UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x Annual report under Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2015.

o Transition report under Section 13 or 15(d) of the Securities Exchange Act of 1934 (No fee required)

For the transition period from _______ to _______.

Commission file number: 000-53473

Torchlight Energy Resources, Inc.

(Exact name of registrant in its charter)

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

5700 W. Plano Parkway, Suite 3600

Plano, Texas 75093

(Address of principal executive offices)

(214) 432-8002

(Registrant’s telephone number, including area code)

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

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

The NASDAQ Stock Market LLC (Name of each exchange on which registered)

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

None

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

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

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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

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

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

Large accelerated filer	o	Accelerated filer	o
Non-accelerated filer	o (Do not check if a smaller reporting company)	Smaller reporting company	x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

The aggregate market value of the common stock held by non-affiliates of the registrant on June 30, 2015, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $2.24 on the Nasdaq Stock Market, was approximately $61,015,694.

At March 24, 2016, there were 35,050,806 shares of the registrant’s common stock outstanding (the only class of common stock).

DOCUMENTS INCORPORATED BY REFERENCE

None.

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NOTE ABOUT FORWARD-LOOKING STATEMENTS

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

As used herein, the “Company,” “Torchlight,” “we,” “our,” and similar terms include Torchlight Energy Resources, Inc. and its subsidiaries, unless the context indicates otherwise.

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TABLE OF CONTENTS

PART I

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

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PART I

ITEM 1.     BUSINESS

Corporate History and Background

Torchlight Energy Resources, Inc. was incorporated in October 2007 under the laws of the State of Nevada as Pole Perfect Studios, Inc. (“PPS”).  

On November 23, 2010, we entered into and closed a Share Exchange Agreement (the “Exchange Agreement”) between the major shareholders of PPS and the shareholders of Torchlight Energy, Inc. (“TEI”).  As a result of the transactions effected by the Exchange Agreement, at closing TEI became our wholly-owned subsidiary, and the business of TEI became our sole business.  TEI is an energy company, incorporated under the laws of the State of Nevada in June 2010.  We are engaged in the acquisition, exploration, exploitation, and/or development of oil and natural gas properties in the United States.  In addition to TEI, we also operate our business through two other wholly-owned subsidiaries, Torchlight Energy Operating, LLC, a Texas limited liability company, and Hudspeth Oil Corporation, a Texas corporation.

On December 10, 2010, we effected a 4-for-1 forward split of our shares of common stock outstanding.  All owners of record at the close of business on December 10, 2010 (record date) received three additional shares for every one share they owned.  All share amounts reflected throughout this report take into account the 4-for-1 forward split.

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

Business Overview

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

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

Key Business Attributes

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

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

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

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

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ITEM 1.    BUSINESS - continued

Project Focus

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

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

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

Business Processes

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

· Investment Evaluation and Review;

· Operations and Field Activities; and

· Administrative and Finance Management.

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

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

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

Current Projects

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

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ITEM 1.    BUSINESS - continued

Marcelina Creek Field Development.

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

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

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

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

The Ring Energy Joint Venture, Southwest Kansas

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

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

Hunton Play, Central Oklahoma

The initial Hunton acquisition included three Hunton wells, the Hancock, Robinson and Lenhart.  The Hancock and Robinson are producing wells but have small working interests of 1% and .25 of 1%, respectively. 

The Lenhart well was a 62% working interest and was planned for recompletion to return to production.

We identified a shallow sandstone that could potentially be productive and tested this formation, and although there were hydrocarbons present, they are not in sufficient quantities to be economic.   The Lenhart property was sold for $25,000 and buyer’s assumption of plugging liability in 2015.

During the second quarter of 2013, Torchlight entered into an agreement with Husky Ventures to participate in the drilling of wells to the Hunton Formation in central Oklahoma. We continued to expand this relationship with Husky Ventures on a monthly basis as we expand our lease acreage in the contracted Areas of Mutual Interest (AMI’s).

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ITEM 1.    BUSINESS - continued

When Torchlight executed the agreement Husky had already drilled and completed 18 successful wells in the Hunton.  We estimated that Husky had spent, or caused to be spent, $125 million in what we considered a Research and Development project.  The results of Husky’s initial program lead them to develop certain drilling and completions techniques of which we could participate in and take advantage of.

The terms in our agreement with Husky are that we pay our proportionate costs of leases and operating expenses based on our working interest.   For leasing and drilling costs (the AFE), we carry Husky for 15% based on our working interest participation.  This is to compensate Husky for the initial program mentioned above and, additionally, the project coordination of the geological, leasing, legal and title opinions, survey and permitting, all drilling, frac design, completion and equipping, day to day operations, and accounting and filing all required monthly and annual reporting to all governmental agencies.

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

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

Cimarron AMI

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

Chisholm Trail AMI

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

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

Viking AMI

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

R4 AMI

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

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ITEM 1.    BUSINESS - continued

Prairie Grove – Judy Well

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

T4 AMI

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

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

Salt Water Disposal Facility

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

Orogrande Project, West Texas

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

Of the 172,000 acres, 40,154 were scheduled for renewal in December, 2014.  The Company renewed the leases for the 40,154 acres during second quarter, 2015. Prior to March 31, 2015, the Company had the obligation to begin drilling its first well in order to hold the acreage block. The well was permitted and spudded and drilling began by March 31, 2015.

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

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

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ITEM 1.    BUSINESS - continued

Under a joint operating agreement (on A.A.P.L. Form 610 – 1989 Model Form Operating Agreement with COPAS 2005 Accounting Procedures) (“JOA”) also entered into on September 23, 2015, Founders Oil & Gas Operating, LLC is designated as operator of the leases.  Any variance to the operating plan will be determined by a Development Committee, which committee will be made up of members from Founders and Farmor, or their designees, to discuss and recommend the location of the drill wells, data to be gathered and the form of same.  As contemplated under the Farmout Agreement, starting within 90 days of the completion of the fracing on the Rich Well, and at all times subject to the 90 day continuous drilling clause, Founders has the option, but not the obligation, to retain the assigned interest as follows: (1) if Founders spends a minimum of $45 million on actual drilling operations while maintaining compliance with the continuous drilling clause, subject to reasonable delays resulting from reasonable Force Majeure conditions, Founders will have fulfilled its farmout obligations and will be entitled to retain the assigned interests. If Founders does not meet such obligations, it will reassign to Farmor the assigned interest except it will be entitled to retain its interest in the leases covering all wells drilled by Founders and the sections in which such wells are located. Additionally, Founders will resign as operator of the JOA as to all lands reassigned; and (2) Farmor will be carried in all drilling operations during the first two years and/or $45 million in drilling operations, whichever comes last, subject to Founders’ right to recoup certain expenses on “Gap Wells.”  After three years and after Founders has earned its working interest, either party may elect to market the acreage as an entire block, including operatorship.  Should an acceptable bid arise, and both parties agree, the block will be sold 100% working interest to that third party bidder.  However, if only one party wants to accept the outside offer, the other party (the party who wishes not to sell) has the right to purchase the working interest from the selling party.

The Rich A-11 well that was drilled by Torchlight in second quarter, 2015 has been evaluated and numerous scientific tests were performed to provide key data for the field development thesis. During the testing process a poor cement bond was identified preventing a cost effective production test for the primary pay zones. Repair to the well bore necessary for a subsequent frac procedure was determined to be economically unfeasible. With the Rich A-11 designed as a test well rather than commercial target, a decision to begin plans for drilling the next well(s) with larger casing that utilized for future commercial production was made.

Torchlight Energy and Founders have elected to move forward on planning the next phase of drilling in the Orogrande Project. The project operator plans to permit three new wells starting with the University Founders B-19 #1 well. The new wells would be   drilled vertically for test purposes and would have sufficient casing size to support lateral entry into any pay zone(s) encountered once the well is tested vertically. Torchlight and the project operator would then run a battery of tests on each well to gain information for future development of the field.

Industry and Business Environment

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

Competition

The oil and natural gas industry is intensely competitive, and we will compete with numerous other companies engaged in the exploration and production of oil and gas.  Some of these companies have substantially greater resources than we have.  Not only do they explore for and produce oil and natural gas, but also many carry on midstream and refining operations and market petroleum and other products on a regional, national, or worldwide basis.  The operations of other companies may be able to pay more for exploratory prospects and productive oil and natural gas properties.  They may also have more resources to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit.

Our larger or integrated competitors may have the resources to be better able to absorb the burden of current and future federal, state, and local laws and regulations more easily than we can, which would adversely affect our competitive position.  Our ability to locate reserves and acquire interests in properties in the future will be dependent upon our ability and resources to evaluate and select suitable properties and consummate transactions in this highly competitive environment.  In addition, we may be at a disadvantage in producing oil and natural gas properties and bidding for exploratory prospects because we have fewer financial and human resources than other companies in our industry.  Should a larger and better financed company decide to directly compete with us, and be successful in its efforts, our business could be adversely affected.

