties were located in the Marcelina Project in Texas which produces no gas.

The increase of 1,008,426 BOE (979,800 for our Hunton Project and 28,626 for our Marcelina Project) in proved undeveloped reserves comes from the third party engineering studies of the Cimarron and Chisholm Trail AMI's in Oklahoma which were acquired by the Company in 2013 and engineering for our Marcelina Project.  The increase consists of an increase of 537,369 barrels of oil plus an additional 471,057 BOE from conversion of natural gas reserves using MCFD/6.
 
 
 
 
 
 
 
 
 
 
 

 
 
20

 
 
Standardized Measure of Oil & Gas Quantities - Volume Rollforward
 
Year Ended December 31, 2013 and 2012
 
                         
The following table sets forth the Company’s net proved reserves, including the changes therein, and proved developed reserves:
 
                         
                         
   
2013
   
2012
 
   
Oil (Bbls)
   
Gas (Mcf)
   
Oil (Bbls)
   
Gas (Mcf)
 
TOTAL PROVED RESERVES:
                       
Beginning of period
   
417,500
     
-
     
-
     
-
 
Acquisition
   
572,461
     
3,139, 596
     
-
     
-
 
Extensions and discoveries
   
101,229
     
-
     
428,155
     
-
 
Revisions of previous estimates
   
(34,743
)
   
3,539
     
-
     
-
 
Production
   
(13,286
)
   
(3,540
)
   
(10,655
)
   
-
 
End of period
   
1,043,161
     
3,139,595
     
417,500
     
-
 
                                 
                                 
PROVED DEVELOPED RESERVES
                               
Proved developed producing
   
64,858
     
108,001
     
24, 800
     
-
 
Proved developed nonproducing
   
48,234
     
205,250
     
-
     
-
 
Total
   
113,092
     
313,251
     
24, 800
     
-
 
                                 
Total PUD
   
930,069
     
2,826, 344
     
392,700
     
-
 
 
The preceding table shows significant increases in  the Acquisition  category for 2013 as compared to 2012.

The 2013 Extension and Discoveries is impacted by drilling of the Johnson #2 well in the Buda formation, which resulted in the addition of two new proved undeveloped locations.  Additionally, four new proved undeveloped locations offset to the Johnson #1 in the Austin Chalk formation were added.  The Buda locations account for a  45,613 BO increase in proved reserves, and the Austin Chalk locations account for  55,616 BO in additional proved reserves.  All locations assigned are within one offsetting location away from the nearest proved producing well in the same formation.

The 2013 Revisions of Previous Estimates are composed of revisions to the proved producing and proved undeveloped reserves. The negative 34,743 BO total revision is comprised of a positive 12,700 BO adjustment due primarily to improved performance from the Johnson 1 and Johnson 4 wells, and a negative  47,443 BO adjustment for two proved undeveloped locations in the Eagle Ford formation.  Performance of offset producing Eagle Ford wells is analyzed to estimate proved undeveloped reserves on the Company's lease, and the 2013 analysis of the offset wells resulted in a reduction of their estimated ultimate recoveries compared to 2012 estimates.
 
 
 
 

 
21

 

The 2013 Acquisition increase is all related to the working interest acquired in the Cimarron and the Chisholm Trail AMI's with Husky Ventures in Oklahoma during 2013.

The increase in 2012 Extensions and discoveries are the result of completing our Johnson #4 well.
 
Standardized Measure of Oil & Gas Quantities
 
Year Ended December 31, 2013 & 2012
 
             
The standardized measure of discounted future net cash flows relating
           
to proved oil and natural gas reserves is as follows (in thousands):
 
2013
   
2012
 
             
Future cash inflows
 
$
119,629,906
   
$
41,103,000
 
Future production costs
   
(31,656,853
)
   
(12,413,000
)
Future development costs
   
(34,152,898
)
   
(18,755,000
)
Future income tax expense
   
(11,264,101
)
   
(1,012,000
)
Future net cash flows
   
42,556,054
     
8,923,000
 
10% annual discount for estimated
               
timing of cash flows
   
(22,865,456
)
   