Marketing and Customers

The market for oil and natural gas that we will produce depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels, and the effects of state and federal regulation.  The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial, and individual consumers.

Our oil production is expected to be sold at prices tied to the spot oil markets.  Our natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices.  We will rely on our operating partners to market and sell our production.

Governmental Regulation and Environmental Matters

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

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ITEM 1.    BUSINESS - continued

Regulation of Oil and Natural Gas Production

Our oil and natural gas exploration, production, and related operations, when developed, will be subject to extensive rules and regulations promulgated by federal, state, tribal, and local authorities and agencies.  Certain states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging, and abandonment of such wells.  Failure to comply with any such rules and regulations can result in substantial penalties.  The regulatory burden on the oil and gas industry will most likely increase our cost of doing business and may affect our profitability.  Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.  Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations.

Environmental Matters

Our operations and properties are and will be subject to extensive and changing federal, state, and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation, and discharge of materials into the environment, and relating to safety and health.  The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue.  These laws and regulations may:

·           require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;

·           limit or prohibit construction, drilling, and other activities on certain lands lying within wilderness and other protected areas;

·           impose substantial liabilities for pollution resulting from operations; or

·           restrict certain areas from fracking and other stimulation techniques.

The permits required for our operations may be subject to revocation, modification, and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we are and will be in substantial compliance with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on our company, as well as the oil and natural gas industry in general.

The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict, joint, and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites.  It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.  The Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products.  In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements.

The Endangered Species Act (“ESA”) seeks to ensure that activities do not jeopardize endangered or threatened animal, fish, and plant species, nor destroy or modify the critical habitat of such species.  Under ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat.  ESA provides for criminal penalties for willful violations of the Act.  Other statutes that provide protection to animal and plant species and that may apply to our operations include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act.  Although we believe that our operations will be in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject our company to significant expenses to modify our operations or could force our company to discontinue certain operations altogether.

Climate Change

Significant studies and research have been devoted to climate change and global warming, and climate change has developed into a major political issue in the United States and globally.  Certain research suggests that greenhouse gas emissions contribute to climate change and pose a threat to the environment.  Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to oil and natural gas exploration and production.  Many states and the federal government have enacted legislation directed at controlling greenhouse gas emissions, and future legislation and regulation could impose additional restrictions or requirements in connection with our drilling and production activities and favor use of alternative energy sources, which could affect operating costs and demand for oil products.  As such, our business could be materially adversely affected by domestic and international legislation targeted at controlling climate change.

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ITEM 1.    BUSINESS - continued

Employees

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

Research and Development

We did not spend any funds on research and development activities during years ended December 31, 2015 and 2014.

ITEM 1A.  RISK FACTORS

An investment in us involves a high degree of risk and is suitable only for prospective investors with substantial financial means who have no need for liquidity and can afford the entire loss of their investment in us.  Prospective investors should carefully consider the following risk factors, in addition to the other information contained in this report.

Risks Related to the Company and the Industry

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

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

· our ability to raise adequate working capital;

· the success of our development and exploration;

· the demand for natural gas and oil;

· the level of our competition;

· our ability to attract and maintain key management and employees; and

· our ability to efficiently explore, develop, produce or acquire sufficient quantities of marketable natural gas or oil in a highly competitive and speculative environment while maintaining quality and controlling costs.

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

We have limited capital and will need to raise additional capital in the future.

We do not currently have sufficient capital to fund both our continuing operations and our planned growth.  We will require additional capital to continue to grow our business via acquisitions and to further expand our exploration and development programs.  We may be unable to obtain additional capital when required.  Future acquisitions and future exploration, development, production and marketing activities, as well as our administrative requirements (such as salaries, insurance expenses and general overhead expenses, as well as legal compliance costs and accounting expenses) will require a substantial amount of additional capital and cash flow.

We may pursue sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing, or other means.  We may not be successful in identifying suitable financing transactions in the time period required or at all, and we may not obtain the capital we require by other means.  If we do not succeed in raising additional capital, our resources may not be sufficient to fund our planned operations.

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ITEM 1A. RISK FACTORS - continued

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

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

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

Our auditor has indicated that certain factors raise substantial doubt about our ability to continue as a going concern.

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

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

As a non-operator, our development of successful operations relies extensively on third-parties who, if not successful, could have a material adverse effect on our results of operation.

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

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

Because of the speculative nature of oil and gas exploration, there is risk that we will not find commercially exploitable oil and gas and that our business will fail.

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

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ITEM 1A. RISK FACTORS - continued

Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.

Our ability to successfully acquire oil and gas interests, to build our reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will depend on developing and maintaining close working relationships with industry participants and our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment.  These realities are subject to change and our inability to maintain close working relationships with industry participants or continue to acquire suitable property may impair our ability to execute our business plan.

To continue to develop our business, we will endeavor to use the business relationships of our management to enter into strategic relationships, which may take the form of joint ventures with other private parties and contractual arrangements with other oil and gas companies, including those that supply equipment and other resources that we will use in our business.  We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them.  In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to in order to fulfill our obligations to these partners or maintain our relationships.  If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

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

Our future financial condition, results of operations and the carrying value of any oil and natural gas interests we acquire will depend primarily upon the prices paid for oil and natural gas production. Oil and natural gas prices historically have been volatile and likely will continue to be volatile in the future, especially given current world geopolitical conditions. Our cash flows from operations are highly dependent on the prices that we receive for oil and natural gas. This price volatility also affects the amount of our cash flows available for capital expenditures and our ability to borrow money or raise additional capital. The prices for oil and natural gas are subject to a variety of additional factors that are beyond our control. These factors include:

· the level of consumer demand for oil and natural gas;

· the domestic and foreign supply of oil and natural gas;

· the ability of the members of the Organization of Petroleum Exporting Countries ("OPEC") to agree to and maintain oil price and production controls;

· the price of foreign oil and natural gas;

· domestic governmental regulations and taxes;

· the price and availability of alternative fuel sources;

· weather conditions;

· market uncertainty due to political conditions in oil and natural gas producing regions, including the Middle East; and

· worldwide economic conditions.

These factors as well as the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements with any certainty. Declines in oil and natural gas prices affect our revenues, and could reduce the amount of oil and natural gas that we can produce economically.  Accordingly, such declines could have a material adverse effect on our financial condition, results of operations, oil and natural gas reserves and the carrying values of our oil and natural gas properties. If the oil and natural gas industry experiences significant price declines, we may be unable to make planned expenditures, among other things. If this were to happen, we may be forced to abandon or curtail our business operations, which would cause the value of an investment in us to decline in value, or become worthless.

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

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

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

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ITEM 1A. RISK FACTORS - continued

At December 31, 2014, we performed an impairment review using prices that reflect an average of 2014’s monthly prices as prescribed pursuant to the SEC’s guidelines.  These average prices used in the December 31, 2014 impairment review were significantly higher than the actual and currently forecasted prices in 2015.  As lower average monthly pricing is reflected in the trailing 12-month average pricing calculation, the present value of our future net revenues would decline and impairment would be recognized. Since this significantly lower pricing environment persisted into 2015 we were required to write down the value of our oil and gas properties.    

The Company recognized impairment of $22,438,114 on its oil and gas properties at June 30, 2015 and an additional Impairment adjustment of $3,236,009 was made at December 31, 2015 for a total Impairment Adjustment of $25,674,123 for the year 2015. 

Because of the inherent dangers involved in oil and gas operations, there is a risk that we may incur liability or damages as we conduct our business operations, which could force us to expend a substantial amount of money in connection with litigation and/or a settlement.

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

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

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

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

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

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

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ITEM 1A. RISK FACTORS - continued

Our operations are heavily dependent on current environmental regulation, changes in which we cannot predict.

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

Various federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact our operations and costs. These regulations include, among others, (i) regulations by the Environmental Protection Agency and various state agencies regarding approved methods of disposal for certain hazardous and non-hazardous wastes; (ii) the Comprehensive Environmental Response, Compensation, and Liability Act, Federal Resource Conservation and Recovery Act and analogous state laws which regulate the removal or remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators), property contamination (including groundwater contamination), and remedial plugging operations to prevent future contamination; (iii) the Clean Air Act and comparable state and local requirements which may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations; (iv) the Oil Pollution Act of 1990 which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States; (v) the Resource Conservation and Recovery Act which is the principal federal statute governing the treatment, storage and disposal of hazardous wastes; and (vi) state regulations and statutes governing the handling, treatment, storage and disposal of naturally occurring radioactive material.

Management believes that we will be in substantial compliance with applicable environmental laws and regulations. To date, we have not expended any amounts to comply with such regulations, and management does not currently anticipate that future compliance will have a materially adverse effect on our consolidated financial position, results of operations or cash flows. However, if we are deemed to not be in compliance with applicable environmental laws, we could be forced to expend substantial amounts to be in compliance, which would have a materially adverse effect on our financial condition. If this were to happen, any investment in us could be lost.

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

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

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

Hydraulic fracturing is typically regulated by state oil and gas commissions. Some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, and/or well construction requirements on hydraulic fracturing operations.  For example, Pennsylvania is currently considering proposed regulations applicable to surface use at oil and gas well sites, including new secondary containment requirements and an abandoned and orphaned well identification program that would require operators to remediate any such wells that are damaged during current hydraulic fracturing operations.  New York has placed a permit moratorium on high volume fracturing activities combined with horizontal drilling pending the results of a study regarding the safety of hydraulic fracturing. And certain communities in Colorado have also enacted bans on hydraulic fracturing.

In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. There are also certain governmental reviews either underway or being proposed that focus on deep shale and other formation completion and production practices, including hydraulic fracturing. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate such activities. Certain environmental and other groups have also suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process.

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ITEM 1A. RISK FACTORS - continued

Further, the EPA has asserted federal regulatory authority over hydraulic fracturing involving “diesel fuels” under the SWDA’s UIC Program. In February 2014, the EPA released its final guidance on the use of diesel additives in hydraulic fracturing operations. The EPA is also engaged in a study of the potential impacts of hydraulic fracturing activities on drinking water resources in these states where the EPA is the permitted authority, including Pennsylvania, with a progress report released in late 2012 and a draft report released in June 2015. It concluded that hydraulic fracturing activities have not led to widespread systematic impacts on drinking water resources in the U.S., but there are above and below ground mechanisms by which hydraulic fracturing could affect drinking water resources. In addition, in March 2015, the Bureau of Land Management (“BLM”) issued a final rule to regulate hydraulic fracturing on federal and Indian land; however, enforcement of the rule has been delayed pending a decision in a legal challenge in the U.S. District Court of Wyoming. Further, the EPA issued an Advanced Notice of Proposed Rulemaking in May 2014 seeking comments relating to the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and mechanisms for obtaining this information. These actions, in conjunction with other analyses by federal and state agencies to assess the impacts of hydraulic fracturing could spur further action toward federal and/or state legislation and regulation of hydraulic fracturing activities.

We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit.  Restrictions on hydraulic fracturing could make it prohibitive for our third-party operating partners to conduct operations, and also reduce the amount of oil, natural gas liquids and natural gas that we are ultimately able to produce in commercial quantities from our properties.  If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and process prohibitions.

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

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

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

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

We may have difficulty distributing production, which could harm our financial condition.

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

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ITEM 1A. RISK FACTORS - continued

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

Our business will suffer if we cannot obtain or maintain necessary licenses.

Our operations will require licenses, permits and in some cases renewals of licenses and permits from various governmental authorities.  Our ability to obtain, sustain or renew such licenses and permits on acceptable terms is subject to change in regulations and policies and to the discretion of the applicable governments, among other factors.  Our inability to obtain, or our loss of or denial of extension of, any of these licenses or permits could hamper our ability to produce revenues from our operations.

Challenges to our properties may impact our financial condition.

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

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

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

The loss of key personnel would directly affect our efficiency and profitability.

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

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

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

In the future, we may incur significant increased costs as a result of operating as a public company, and our management may be required to devote substantial time to new compliance initiatives.

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

18

ITEM 1A. RISK FACTORS - continued

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

Certain Factors Related to Our Common Stock

There presently is a limited market for our common stock, and the price of our common stock may be volatile.

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

We have received a notice of failure to satisfy a continued listing requirement of NASDAQ

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

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

We are currently reviewing our options to regain compliance with the NASDAQ Listing Rules.  If we are unable to regain compliance and are ultimately delisted from NASDAQ, this may have a material adverse impact on our stockholders.

Offers or availability for sale of a substantial number of shares of our common stock may cause the price of our common stock to decline.

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

19

ITEM 1A. RISK FACTORS - continued

Our directors and officers have rights to indemnification.

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

We do not anticipate paying any cash dividends.

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

ITEM 1B.  UNRESOLVED STAFF COMMENTS

Not Applicable.

ITEM 2.     PROPERTIES

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

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

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

Oil and Natural Gas Reserves

Reserve Estimates

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

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

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

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

20

ITEM 2.    PROPERTIES – continued

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

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

BOE equivalents are determined by combining barrels of oil with MCF of gas divided by six.

The decrease of 1,271,563 BOE (998,333 for our Hunton Project and 273,230 for our Marcelina Project) in proved  nonproducing reserves comes from the third party engineering studies of the Cimarron and Chisholm Trail AMI's in Oklahoma and engineering studies for our Marcelina Project. 

No reserve value for the Ring Project is included in 2014 reserve tables presented above since the company believes this project is still considered to be in the testing phase.

21

ITEM 2.    PROPERTIES - continued

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

The decrease attributable to divestiture of reserves is from the sale of Oklahoma properties - the Chisholm Trail properties in fourth quarter, 2015 and the pending sale of the Cimarron properties in first quarter, 2016. The pending sale of the Cimarron resulted in no reserve value recorded at December 31, 2015 for the Cimarron properties.

The downward revisions of previous estimates of 441,413 Bbls and 1,176,999 MCF results primarily from 2015 reserve report calculations for the Company’s properties driven by industry conditions, particularly the decline in product prices, which further causes future development of properties to be uneconomic resulting in no PUD value for 2015.

22

ITEM 2.    PROPERTIES - continued

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

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

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

23

ITEM 2.    PROPERTIES - continued

Reserve Estimation Process, Controls and Technologies

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

We do not have any employees with specific reservoir engineering qualifications in the company.  Our Chairman and Chief Executive Officer worked closely with Crest Engineering Services Inc. and PeTech Enterprises Inc. in connection with their preparation of our reserve estimates, including assessing the integrity, accuracy, and timeliness of the methods and assumptions used in this process.

CREST Engineering Services, Inc. (CREST) is an independent petroleum engineering company specializing in the evaluation and appraisal of oil and gas reserves. CREST has been employed as an independent provider of these services specifically to provide the appraisal on behalf of us. Neither CREST, nor any of its individual engineers or consultants,  own an interest in either the Company, or any of the properties subject to this evaluation and does not anticipate any future ownership. Waterson Calhoun, P.E. is a petroleum engineer registered with the Texas State Board of Professional Engineers with over 20 years of industry experience providing evaluation services. Mr. Calhoun is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. Mr. Calhoun founded CREST Engineering Services Inc. in 1995 providing evaluation services on behalf of individuals, client companies and lending institutions.

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

Proved Nonproducing Reserves

As of December 31, 2015, our proved nonproducing reserves totaled 40,170 barrels of oil equivalents compared to 1,311,733 as of December 31, 2014, a decrease of 1,271,563.  These proved nonproducing reserves at December 31, 2015 were associated with our Marcelina Creek Field property (which decreased by 273,230) and our Hunton projects (which account for the decrease of 998,333). These numbers are taken from the third party reserves studies by CREST Engineering Services, Inc. and PeTech.

This decrease of 998,333 BOE in proved nonproducing reserves attributable to our Hunton projects comes from the third party engineering studies from PeTech of the Hunton in Oklahoma.  The net reserves change associated with these properties is a decrease of approximately 481,000 Bbls of oil and a decrease of approximately 3,104 MMcf of gas, or 998,333 BOE calculated with a gas-oil equivalency factor of six.  

With respect to our Marcelina Project, the decrease in proved nonproducing reserves of 273,230 BOE in Texas is due to a combination of factors.  This reduction was based on analysis by CREST Engineering Services, Inc.

We made various investments and progress during 2015 to convert proved nonproducing reserves to proved developed reserves.  Limitations on our ability to develop proved nonproducing reserves in 2015 were due to restraints on our capital availability and depressed industry conditions.  

Our current drilling plans, subject to sufficient capital resources and the periodic evaluation of interim drilling results and other potential investment opportunities, include drilling substantially all of the Buda wells in our proved nonproducing reserves during 2016 and 2017.  We do not currently have plans to drill the Eagle Ford shale wells in the next year.  The area of the Marcelina Creek Field is an active area of Eagle Ford shale development, and we intend to actively explore our options with regard to these proved nonproducing locations and other potential Eagle Ford drilling locations on our acreage. 