(6,014,000
)
Standardized measure of discounted future
               
net cash flows related to proved reserves
 
$
19,690,598
   
$
2,909,000
 
                 
                 
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 (in thousands):
               
     
2013
     
2012
 
Balance, beginning of period
 
$
2,909,000
   
$
-
 
Sales and transfers of oil and gas produced during the period
   
(905,125
)
   
-
 
Net change in sales and transfer prices and in production (lifting) costs related to future production
   
2,267,471
     
-
 
Net change due to purchases of minerals in place
   
30,474,988
     
-
 
Net change due to extensions and discoveries
   
2,814,577
     
-
 
Changes in estimated future development costs
   
(17,355,723
)
   
-
 
Previously estimated development costs incurred during the period
   
3,181,356
     
-
 
Net change due to revisions in quantity estimates
   
(949,883
)
   
-
 
Other
   
2,001,122
     
-
 
Accretion of discount
   
329,960
     
-
 
Net change in income taxes
   
(5,077,145
)
   
-
 
Balance, end of period
 
$
19,690,598
   
$
-
 

 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.


 
22

 

Reserve Estimation Process, Controls and Technologies
 
The reserve estimates, including PV-10 estimates, set forth above were prepared by Netherland, Sewell & Associates, Inc. and Wright & Company, Inc.  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.

Our Chief Executive Officer is an experienced and qualified geoscience professional with a degree in geophysical science, but we do not have any employees with specific reservoir engineering qualifications in the company.  Our Chief Executive Officer worked closely with Netherland, Sewell & Associates, Inc. and Wright & Company 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.

Netherland, Sewell & Associates, Inc. (“NSAI”) is a large Texas-based professional engineering firm specializing in technical and financial evaluation of oil and gas assets.  NSAI used a combination of performance analysis and analogy, using technical and economic data including but not limited to well logs, well test data, and production data.  Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI reserves report is C. Ashley Smith.  Mr. Smith has been practicing consulting petroleum engineering at NSAI since 2006.  Mr. Smith is a Licensed Professional Engineer in the State of Texas (No. 100560) and has over 13 years of practical experience in petroleum engineering, with over 7 years experience in the estimation and evaluation of reserves.  He graduated from University of Missouri-Rolla (Missouri University of Science & Technology) in 2000 with a Bachelor of Science Degree in Petroleum Engineering.  Mr. Smith meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; Mr. Smith is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Wright & Company Inc. (“Wright”) is a Tennessee based professional engineering firm made up of petroleum engineers, geologists, geophysicists, and petro physicists that specialize in technical and financial evaluation of oil and gas assets.  They used a combination of production and pressure performance, simulation studies, offset analogies, seismic data and interpretation, geophysical logs, and other relevant field data to calculate our reserves estimates.  D. Randall Wright is the primary technical person in charge of the estimates of reserves and associated cash flow and economics on behalf of Wright for the results presented in its reserves report to us.  He has a Master of Science degree in Mechanical Engineering from Tennessee Technological University.  He is a qualified Reserves Estimator as set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers.  This qualification is based on more than 40 years of practical experience in the estimation and evaluation of petroleum reserves with Texaco, Inc., First City National Bank of Houston, Sipes, Williamson & Associates, Inc., Williamson Petroleum Consultants, Inc., and Wright which he founded in 1988.  He is a registered Professional Engineer in the state of Texas (TBPE #43291), granted in 1978, a member of the Society of Petroleum Engineers and a member of the Order of the Engineer.

Proved Undeveloped Reserves

As of December 31, 2013, our proved undeveloped reserves totaled 1,401,126 barrels of oil equivalents compared to 392,700 as of December 31, 2012, a total increase of 1,008,426.  These proved undeveloped reserves at December 31, 2013 were associated with our Marcelina Creek Field property (which increased by 28,626) and our Hunton projects (which account for an increase of 979,800, all of which were acquired in 2013). These numbers are taken from the third party reserves studies by Netherland, Sewell and Associates and Wright & Company.

This increase of 979,800 BOE in proved undeveloped reserves  attributable to our Hunton projects comes from the third party engineering study from Wright & Company of the Cimarron and Chisholm Trail AMI's in Oklahoma which were acquired by the Company in 2013.  The net reserves increase associated with these properties is approximately 508.8 Mbbl of oil and 2,826.3 MMcf of gas, or 979.8 MBOE calculated with a gas-oil equivalency factor of six.  We acquired an interest in the Boeckman 1-14H well in May 2013, representing our first property in Oklahoma.  Over the course of 2013, we acquired interests in five wells that were producing by December 31, 2013. These were considered proved developed producing (PDP) and include the Boeckman 1-14H, Hancock 1-25H, Robinson 1-30H, School Land 1-36H and Stevens 1-36H.  During 2013, we also acquired interests in six other wells that were drilled and completed, but not producing, by December 31, 2013. These were considered proved developed non-producing (PDNP) and include the Coronado 1-3H, CW 1-4H, Jet 1-12H, Jones 1-21H, Liebhart 1-31H, and Mel B 1-33H.
 
With respect to our Marcelina Project, the increase in proved undeveloped reserves of 28,626 BO in Texas is due to a combination of factors.  The Johnson #2 well was drilled in 2013, which resulted in moving 22,674 BO from proved undeveloped to proved developed.  In addition, a negative revision of 49,900 BO was due to a decrease in expected recovery from two undeveloped locations in the Eagle Ford formation.  This reduction was based on analysis by Netherland, Sewell & Associates, Inc. of performance for offset Eagle Ford producers adjacent to the Company's lease.

 
23

 

Proved undeveloped reserves were increased by 101,200 BO due to the addition of new locations in the Buda and Austin Chalk formations.  The Johnson #2 well drilled in 2013 resulted in two new Buda locations directly offset to the west and northwest, and four locations in the Austin Chalk were added that are directly offset to the Johnson #1 well.
 
We made various investments and progress during 2013 to convert proved undeveloped reserves to proved developed reserves.  Wells that were converted from proved undeveloped reserves to developed include the Hancock, Robinson, Boeckman, Stevens, and School Land. The capital expenditures incurred in converting our proved undeveloped reserves to developed were approximately $1,198,130.  We believe that nearly all of our proved undeveloped reserves as of December 31, 2013 will be developed within five years.  Limitations on our ability to develop proved undeveloped reserves within five years would likely be due to restraints on our capital and/or personnel moving forward.  The restraints, however, could be alleviated through increased revenue or additional funding.

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 undeveloped reserves during 2014 and 2015.  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 undeveloped locations and other potential Eagle Ford drilling locations on our acreage.  Further we will maintain our continuous drilling program in the Hunton projects for the foreseeable future.

Production, Price, and Production Cost History
 
During the year ended December 31, 2013, we produced and sold 13,286 barrels of oil net to our interest at an average sale price of $100.67 per bbl. We produced and sold 3,540 MCF of gas net to our interest at an average sales price of $5.68 per MCF.  Our average production cost including lease operating expenses and direct production taxes was $31.29 per bbl.  Our depreciation, depletion, and amortization expense was $49.09 per bbl.

During the year ended December 31, 2012, we produced and sold 10,655 barrels of oil net to our interest at an average sale price of $97.35 per bbl.  We had no gas production.  Our average production cost including lease operating expenses and direct production taxes was $46.93 per bbl.  Our depreciation, depletion, and amortization expense was $51.80 per bbl.

Our production is from properties concentrated in central Oklahoma and in southern Texas. Reserves from each of these areas comprise more than 15% of total reserves. For 2012, 100% of our production came from Marcelina Creek.  For 2013, approximately 88 BOPD was being produced at Marcelina Creek and approximately 47 BOEPD in Oklahoma, or 65% from Marcelina Creek and 35% from Oklahoma.

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, 2013, we had three productive wells in the Marcelina Creek Field (2.00 net wells) and one well which was in the process of being tested 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.  As of December 31, 2013 these five wells were producing and the Company was a participant in six additional wells that were either drilling or in the process of completing at year end.