24

ITEM 2.    PROPERTIES - continued

Production, Price, and Production Cost History

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

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

Our production was from properties concentrated in central Oklahoma and in southern Texas. Reserves from each of these areas comprise more than 15% of total reserves. For 2015, approximately 7,896 BOE was produced at Marcelina Creek and approximately 36,472 BOE in Oklahoma, or 17% from Marcelina Creek and 78% from Oklahoma.

Quarterly Revenue and Production by State for 2015 and 2014 are detailed as follows:

Property	Quarter	Oil Production {BBLS}		Gas Production {MCF}		Oil Revenue		Gas Revenue		Total Revenue
Marcelina	Q1 - 2015		2,425		0	$	98,787	$	-	$	98,787
Oklahoma	Q1 - 2015		5,931		37,226	$	277,574	$	117,521	$	395,095
Kansas	Q1 - 2015		979		0	$	40,680	$	-	$	40,680
Total Q1-2015			9,335		37,226		417,041		117,521		534,562
Marcelina	Q2 - 2015		1,957		0	$	101,291	$	-	$	101,291
Oklahoma	Q2 - 2015		5,495		32,348	$	290,540	$	97,374	$	387,914
Kansas	Q2 - 2015		889		0	$	19,060	$	-	$	19,060
Total Q2-2015			8,341		32,348	$	410,891	$	97,374	$	508,265
Marcelina	Q3 - 2015		2,177		0	$	86,845	$	-	$	86,845
Oklahoma	Q3 - 2015		4,550		31,275	$	212,156	$	87,791	$	299,947
Kansas	Q3 - 2015		370		0	$	13,238	$	-	$	13,238
Total Q3-2015			7,097		31,275	$	312,239	$	87,791	$	400,030
Marcelina	Q4 - 2015		1,337		0	$	44,391	$	-	$	44,391
Oklahoma	Q4 - 2015		1,624		12,380	$	93,864	$	37,349	$	131,213
Kansas	Q4 - 2015		247		0	$	9,573	$	-	$	9,573
Total Q4-2015			3,208		12,380	$	147,828	$	37,349	$	185,177
Year Ended 12/31/15			27,981		113,229	$	1,287,999	$	340,035	$	1,628,034

25

ITEM 2.    PROPERTIES - continued

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

Drilling Activity and Productive Wells

Marcelina Creek Project - Texas

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

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

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

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

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

Central Oklahoma Projects

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

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

26

ITEM 2.    PROPERTIES - continued

Combined Well Status

The following table summarizes drilling activity and Well Status at December 31, 2015:

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

27

ITEM 2.    PROPERTIES - continued

Our acreage positions at December 31, 2015 are summarized as follows:

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

Marcelina Creek

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

Orogrande

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

Of the 172,000 acres, 40,154 were scheduled for renewal in December, 2014.  The Company renewed the leases for the 40,154 acres during second quarter, 2015. Prior to March 31, 2015, the Company had the obligation to begin drilling its first well in order to hold the acreage block. The well was permitted and spudded and drilling began by March 31.

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

28

ITEM 2.    PROPERTIES - continued

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

Under a joint operating agreement (on A.A.P.L. Form 610 – 1989 Model Form Operating Agreement with COPAS 2005 Accounting Procedures) (“JOA”) also entered into on September 23, 2015, Founders Oil & Gas Operating, LLC is designated as operator of the leases.  Any variance to the operating plan will be determined by a Development Committee, which committee will be made up of members from Founders and Farmor, or their designees, to discuss and recommend the location of the drill wells, data to be gathered and the form of same.  As contemplated under the Farmout Agreement, starting within 90 days of the completion of the fracing on the Rich Well, and at all times subject to the 90 day continuous drilling clause, Founders has the option, but not the obligation, to retain the assigned interest as follows: (1) if Founders spends a minimum of $45 million on actual drilling operations while maintaining compliance with the continuous drilling clause, subject to reasonable delays resulting from reasonable Force Majeure conditions, Founders will have fulfilled its farmout obligations and will be entitled to retain the assigned interests. If Founders does not meet such obligations, it will reassign to Farmor the assigned interest except it will be entitled to retain its interest in the leases covering all wells drilled by Founders and the sections in which such wells are located. Additionally, Founders will resign as operator of the JOA as to all lands reassigned; and (2) Farmor will be carried in all drilling operations during the first two years and/or $45 million in drilling operations, whichever comes last, subject to Founders’ right to recoup certain expenses on “Gap Wells.”  After three years and after Founders has earned its working interest, either party may elect to market the acreage as an entire block, including operatorship.  Should an acceptable bid arise, and both parties agree, the block will be sold 100% working interest to that third party bidder.  However, if only one party wants to accept the outside offer, the other party (the party who wishes not to sell) has the right to purchase the working interest from the selling party.

The Rich A-11 well that was drilled by Torchlight in second quarter, 2015 has been evaluated and numerous scientific tests were performed to provide key data for the field development thesis. During the testing process a poor cement bond was identified preventing a cost effective production test for the primary pay zones. Repair to the well bore necessary for a subsequent frac procedure was determined to be economically unfeasible. With the Rich A-11 designed as a test well rather than commercial target, a decision to begin plans for drilling the next well(s) with larger casing that utilized for future commercial production was made.

Torchlight Energy and Founders have elected to move forward on planning the next phase of drilling in the Orogrande Project. The project operator plans to permit three new wells starting with the University Founders B-19 #1 well. The new wells would be   drilled vertically for test purposes and would have sufficient casing size to support lateral entry into any pay zone(s) encountered once the well is tested vertically. Torchlight and the project operator would then run a battery of tests on each well to gain information for future development of the field.

Central Oklahoma Projects

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

Ring Energy Project

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

We made the initial $3.1 million deposit and the first five well drilling program is currently underway. Well locations were selected and drilling operations commenced in March, 2014. Seven wells were drilled – three are producing, one can be converted to a salt water disposal well, one was not completed, and two were plugged and abandoned. 3-D seismic data has been acquired to assist the selection of future drill sites.

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

29

ITEM 3.     LEGAL PROCEEDINGS

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

ITEM 4.     MINE SAFETY DISCLOSURES

Not Applicable.

30

PART II

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

Our common stock is quoted on The NASDAQ Stock Market LLC under the symbol, “TRCH.”  Trading in our common stock in the over-the-counter market has historically been limited and occasionally sporadic and the quotations set forth below are not necessarily indicative of actual market conditions.  The high and low sales prices for the common stock for each quarter of the fiscal years ended December 31, 2015 and 2014, according to NASDAQ, were as follows:

Quarter Ended	High		Low
12/31/2015	$	1.87	$	0.93
9/30/2015	$	2.44	$	0.48
6/30/2015	$	2.40	$	0.25
3/31/2015	$	0.83	$	0.22
12/31/2014	$	3.59	$	0.64
9/30/2014	$	4.20	$	3.25
6/30/2014	$	5.41	$	3.10
3/31/2014	$	5.41	$	4.15

Record Holders

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

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

Dividends

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

Equity Compensation Plan Information

The following table sets forth all equity compensation plans as of December 31, 2015:

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

31

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

Sales of Unregistered Securities

Other than the sale below, all equity securities that we have sold during the period covered by this report that were not registered under the Securities Act have previously been included in a Quarterly Report on Form 10-Q or in a Current Report on Form 8-K.

On July 1, 2015, we issued an investor 500,000 three-year warrants as part of the final terms and conditions of its purchase of a working interest in certain of our oil and gas properties.  Of these warrants, 250,000 warrants became exercisable on September 30, 2015 and the remaining 250,000 warrants became exercisable on December 31, 2015.  The warrants have an exercise price of $2.31 per share.

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

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

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

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

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

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

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

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

ITEM 6.  SELECTED FINANCIAL DATA

Not Applicable.

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

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

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

Basis of Presentation of Financial Information

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

32

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

Summary of Key Results

Overview

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

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

We had no active operations prior to the inception of TEI on June 25, 2010 and had limited revenues prior to the year ended December 31, 2012.  

Historical Results for the Years Ended December 31, 2015 and 2014

For the year ended December 31, 2015, we had a net loss of $43,252,878 compared to a net loss of $15,809,603 for the year ended December 31, 2014.

Revenues and Cost of Revenues

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

Property	Quarter	Oil Production {BBLS}		Gas Production {MCF}		Oil Revenue		Gas Revenue		Total Revenue
Marcelina	Q1 - 2015		2,425		0	$	98,787	$	-	$	98,787
Oklahoma	Q1 - 2015		5,931		37,226	$	277,574	$	117,521	$	395,095
Kansas	Q1 - 2015		979		0	$	40,680	$	-	$	40,680
Total Q1-2015			9,335		37,226		417,041		117,521		534,562
Marcelina	Q2 - 2015		1,957		0	$	101,291	$	-	$	101,291
Oklahoma	Q2 - 2015		5,495		32,348	$	290,540	$	97,374	$	387,914
Kansas	Q2 - 2015		889		0	$	19,060	$	-	$	19,060
Total Q2-2015			8,341		32,348	$	410,891	$	97,374	$	508,265
Marcelina	Q3 - 2015		2,177		0	$	86,845	$	-	$	86,845
Oklahoma	Q3 - 2015		4,550		31,275	$	212,156	$	87,791	$	299,947
Kansas	Q3 - 2015		370		0	$	13,238	$	-	$	13,238
Total Q3-2015			7,097		31,275	$	312,239	$	87,791	$	400,030
Marcelina	Q4 - 2015		1,337		0	$	44,391	$	-	$	44,391
Oklahoma	Q4 - 2015		1,624		12,380	$	93,864	$	37,349	$	131,213
Kansas	Q4 - 2015		247		0	$	9,573	$	-	$	9,573
Total Q4-2015			3,208		12,380	$	147,828	$	37,349	$	185,177
Year Ended 12/31/15			27,981		113,229	$	1,287,999	$	340,035	$	1,628,034

We recorded depreciation, depletion and amortization expense of $930,934 for the year ended December 31, 2015.

General and Administrative Expenses

Our general and administrative expenses for the years ended December 31, 2015 and 2014 were $15,550,145 and $10,156,307, respectively, an increase of $5,393,838. 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, 2015 compared to 2014 is detailed as follows:

33

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

Increase(decrease) in non cash stock and warrant compensation	$	5,621,898
Increase(decrease) in capital funding expense	$	(309,971	)
Increase(decrease) in consulting expense	$	751,387
Increase(decrease) in professional fees	$	(65,695	)
Increase(decrease) in investor relations expense	$	(578,500	)
Increase(decrease) in travel expense	$	(197,696	)
Increase(decrease) in salaries and compensation	$	351,243
Increase(decrease) in bad debt	$	560,382
Increase(decrease) in legal fee's	$	(92,970	)
Increase(decrease) in general corporate expenses	$	(646,240	)
Total Increase in General and Administrative Expenses	$	5,393,838

Liquidity and Capital Resources

At December 31, 2015, we had working capital of $(478,141), current assets of $2,006,959 consisting of cash, accounts receivable, and prepaid expenses, and total assets of $9,188,046 consisting of current assets, investments in oil and gas properties, and other assets. As of December 31, 2015, we had current liabilities of $2,485,100, consisting of accounts payable, payables to related parties, notes payable and accrued interest, and stockholders’ equity was $3,382,274.

Cash flow provided (used) in operating activities for the years ended December 31, 2015, was $(3,115,010) compared to $341,557 for the year ended December 31, 2014, a decrease of $3,456,567. Cash flow used in operating activities during 2015 can be primarily attributed to net losses from operations of $43,252,878, which consists primarily of $25,674,123 of impairment expense, $24,479 in loss on sale of assets, $15,550,145 in general and administrative expenses ($11,265,926 of which are non-cash stock based compensation), depreciation, depletion, and amortization of $930,934, accretion of convertible note discounts of $1,395,103. Cash flow used in operating activities during 2014 can be primarily attributed to net losses from operations of $15,809,603, which consists primarily of $10,156,307 in general and administrative expenses ($5,644,028 of which are non-cash  stock based compensation), depreciation, depletion, and amortization of $2,736,562, and accretion of convertible note discounts of $5,771,050. 

Cash flow used in investing activities for year ended December 31, 2015 was $1,667,512 compared to $18,645,289 for the year ended December 31, 2014.  Cash flow used in investing activities consists primarily of oil and gas investment properties acquired during the year ended December 31, 2015.

Cash flow provided by financing activities for the year ended December 31, 2015 was $5,629,335 as compared to $16,671,806 for the year ended December 31, 2014.  Cash flow provided by financing activities in 2015 consists of proceeds from common and preferred 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 to meet our 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. 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 on our common stock 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, 2015 and December 31, 2014, 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.

34

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

We currently have interests in four oil and gas projects, the Marcelina Creek Field Development in Wilson County, Texas, the Orogrande project in Hudspeth County, Texas, projects in Logan and Kingfisher counties, Oklahoma and projects in 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.

35

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Board of Directors and Stockholders

Torchlight Energy Resources, Inc.

Plano, Texas

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have audited the accompanying consolidated balance sheets of Torchlight Energy Resources, Inc. (the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years then ended. These consolidated financial statements are the responsibility of the entity’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the years then ended, in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that the entity will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the entity has suffered recurring losses from operations and has a net working capital deficiency which raises substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ Calvetti Ferguson

Houston, Texas

March 30, 2016

36

TORCHLIGHT ENERGY RESOURCES, INC.
CONSOLIDATED CONDENSED BALANCE SHEETS
	December 31,			December 31,
	2015			2014
ASSETS
Current assets:
Cash	$	1,026,600		$	179,787
Accounts receivable		741,653			223,371
Production revenue receivable		199,317			210,435
Note receivable		613			515,748
Prepayments - development costs		-			20,602
Prepaid expenses		38,776			29,634
Total current assets		2,006,959			1,179,577
Investment in oil and gas properties, net		7,057,671			34,498,681
Office equipment		43,110			55,150
Debt issuance costs, net		8,224			353,733
Other assets		72,082			63,223
TOTAL ASSETS	$	9,188,046		$	36,150,364
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	1,114,409		$	4,018,306
Accrued liabilities		628,876			240,000
Related party payables		130,000			90,000
Note payable within one year - related party		205,000			0
Convertible promissory notes, (Series A) net of discount of
$700,178 at December 31, 2014		-			7,417,420
Notes payable within one year		129,741			829,719
Due to working interest owners		103,364			73,439
Interest payable		173,710			383,741
Total current liabilities		2,485,100			13,052,625
Convertible promissory notes, (Series B) net of discount of $277,911 at December 31, 2015 and $625,457 at December 31, 2014		3,291,589			3,944,043
Asset retirement obligation		29,083			35,951
					-
Commitments and contingencies		-			-
Stockholders’ equity:
Preferred stock, par value $.001, 100,000,000 shares authorized,
134,000 shares issued and outstanding		134			-
Common stock, par value $0.001 per share; 75,000,000 shares authorized;		33,168			23,235
33,166,344 issued and outstanding at December 31, 2015
23,235,441 issued and outstanding at December 31, 2014
Additional paid-in capital		61,921,450			43,108,752
Warrants outstanding		16,330,961			7,636,320
Accumulated deficit		(74,903,439	)		(31,650,561	)
Total stockholders' equity		3,382,274			19,117,745
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	9,188,046		$	36,150,364

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

37

TORCHLIGHT ENERGY RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
	YEAR			YEAR
	ENDED			ENDED
	DECEMBER 31, 2015			DECEMBER 31, 2015
Revenue
Oil and gas sales	$	1,628,034		$	5,455,555
SWD and royalties		6,274			85,529
Cost of revenue		(814,078	)		(1,253,090	)
Gross income		820,230			4,287,994
Operating expenses:
General and administrative expense		15,550,145			10,156,307
Depreciation, depletion and amortization		930,934			2,736,562
Loss on sale		24,479			0
Total operating expenses		16,505,558			12,892,869
Other income (expense)
Income - Cancellation of Debt		-			22,748
Impairment expense		25,674,123			(447,084	)
Interest income		0			69
Interest and accretion expense		1,893,427			(6,780,461	)
Total other income (expense)		27,567,550			(7,204,728	)
Net loss before taxes		(43,252,878	)		(15,809,603	)
Provision for income taxes		-			-
Net (loss)	$	(43,252,878	)	$	(15,809,603	)
Loss per share:
Basic and Diluted	$	(2.64	)	$	(1.01	)
Weighted average shares outstanding:
Basic and Diluted		16,372,826			15,728,621