 
24

 

Our producing wells included the Hancock (0.01 WI, 0.8 BOEPD), the Robinson (0.0025 WI, 0.2 BOEPD), the Boeckman (0.1891 WI, 33.4 BOEPD), the Stevens (0.0173 WI, 7.2 BOEPD), and the School Land (0.005 WI, 6.4 BOEPD), amounting to net producing wells of 22.39% of one well.

Present activities in Oklahoma at December 31, 2013 include wells in process of being drilled - the CW (0.0225 WI), the Mel B (0.075 WI), the Jet (0.0191 WI), the Rosemary (0.1246 WI), the Jones (0.0213 WI), and the Liebhart (0.0308 WI), amounting to net testing wells of 29.33% of one well.

 Combined Well Status
The following table summarizes drilling activity and Well Status at December 31, 2013:
 
   
Cumulative Well Status
                                     
Drilling Activity/Well Status
 
at 12/31/2013
   
2013
   
2012
   
2011
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
                                                 
Development Wells:
                                               
Productive -Texas
   
3
     
2.00
     
1
     
0.75
     
1
     
0.75
     
1
     
0.50
 
Productive - Okla
   
3
     
0.21
     
3
     
0.21
     
0
     
0.00
     
0
     
0.00
 
Dry
   
0
     
0.00
     
0
     
0.00
     
0
     
0.00
     
0
     
0.00
 
                                                                 
Exploration Wells:
                                                               
Productive
   
0
     
0.00
     
0
     
0.00
     
0
     
0.00
     
0
     
0.00
 
Dry
   
0
     
0.00
     
0
     
0.00
     
0
     
0.00
     
0
     
0.00
 
                                                                 
                                                                 
Total Drilled Wells:
                                                               
Productive -Texas
   
3
     
2.00
     
1
     
0.75
     
1
     
0.75
     
1
     
0.50
 
Productive - Okla
   
3
     
0.21
     
3
     
0.21
     
0
     
0.00
     
0
     
0.00
 
Dry
   
0
     
0.00
     
0
     
0.00
     
0
     
0.00
     
0
     
0.00
 
                                                                 
                                                                 
                                                                 
Acquired Wells:
                                                               
Productive -Texas
   
1
     
0.40
     
0
     
0.00
     
1
     
0.40
     
0
     
0.00
 
Productive - Okla
   
2
     
0.013
     
2
     
0.013
     
0
     
0.00
     
0
     
0.00
 
                                                                 
                                                                 
                                                                 
Total Wells:
                                                               
Productive -Texas
   
4
     
2.40
     
1
     
0.75
     
2
     
1.15
     
1
     
0.50
 
Productive - Okla
   
5
     
0.223
     
5
     
0.223
     
0
     
0.00
     
0
     
0.00
 
                                                                 
Total
   
9
     
2.623
     
6.00
     
0.973
     
2.00
     
1.15
     
1.00
     
0.50
 
                                                                 
Well Type:
                                                               
Oil
   
3
     
2.00
     
1
     
0.75
     
1
     
0.75
     
1
     
0.50
 
Gas
   
1
     
0.40
     
0
     
0.00
     
1
     
0.40
     
0
     
0.00
 
Combination -Oil and Gas
   
5
     
0.223
     
5
     
0.223
     
0
     
0.00
     
0
     
0.00
 
                                                                 
Total
   
9
     
2.623
     
6.00
     
0.9725
     
2.00
     
1.15
     
1.00
     
0.50
 


 
25

 

Our acreage positions at December 31, 2013 are summarized as follows:
 
   
Total Acres
   
Developed Acres
   
Undeveloped Acres
 
Leasehold Interests - 12/31/2013
 
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
                                     
Texas -
                                   
Marcelina Creek
   
1,045
     
714
     
360
     
230
     
685
     
484
 
Coulter Field
   
940
     
376
     
940
     
376
     
0
     
0
 
                                                 
Oklahoma -
                                               
Cimmarron
   
5,061
     
893
     
1,760
     
143
     
3,301
     
750
 
Chisholm Trail
   
8,665
     
1,560
     
3,200
     
60
     
5,465
     
1,500
 
Viking
   
4,326
     
1,082
     
0
     
0
     
4,326
     
1,082
 
                                                 
Kansas -
                                               
Smokey Hill
   
11,752
     
2,091
     
0
     
0
     
11,752
     
2,091
 
                                                 
                                                 
Total
   
31,789
     
6,715
     
6,260
     
809
     
25,529
     
5,907
 
 
The Marcelina Creek Project consists of 1,045 acres all of which are held by production.
 
The Central Oklahoma Projects acreage is in three AMI’s as of December 31, 2013 with a combined total of 18,052 gross acres.  Producing wells (5) and wells under development (6) comprise 4,960 acres with the balance subject to a managed drilling program to retain leases for long term development.  The leases have two to three year terms. The drilling program being executed will hold the leases by production within those terms

The Smokey Hills acquisition included approximately 16,000 gross acres and a well, the Hoffman 1-H within the greater Lindsborg Field area.  Since development did not continue due to the need for analysis after the Hoffman initial well experience, the acreage position declined from approximately 16,000 acres at acquisition to approximately 11,752 at December 31, 2013.  We are planning to drill a ten well program late in Q2 or early Q3, 2014 to evaluate the possibility of producing the formation in a traditional vertical method.  Of the 800 wells of interest in the area, all were produced vertically and in economic quantities.

The results of the ten well program will drive the continuing development of the Smokey Hills acreage. Based on the economic success of the first ten wells and the geological analysis of the acreage, a drilling program will continue at an initial planned pace of four wells each month which will hold 640 additional acres per month. The leases are beyond their primary term and in their two year extension period. The leases are scheduled to expire over the period from third quarter 2014 through third quarter 2015.  As continued drilling generates economic success we plan to increase the pace of drilling sufficient to develop 100% of the acreage prior to expiration of any of the acreage undeveloped as of December 31, 2013.

Net acres in all areas are approximately 6,715 at December 31, 2013.

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 for the Marcelina Creek prospect and the East Stockdale prospect.  We allege that Hockley Energy did not perform its obligations under the agreements, which obligations included providing the agreed upon funding, and we seek damages against both Hockley and Mr. Snortheim (who is a shareholder of Hockley Energy) for breach of contract, fraudulent inducement, and promissory estoppel.  Each defendant has answered our original petition with a general denial, and we have filed a motion for default judgment. A trial date has been set for April 28, 2014.  We have also had discussions with the defendants regarding resolving this matter out of court, but we have not reached an agreement to date.

ITEM 4.  MINE SAFETY DISCLOSURES

Not Applicable.

 
26

 
 
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, 2013 and 2012, according to NASDAQ, were as follows:
 
Quarter Ended
 
High
   
Low
 
December 31, 2013
 
$
6.75
   
$
2.65
 
September 30, 2013
 
$
3.50
   
$
1.85
 
June 30, 2013
 
$
2.34
   
$
1.70
 
March 31, 2013
 
$
2.31
   
$
1.75
 
December 31, 2012
 
$
2.66
   
$
1.60
 
September 30, 2012
 
$
2.45
   
$
1.14
 
June 30, 2012
 
$
1.60
   
$
0.73
 
March 31, 2012
 
$
2.05
   
$
0.79
 

Record Holders

As of March 20, 2014, there were approximately 238 stockholders of record holding a total of 18,270,408 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 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.

Equity Compensation Plan Information

As of December 31, 2013, we did not have any compensation plans (including individual compensation arrangements) under which our equity securities are authorized for issuance.

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.

In December 2013, investors exercised warrant agreements, whereby they purchased from us a total of 101,714 shares of common stock at a price of $2.00 per share.  The securities were issued under the exemption from registration provided by Section 4(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 the securities were isolated private transactions; (ii) a limited number of securities were issued to a single purchaser; (iii) there were no public solicitations; (iv) the purchaser previously represented that he was an “accredited investors”; (v) the investment intent of the purchaser; and (vi) the restriction on transferability of the securities issued.

ITEM 6.  SELECTED FINANCIAL DATA

Not Applicable.




 
27

 

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

The 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-Q. 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.

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, 2013.  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.  
 