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

38

TORCHLIGHT ENERGY RESOURCES, INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
	Common		Common		Pref.			Pref.			Additional
	stock		stock		stock			Stock			paid-in			Accumulated			Warrants
	shares		amount		shares			Amt.			capital			deficit			Outstanding			Total
Balance, December 31, 2013		16,141,765	$	16,142							$	21,978,607		$	(15,840,958	)	$	3,043,420		$	9,197,210
Issuance of common stock for cash		2,989,655	$	2,989							$	10,629,802								$	10,632,791
Issuance of common stock for services		450,180	$	451							$	933,977								$	934,428
Issuance of common stock - mineral interests		1,781,595	$	1,782							$	5,135,097								$	5,136,879
Issuance of common stock in warrant exercise		617,500	$	618							$	1,276,882								$	1,277,500
Issuance of common stock for note interest		5,869	$	5							$	10,265								$	10,270
Warrants issued with promissory notes											$	562,354					$	72,000		$	634,354
Warrants issued in private placement		0									$	123,250					$	(116,700	)	$	6,550
Warrants issued for services		0									$	78,765								$	78,765
Common stock issued in conversion of notes		1,248,877	$	1,248							$	2,184,287								$	2,185,535
Beneficial conversion feature on conv. notes											$	195,466								$	195,466
Warrants issued for services																	$	4,637,600		$	4,637,600
Net loss														$	(15,809,603	)				$	(15,809,603	)
Balance, December 31, 2014		23,235,441	$	23,235							$	43,108,752		$	(31,650,561	)	$	7,636,320		$	19,117,745
Issuance of common stock for cash		4,931,250	$	4,931							$	1,295,069								$	1,300,000
Issuance of preferred stock for cash						135,000		$	135		$	13,499,865								$	13,500,000
Issuance of common stock for services		2,447,696	$	2,448							$	2,649,056								$	2,651,504
Issuance of common stock - mineral interests		30,000	$	30							$	26,370								$	26,400
Issuance of common stock in warrant exercise		65,000	$	65							$	113,685								$	113,750
Issuance of common stock for note interest		162,860	$	163							$	162,697								$	162,860
Issuance of common stock for preferred dividends		577,140	$	577							$	809,169								$	809,746
Accounting Value of  Dividend (No RE)											$	(809,746	)							$	(809,746	)
Preferred dividends paid in cash											$	(120,427	)							$	(120,427	)
Warrants issued with promissory notes																	$	467,800		$	467,800
Warrants issued in private placement																				$	-
Warrants issued for services																				$	-
Common stock issued in conversion of notes		1,600,000	$	1,600							$	1,148,400								$	1,150,000
Common stock issued in part payment of bonuses		30,000	$	30							$	39,870								$	39,900
Common stock issued in conversion of preferred stock		86,957	$	87							$	99,913								$	100,000
Preferred stock cancelled in conversion						(1,000	)	$	(1	)	$	(99,999	)							$	(100,000	)
Warrants issued for services											$	(1,222	)				$	8,226,841		$	8,225,619
Net loss														$	(43,252,878	)				$	(43,252,878	)
Balance, December 31, 2015		33,166,344	$	33,168		134,000		$	134		$	61,921,450		$	(74,903,439	)	$	16,330,961		$	3,382,274

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

39

TORCHLIGHT ENERGY RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOW
	Year			Year
	Ended			Ended
	December 31, 2015			December 31, 2014
Cash Flows From Operating Activities
Net (loss)	$	(43,252,878	)	$	(15,809,603	)
Adjustments to reconcile net loss to net cash from operations:
Stock based compensation		11,265,926			5,644,028
Accretion of convertible note discounts		1,395,103			5,771,050
Impairment expense		25,674,123			447,084
Depreciation, depletion and amortization		930,934			2,736,562
Loss on sale of assets		24,479			-
Income - cancellation of debt					(22,748	)
Change in:
Accounts receivable		(187,305	)		133,851
Note receivable		515,135			(515,748	)
Production revenue receivable		11,118			(210,435	)
Prepayment of development costs		(290,398	)		(20,602	)
Prepaid expenses		(9,142	)		(20,490	)
Debt issuance costs		-			(185,875	)
Other assets		(8,860	)		(3,506	)
Accounts payable and accrued liabilities		1,024,098			3,180,467
Due to working interest owners		29,925			(507,045	)
Asset retirement obligation		(948	)		11,170
Interest payable		469,241			84,513
Capitalized interest		(705,561	)		(371,116	)
Net cash provided by (used) in operating activities		(3,115,010	)		341,557
Cash Flows From Investing Activities
Investment in oil and gas properties		(4,518,239	)		(18,591,329	)
Acquisition of office equipment		(1,191	)		(53,960	)
Proceeds from sale of Leases		2,851,918			-
Net cash used in investing activities		(1,667,512	)		(18,645,289	)
Cash Flows From Financing Activities
Proceeds from sale of common stock		1,300,000			10,632,791
Proceeds from sale of preferred stock		13,500,000			-
Payment of preferred stock dividends		(120,427	)		-
Repayment of convertible notes		(8,859,011	)		-
Proceeds from warrant exercise		113,750			744,282
Proceeds from promissory notes		539,916			5,384,991
Repayment of promissory notes		(844,893	)		(90,258	)
Net cash provided by financing activities		5,629,335			16,671,806
Net increase (decrease) in cash		846,813			(1,631,926	)
Cash - beginning of period		179,787			1,811,713
Cash - end of period	$	1,026,600		$	179,787
Supplemental disclosure of cash flow information:
Non cash transactions:
Common stock issued for services	$	2,651,504		$	933,977
Common stock issued for mineral interests	$	26,400		$	5,136,879
Warrants issued for services	$	8,225,619		$	4,716,365
Common stock issued in conversion of promissory notes	$	1,150,000		$	2,185,535
Common stock issued for unpaid compensation	$	39,900		$	0
Warrants issued in connection with promissory notes	$	467,800		$	634,354
Beneficial conversion feature on promissory notes	$	-		$	195,466
Common stock issued in warrant exercises	$	113,750		$	1,277,500
Cash paid for interest	$	919,272		$	1,243,816

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

40

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. NATURE OF BUSINESS

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 was incorporated under the laws of the State of Nevada in June 2010.  We are engaged in the acquisition, 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.”

The Company is engaged in the acquisition, exploration, development and production of oil and gas properties within the United States. The Company’s success will depend in large part on its ability to obtain and develop profitable oil and gas interests.

2. GOING CONCERN

These consolidated financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which assumes that the Company will be able to meet its obligations and continue its operations for its next fiscal year.

At December 31, 2015, the Company had not yet achieved profitable operations. We had a net loss of approximately $43.2 million for the year ended December 31, 2015 and had accumulated losses of $74,903,439 since its inception and expects to incur further losses in the development of its business.  Working Capital as of December 31, 2015 was negative $478,141. The Company’s ability to continue as a going concern is dependent on its ability to generate future profitable operations and/or to obtain the necessary financing to meet its obligations and repay its liabilities arising from normal business operations when they come due.  Management’s plan to address the Company’s ability to continue as a going concern includes:  (1) obtaining debt or equity funding from private placement or institutional sources; (2) obtain 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 the Company to remain a going concern through the methods discussed above, there can be no assurances that such methods will prove successful.  The accompanying consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Planned Divestiture of Hunton Assets

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

3. SIGNIFICANT ACCOUNTING POLICIES

The Company maintains its accounts on the accrual method of accounting in accordance with accounting principles generally accepted in the United States of America. Accounting principles followed and the methods of applying those principles, which materially affect the determination of financial position, results of operations and cash flows are summarized below:

Use of estimates – The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and certain assumptions that affect the amounts reported in these consolidated financial statements and accompanying notes. Actual results could differ from these estimates.

Basis of presentation—The financial statements are presented on a consolidated basis and include all of the accounts of Torchlight Energy Resources Inc. and its wholly owned subsidiaries, Torchlight Energy, Inc., Torchlight Energy Operating, LLC, and Hudspeth Oil Corporation. All significant intercompany balances and transactions have been eliminated.

41

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. SIGNIFICANT ACCOUNTING POLICIES - continued

Risks and uncertainties – The Company’s operations are subject to significant risks and uncertainties, including financial, operational, technological, and other risks associated with operating an emerging business, including the potential risk of business failure.

Concentration of risks – The Company’s cash is placed with a highly rated financial institution, and the Company periodically reviews the credit worthiness of the financial institutions with which it does business. At times the Company’s cash balances are in excess of amounts guaranteed by the Federal Deposit Insurance Corporation.

Fair value of financial instruments – Financial instruments consist of cash, accounts receivable, accounts payable, notes payable to related party, and convertible promissory notes. The estimated fair values of cash, accounts receivable, accounts payable, and related party payables approximate the carrying amount due to the relatively short maturity of these instruments. The carrying amounts of the convertible promissory notes approximate their fair value giving affect for the term of the note and the effective interest rates.

For assets and liabilities that require re-measurement to fair value the Company categorizes them in a three-level fair value hierarchy as follows:

· Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

· Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration.

· Level 3 inputs are unobservable inputs based on management’s own assumptions used to measure assets and liabilities at fair value.

A financial asset or liability’s classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.

Accounts receivable – Accounts receivable consist of uncollateralized oil and natural gas revenues due under normal trade terms, as well as amounts due from working interest owners of oil and gas properties for their share of expenses paid on their behalf by the Company. Management reviews receivables periodically and reduces the carrying amount by a valuation allowance that reflects management’s best estimate of the amount that may not be collectible. As of December 31, 2015 and December 31, 2014 no valuation allowance was considered necessary.