 
 
 
 
 
 
 
 
 
 
 

 

 
28

 

Historical Results for the Years Ended December 31, 2013 and 2012

Revenues and Cost of Revenues

For the year ended December 31, 2013, we had production revenue of $1,243,998 compared to $1,037,247 of production revenue for the year ended December 31, 2012.  During the first half of 2013, production began a natural decline in both the Marcelina Johnson #1-BH and the Johnson #4 wells. During third quarter the new drill, the Johnson #2, began production. Oklahoma production began in third quarter from the Company’s participation in the Hunton wells. Refer to the table of production and revenue for 2013 included below.  Our cost of revenue, consisting of lease operating expenses and production taxes, was $434,119, and $500,053 for the years ended December 31, 2013 and 2012, respectively.

Property
 
Quarter
   
Oil Production {BBLS}
   
Gas Production {MCF}
   
Oil Revenue
($)
   
Gas Revenue
($)
   
Total Revenue
($)
 
Marcelina
 
Q1 - 2013
     
2,255
     
0
     
229,204
     
-
     
229,204
 
Oklahoma
 
Q1 - 2013
     
0
     
0
     
-
     
-
     
-
 
Total Q1
         
2,255
     
0
     
229,204
     
-
     
229,204
 
Marcelina
 
Q2 - 2013
     
1,673
     
0
     
160,823
     
-
     
160,823
 
Oklahoma
 
Q2 - 2013
     
0
     
0
     
-
     
-
     
-
 
Total Q2
         
1,673
     
0
     
160,823
     
-
     
160,823
 
Marcelina
 
Q3 - 2013
     
3,896
     
0
     
387,872
     
-
     
387,872
 
Oklahoma
 
Q3 - 2013
     
316
     
1,321
     
7,064
     
-
     
7,064
 
Total Q3
         
4,212
     
1,321
     
394,936
     
-
     
394,936
 
Marcelina
 
Q4 - 2013
     
4,626
     
0
     
401,956
     
-
     
401,956
 
Oklahoma
 
Q4 - 2013
     
519
     
2,220
     
47,793
     
9,286
     
57,079
 
Total Q4
         
5,145
     
2,220
     
449,749
     
9,286
     
459,035
 
                                               
Year ended 12/31/13
         
13,285
     
3,541
     
1,234,712
     
9,286
     
1,243,998
 

We recorded depreciation, depletion and amortization expense of $652,179 for the year ended December 31, 2013.

General and Administrative Expenses

Our general and administrative expenses for the years ended December 31, 2013 and 2012 were $6,682,377 and $2,430,884, respectively, an increase of $4,251,493. Our general and administrative expenses consisted of consulting and compensation expense, substantially all of which was non-cash or deferred, accounting and administrative costs, professional consulting fees, and other general corporate expenses.  The increase in general and administrative expenses for the year ended December 31, 2013 compared to 2012 is primarily related to a $408,117 increase in investor relations expense and a $3,062,427 increase in stock based compensation.

Liquidity and Capital Resources

At December 31, 2013, we had working capital of $(468,453), current assets of $2,250,556 consisting of cash, accounts receivable, and prepaid expenses, and total assets of $16,743,321 consisting of current assets, investments in oil and gas properties, and goodwill. As of December 31, 2013, we had current liabilities of $2,719,009, consisting of accounts payable, payables to related parties, notes payable, and accrued interest, and stockholders’ equity was $9,197,219.
 
Cash flow used in operating activities for the years ended December 31, 2013, was $2,262,636 compared to $130,274 for the year ended December 31, 2012, an increase of $2,132,362. Cash flow used in operating activities during 2013 can be primarily attributed to net losses from operations of $10,418,662, which consists primarily of $6,682,377 in general and administrative expenses ($4,331,143 of which are non-cash stock based compensation), depreciation, depletion, and amortization of $652,179, and accretion of convertible note discounts $3,894,389. Cash flow used in operating activities during 2012 can be primarily attributed to net losses from operations of $2,808,803, which consists primarily of $2,430,884 in general and administrative expenses ($1,268,216 of which are non-cash  stock based compensation), depreciation, depletion, and amortization of $551,890, and accretion of convertible note discounts $313,963. We expect to continue to use cash flow in operating activities until such time as we achieve sufficient commercial oil and gas production to cover all of our cash costs.
 