As of December 31, 2015, the Company had a $419,839 account receivable from Husky Ventures for the estimated balance of the sale proceeds from the sale of the Chisholm Trail properties in fourth quarter, 2016. The Chisholm Trail properties were sold to Husky Ventures who then included them with the Husky interests in Chisholm Trail and then entered into a sale agreement with Gastar Exploration Inc. for the combined Torchlight and Husky interests. Receipt of the balance of the sale proceeds was subject to final determination of mineral lease classification and was to occur by February 28, 2016. The account receivable is not collected as of March 30, 2016.

Investment in oil and gas properties – The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves.

Oil and gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded represent investments in unevaluated properties and include non-producing leasehold, geological, and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. The Company allocates a portion of its acquisition costs to unevaluated properties based on relative value. Costs are transferred to the full cost pool as the properties are evaluated over the life of the reservoir.

Capitalized interest – The Company capitalizes interest on unevaluated properties during the periods in which they are excluded from costs being depleted or amortized.  During years ended December 31, 2015 and 2014, the Company capitalized $705,561 and $371,116, respectively, of interest on unevaluated properties.

Depreciation, depletion, and amortization – The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of accumulated depreciation, depletion, and amortization (“DD&A”), estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized on a unit-of-production method.

42

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. SIGNIFICANT ACCOUNTING POLICIES - continued

Ceiling test – Future production volumes from oil and gas properties are a significant factor in determining the full cost ceiling limitation of capitalized costs. Under the full cost method of accounting, the Company is required to periodically perform a “ceiling test” that determines a limit on the book value of oil and gas properties. If the net capitalized cost of proved oil and gas properties, net of related deferred income taxes, plus the cost of unproved oil and gas properties, exceeds the present value of estimated future net cash flows discounted at 10 percent, net of related tax affects, plus the cost of unproved oil and gas properties, the excess is charged to expense and reflected as additional accumulated DD&A. The ceiling test calculation uses a commodity price assumption which is based on the unweighted arithmetic average of the price on the first day of each month for each month within the prior 12 month period and excludes future cash outflows related to estimated abandonment costs. The Company recognized impairment of $22,438,114 on its oil and gas properties during the three months ended June 30, 2015 and an additional impairment at December 31, 2015 of $3,236,009 for a total impairment adjustment for 2015 of $25,674,123. No impairment was recognized at December 31, 2014. Due to the volatility of commodity prices, should oil and natural gas prices decline in the future, it is possible that a write-down could occur. Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. The independent engineering estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place. Estimated reserves to be developed through secondary or tertiary recovery processes are classified as unevaluated properties.

The determination of oil and gas reserves is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Subsequent re-evaluation of reserves and cost estimates related to future development of proved oil and gas reserves could result in significant revisions to proved reserves.  Other issues, such as changes in regulatory requirements, technological advances, and other factors which are difficult to predict could also affect estimates of proved reserves in the future.

Gains and losses on the sale of oil and gas properties are not generally reflected in income unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Sales of less than 100% of the Company’s interest in the oil and gas property are treated as a reduction of the capital cost of the field, with no gain or loss recognized, as long as doing so does not significantly affect the unit-of-production depletion rate. Costs of retired equipment, net of salvage value, are usually charged to accumulated depreciation.

The Company’s sale of the Chisholm Trail properties in fourth quarter, 2016 transferred approximately 27% of reserve value which represents a significant alteration of the relationship of reserves to capitalized costs. The $24,479 loss on the sale of the Chisholm Trail properties is, therefore, presented on the Statement of Operations.

Asset retirement obligations – Accounting principles require that the fair value of a liability for an asset’s retirement obligation (“ARO”) be recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost be capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then-present value each subsequent period, and the capitalized cost is depleted over the useful life of the related asset. Abandonment cost incurred is recorded as a reduction to the ARO liability.

Inherent in the fair value calculation of an ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Settlements greater than or less than amounts accrued as ARO are recorded as a gain or loss upon settlement.

Asset retirement obligation activity is disclosed in Note 10.

Share-based compensation – Compensation cost for equity awards is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which an employee is required to provide service in exchange for the award. Compensation cost for liability awards is based on the fair value of the vested award at the end of each period.

Revenue recognition – The Company recognizes oil and gas revenues when production is sold at a fixed or determinable price, persuasive evidence of an arrangement exists, delivery has occurred and title has transferred, and collectability is reasonably assured.

43

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. SIGNIFICANT ACCOUNTING POLICIES - continued

Basic and diluted earnings (loss) per share – Basic earnings (loss) per common share is computed by dividing net income (loss) available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings (loss) per common share is computed in the same way as basic earnings (loss) per common share except that the denominator is increased to include the number of additional common shares that would be outstanding if all potential common shares had been issued and if the additional common shares were dilutive.  The Company has not included potentially dilutive securities in the calculation of loss per share for any periods presented as the effects would be anti-dilutive.

Environmental laws and regulations – The Company is subject to extensive federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their future economic benefit. The Company believes that it is in compliance with existing laws and regulations.

Recent accounting pronouncements –

On August 27, 2014, the FASB issued ASU 2014-15, which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of the Company’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The ASU applies to all entities and is effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted.

In May 2014, the FASB issued ASU 2014-09 that introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. This standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the new guidance to determine the impact it will have on its consolidated financial statements.

In April 2014, the FASB issued ASU 2014-08, which includes amendments that change the requirements for reporting discontinued operations and require additional disclosures about discontinued operations. Under the new guidance, only disposals representing a strategic shift in operations - that is, a major effect on the organization’s operations and financial results should be presented as discontinued operations. Additionally, the ASU requires expanded disclosures about discontinued operations that will provide financial statement users with more information about the assets, liabilities, income, and expenses of discontinued operations. The new standard is effective in the first quarter of 2015 for public organizations with calendar year ends. Early adoption would be permitted for any annual or interim period for which an entity’s financial statements have not yet been made available for issuance. The adoption of this guidance is not expected to have an impact on the Company’s consolidated financial statements.

Other recently issued or adopted accounting pronouncements are not expected to have, or did not have, a material impact on the Company’s financial position or results from operations.

Subsequent events – The Company evaluated subsequent events through March 30, 2016, the date of issuance of the financial statements. Subsequent events are disclosed in Note 11.

4. RELATED PARTY PAYABLES

As of December 31, 2015, related party payables consisted of accrued and unpaid compensation to two of our executive officers totaling $90,000 and $40,000 in deferred Director Fee payable to one of our Directors, Mr. Edward J. Devereaux who elected to receive $50,000 in cash when funds are available and $50,000 in common stock (amounting to 21,834 shares). As of December 31, 2015 $10,000 had been paid to Mr. Devereaux.

On November 4, 2014, Eunis L. Shockey loaned us $500,000 under a 30 day promissory note.  The promissory note accrues interest at an annual rate of 10%.  The balance of the note at December 31, 2015 was $205,000. The due date of the note has been extended to March 31, 2016.

5. COMMITMENTS AND CONTINGENCIES

The Company is subject to contingencies as a result of environmental laws and regulations.  Present and future environmental laws and regulations applicable to the Company’s operations could require substantial capital expenditures or could adversely affect its operations in other ways that cannot be predicted at this time.  As of December 31, 2015 and 2014, no amounts had been recorded because no specific liability has been identified that is reasonably probable of requiring the Company to fund any future material amounts.

44

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6. STOCKHOLDERS’ EQUITY

During the years ended December 31, 2015 and 2014, the Company issued 4,931,250 and 2,989,655 shares of common stock, respectively, for cash of $1,300,000 and $10,632,791.

During the years ended December 31, 2015 and 2014, the Company issued 135,000 and -0- shares of preferred stock, respectively, for cash of $13,500,000 and $-0-.

During the year ended December 31, 2015, the Company paid dividends on preferred stock in cash of $120,427. In addition 577,140 shares of common stock were issued for dividends on preferred stock.

During the years ended December 31, 2015 and 2014, the Company issued 2,477,696 and 450,180 shares of common stock, respectively, as compensation for services, with total values of $2,651,504 and $934,428.

During the years ended December 31, 2015 and 2014, the Company issued 7,015,779 and 1,847,500 warrants, respectively, as compensation for services, with total values of $7,797,619 and $4,637,600.

During the year ended December 31, 2015 and 2014, the Company issued 770,000 and -0- warrants, respectively, in connection with financing transactions, with total values of $368,300 and $-0-.

During the year ended December 31, 2015 the Company issued 2,615,676 warrants in connection with the issuance of preferred stock.

During the year ended December 31,2015,the Company issued 750,000 warrants in connection with the acquisition of lease interests with total value of $527,500.

During the year ended December 31, 2015 and 2014, the Company issued 30,000 and 1,781,595 shares of common stock, respectively, as acquisition of lease interests valued at $26,400 and $5,136,879.