Cash flow used in investing activities for year ended December 31, 2013 was $8,587,104 compared to $830,755 for the year ended December 31, 2012.  Cash flow used in investing activities consists primarily of oil and gas investments in the Johnson wells in the Marcelina Creek Field and the Oklahoma properties acquired during the year ended December 31, 2013.

 
29

 

Cash flow provided by financing activities for the year ended December 31, 2013 was $12,598,201 as compared to $506,000 for the year ended December 31, 2012.  Cash flow provided by financing activities in 2013 consists of convertible promissory notes issued for cash, net of repayments of debt, and proceeds from common stock issues and warrant exercises.  We expect to continue to have cash flow provided by financing activities as we seek new rounds of financing and continue to develop our oil and gas investments.

Our current assets are insufficient to meet our current obligations or to satisfy our cash needs over the next twelve months and as such we will require additional debt or equity financing. Subsequent to December 31, 2013, we received net proceeds of approximately $6.15 million from the offering of units of equity consisting of our common stock and warrants, but these proceeds will not be sufficient to fund all of our proposed drilling operations and operating needs during 2014. We will seek additional financing to meet these plans and needs.  We face obstacles in continuing to attract new financing due to our history and current record of net losses and working capital deficits. Therefore, despite our efforts, we can provide no assurance that we will be able to obtain the financing required to meet our stated objectives or even to continue as a going concern.

We do not expect to pay cash dividends in the foreseeable future.

Commitments and Contingencies

We are subject to contingencies as a result of environmental laws and regulations. Present and future environmental laws and regulations applicable to our operations could require substantial capital expenditures or could adversely affect our operations in other ways that cannot be predicted at this time.  As of December 31, 2013 and December 31, 2012, no amounts have been recorded because no specific liability has been identified that is reasonably probable of requiring us to fund any future material amounts.

We currently have interests in five oil and gas projects, the Marcelina Creek Field Development in Wilson County, Texas, the Coulter Field in Waller County, Texas, projects in Logan and Kingfisher counties, Oklahoma and projects in McPherson, and Gray and Finney counties in Kansas.  See the description under “Current Projects” above under “Item 1.  Business” for more information and disclosure regarding commitments and contingencies relating to these projects.  
 
ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not Applicable.

 
 
 
 
 

 
 
30

 


ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Our comparative financial statements for the fiscal year ended December 31, 2013 are attached hereto.

 
31

 

 
TORCHLIGHT ENERGY RESOURCES, INC.
           
             
CONSOLIDATED BALANCE SHEETS
           
   
December 31,
   
December 31,
 
   
2013
   
2012
 
ASSETS
           
Current assets:
           
Cash
 
$
1,811,713
   
$
63,252
 
Accounts receivable
   
429,699
     
92,897
 
Prepaid expenses
   
9,144
     
8,346
 
Total current assets
   
2,250,556
     
164,495
 
                 
Investment in oil and gas properties, net
   
13,038,751
     
3,461,686
 
Office equipment
   
11,604
         
Debt issuance costs, net
   
920,947
     
473,785
 
Goodwill
   
447,084
     
447,084
 
Other Assets
   
74,379
     
-
 
                 
TOTAL ASSETS
 
$
16,743,321
   
$
4,547,050
 
                 
LIABILITIES AND STOCKHOLDERS' EQUITY
               
Current liabilities:
               
Accounts payable
 
$
985,123
   
$
89,247
 
Accrued liabilities
   
-
     
62,055
 
Related party payables
   
90,000
     
768,648
 
Notes payable
   
753,904
     
51,000
 
Due to working interest owners
   
580,484
     
-
 
Interest payable
   
309,498
     
10,581
 
Total current liabilities
   
2,719,009
     
981,531
 
                 
Convertible promissory notes, net of discount of $5,500,462 and $521,864 at December 31, 2013 and December 31, 2012, respectively
   
4,802,711
     
580,636
 
Asset retirement obligation
   
24,382
     
12,614
 
Commitments and contingencies
   
-
     
-
 
Stockholders’ equity:
               
Common stock, par value $0.001 per share; 75,000,000 shares authorized;
   
16,142
     
13,565
 
16,141,765 issued and outstanding at December 30, 2013
13,564,815 issued and outstanding at December 31, 2012
Additional paid-in capital
   
21,978,616
     
8,381,001
 
Warrants outstanding
   
3,043,420
     
-
 
Accumulated deficit
   
(15,840,959
)
   
(5,422,297
)
Total stockholders' equity
   
9,197,219
     
2,972,269
 
                 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
 
$
16,743,321
   
$
4,547,050
 



 
32

 

 
TORCHLIGHT ENERGY RESOURCES, INC.
 
             
CONSOLIDATED STATEMENTS OF OPERATIONS
 
             
             
   
YEAR
   
YEAR
 
   
ENDED
   
ENDED
 
   
DECEMBER 31, 2013
   
DECEMBER 31, 2012
 
Revenue
           
Oil and gas sales
 
$
1,243,998
   
$
1,037,247
 
Royalties
   
51,501
     
-
 
                 
Cost of revenue
   
(434,119
)
   
(500,053
)
                 
Gross income
   
861,380
     
537,194
 
                 
Operating expenses:
               
General and administrative
   
6,682,377
     
2,430,884
 
Depreciation, depletion, and amortization
   
652,179
     
551,890
 
Total operating expenses
   
7,334,556
     
2,982,774
 
                 
Other income (expense)
               
Forgiveness of debt income
   
660,000
     
-
 
Interest income
   
59
     
12
 
Interest and accretion expense
   
(4,605,545
)
   
(363,235
)
Total other income (expense)
   
(3,945,486
)
   
(363,223
)
                 
Net loss before taxes
   
(10,418,662
)
   
(2,808,803
)
                 
Provision for income taxes
   
-
     
-
 
                 
Net (loss)
 
$
(10,418,662
)
 
$
(2,808,803
)
                 
Loss per share:
               
Basic and Diluted
 
$
(0.74
)
 
$
(0.21
)
Weighted average shares outstanding:
               
Basic and Diluted
   
14,016,240
     
13,564,815
 




 
33

 
 
TORCHLIGHT ENERGY RESOURCES, INC.
 
   
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
 
FOR THE PERIOD FROM JANUARY 1, 2012 TO DECEMBER 31, 2013
 
                                           
               
Common stock
   
Additional paid-in
   
Accumulated
   
Warrants
       
   
Preferred stock
   
Common stock shares
   
Amount
($)
   
Capital
($)
   
Deficit
($)
   
Outstanding
($)
   
Total
($)
 
                                           
                                           
Balance, January 1, 2012
   
-
     
14,664,815
     
14,665
     
5,861,985
     
(2,613,494
)
   
-
     
3,263,156
 
                                                         
Issuance of common stock for services
   
-
     
425,000
     
425
     
329,450
     
-
     
-
     
329,875
 
Shares issued in connection with promissory notes
   
-
     
75,000
     
75
     
67,650
     
-
     
-
     
67,725
 
Warrants issued in connection with promissory notes
   
-
     
-
     
-
     
791,376
     
-
     
-
     
791,376
 
Beneficial conversion feature on convertible notes
   
-
     
-
     
-
     
390,600
     
-
     
-
     
390,600
 
Warrants issued for services
   
-
     
-
     
-
     
938,340
     
-
     
-
     
938,340
 
Common stock retired
   
-
     
(1,600,000
)
   
(1,600
)
   
1,600
     
-
     
-
     
-
 
Net loss
   
-
     
-
     
-
     
-
     
(2,808,803
)
   
-
     
(2,808,803
)
                                                         
Balance, December 31, 2012
   
-
     
13,564,815
     
13,565
     
8,381,001
     
(5,422,297
)
   
-
     
2,972,269
 
                                                         
Issuance of common stock for services
   
-
     
735,752
     
735
     
1,438,245
     
-
     
-
     
1,438,980