During the year ended December 31, 2015 and 2014 the Company issued 1,600,000 and 1,248,877 shares of common stock, respectively, in conversions of Notes Payable valued at $1,150,000 and $2,185,535.

During the years ended December 31, 2015 and 2014, the Company issued 162,860 and 5,869 shares of common stock, respectively, for interest on notes payable of $162,860 and $10,270.

During the year ended December 31, 2015 and 2014 the Company issued 65,000 and 623,369 shares of common stock, respectively, resulting from Warrant exercises for consideration totaling $113,750 and $1,277,500.

45

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6. STOCKHOLDERS’ EQUITY - continued

A summary of stock options and warrants outstanding as of December 31, 2015 by exercise price and year of expiration is presented below:

Exercise		Expiration Date in
Price		2016		2017		2018		2019		2020		Total
$	0.50						800,000						800,000
$	1.00		-		150,000		-		-				150,000
$	1.40										1,704,346		1,704,346
$	1.57										3,750,000		3,750,000
$	1.73						100,000						100,000
$	1.75		1,135,714		-		-		-				1,135,714
$	1.79										225,000		225,000
$	1.80										850,000		850,000
$	2.00		1,035,271		126,000		1,696,380		-				2,857,651
$	2.03						2,000,000						2,000,000
$	2.09		-		-		2,800,000		-				2,800,000
$	2.23										911,330		911,330
$	2.29						120,000						120,000
$	2.31						500,000						500,000
$	2.50		100,000		-		-		80,779				180,779
$	2.82		-		-		38,174		-				38,174
$	3.00		100,000		-		-		-				100,000
$	3.50								15,000				15,000
$	4.50		-		-		-		700,000				700,000
$	5.00		8,391		190,000		-		-				198,391
$	6.00		-		-		577,501		327,675				905,176
$	7.00		-		-		-		700,000				700,000
			2,379,376		466,000		8,632,055		1,823,454		7,440,676		20,741,561

As of the date of this filing, 99,200 of the warrants exercisable in 2016 have expired.

At December 31, 2015 the Company had reserved 20,741,561 shares for future exercise of warrants.

Warrants issued in relation to the promissory notes issued (see note 9) were valued using the Black Scholes Option Pricing Model. The assumptions used in calculating the fair value of the warrants issued are as follows:

Risk-free interest rate	0.78%
Expected volatility of common stock	191% - 253%
Dividend yield	0.00%
Discount due to lack of marketability	20-30%
Expected life of warrant	3 years - 5 years

46

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. CAPITALIZED COSTS

The following table presents the capitalized costs of the Company as of December 31, 2015 and December 31, 2014:

	2015			2014
Evaluated costs subject to amortization	$	24,177,851		$	24,276,483
Unevaluated costs		9,677,425			14,152,415
Accumulated impairment expense		(22,783,989	)		-
Total capitalized costs		11,071,287			38,428,898
Less accumulated depreciation, depletion  and amortization		(4,013,616	)		(3,930,217	)
Net capitalized costs	$	7,057,671		$	34,498,681

Unevaluated costs as of December 31, 2015 consisted of $696,949 associated with the Company’s interest in the Coulter #1 well. The Coulter is a non-core, non-producing asset which we will attempt to monetize by sale of the lease. We presently have approximately 940 acres.

8. INCOME TAXES

Income taxes are accounted for under the asset and liability method.  Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss carry forwards.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.  The Company has placed a 100% valuation allowance against the net deferred tax asset because future realization of these assets is not assured.

Authoritative guidance for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an examination.  Management has reviewed the Company’s tax positions and determined there were no uncertain tax positions requiring recognition in the consolidated financial statements.  The Company’s tax returns remain subject to Federal and State tax examinations for all tax years since inception as none of the statutes have expired.  Generally, the applicable statutes of limitation are three to four years from their respective filings.

Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in the statement of operation.  The Company has not recorded any interest or penalties associated with unrecognized tax benefits for any periods covered by these financial statements.

The following is a reconciliation between the federal income tax benefit computed at the statutory federal income tax rate of 34% and actual income tax provision for the years ended December 31, 2015 and December 31, 2014:

	Year ended			Year ended
	Dec. 31, 2015			Dec. 31, 2014
Federal income tax benefit at statutory rate	$	(14,705,979	)	$	(5,626,540	)
Permanent Differences		4,127			511,184
Other		(587,126	)		894,181
Change in valuation allowance		15,288,978			4,221,175
Provision for income taxes	$	-		$	-

47

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8. INCOME TAXES - continued

The tax effects of temporary differences that gave rise to significant portions of deferred tax assets and liabilities at December 31, 2015 and December 31, 2014 are as follows:

	Dec. 31, 2015			Dec. 31, 2014
Deferred tax assets:
Net operating loss carryforward	$	11,443,389		$	8,190,580
Accruals		30,600			30,600
Reserves		5,883,263			2,952,364
Deferred tax liabilities:
Intangible drilling and other costs for oil and gas properties		7,240,011			(1,865,259	)
Net deferred tax assets and liabilities		24,597,263			9,308,285
Less valuation allowance		(24,597,263	)		(9,308,285	)
Total deferred tax assets and liabilities	$	-		$	-

The Company had a net deferred tax asset related to federal net operating loss carryforwards of $33,657,027 and $24,089,942 at December 31, 2015 and December 31, 2014, respectively.  The federal net operating loss carryforward will begin to expire in 2030.  Realization of the deferred tax asset is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards.  The Company has placed a 100% valuation allowance against the net deferred tax asset because future realization of these assets is not assured.

9. PROMISSORY NOTES

Series “A” Convertible Notes issued by the Company during 2012 through 2014 having a total outstanding principal balance of $8,117,598 plus interest, were due in full at their maturity date of March 31, 2015. The notes were paid in full on June 9, 2015. During the quarter ended June 30, 2014, the Company issued $3,197,500 in principal value of 12% Series B Convertible Unsecured Promissory Notes. The 12% Notes are due and payable on June 30, 2017 and provide for conversion into common stock at a price of $4.50 per share and included the issuance of one warrant for each $22.50 of principal amount purchased.  The Company issued a total of 142,111 of these five-year warrants to purchase common stock at an exercise price of $6.00 per share.  The value of the warrant shares was $405,016 and the amount recorded for the beneficial conversion feature was $195,466.  These amounts were recorded as a discount on the 12% Notes.

During the quarter ended September 30, 2014, the Company issued an additional $1,372,000 in principal value of 12% Series B Convertible Unsecured Promissory Notes. The 12% Notes are due and payable on June 30, 2017 and provide for conversion into common stock at a price of $4.50 per share and included the issuance of one warrant for each $22.50 of principal amount purchased.  The Company issued a total of 60,974 of these five-year warrants to purchase common stock at an exercise price of $6.00 per share.  The value of the warrant shares was $157,388 and the amount recorded for the beneficial conversion feature was $-0-.  These amounts were recorded as a discount on the 12% Notes.

Notes Payable within one year 

The Company is obligated on a short term note payable totaling $129,741 as of December 31, 2015. The note is due with interest at its maturity date December 31, 2016.

48

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. ASSET RETIREMENT OBLIGATIONS

The following is a reconciliation of the asset retirement obligation liability through December 31, 2015:

Asset retirement obligation – December 31, 2014	$	35,951
Estimated liabilities recorded		-
Accretion Expense		1,107
Asset retirement obligation – March 31, 2015	$	37,058
Estimated liabilities recorded		-
Accretion Expense		819
Removal of ARO for wells sold		(1,152	)
Asset retirement obligation – June 30, 2015	$	36,725
Estimated liabilities recorded		-
Accretion Expense		819
Asset retirement obligation – September 30, 2015	$	37,544
Estimated liabilities recorded		-
Accretion Expense		747
Removal of ARO for wells sold		(9,208	)
Asset retirement obligation – December 31, 2015	$	29,083

11. SUBSEQUENT EVENTS

Planned Divestiture of Hunton Project

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

49

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2015 and 2014

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

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

Oil and Natural Gas Reserves

Reserve Estimates

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

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

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

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

50

UNAUDITED SUPPLEMENTARY INFORMATION - continued

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

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

BOE equivalents are determined by combining barrels of oil with MCF of gas divided by six.

The decrease of 1,271,563 BOE (998,333 for our Hunton Project and 273,230 for our Marcelina Project) in proved  nonproducing reserves comes from the third party engineering studies of the Cimarron and Chisholm Trail AMI's in Oklahoma and engineering studies for our Marcelina Project. 

No reserve value for the Ring Project is included in 2014 reserve tables presented above since the company believes this project is still considered to be in the testing phase.

51

UNAUDITED SUPPLEMENTARY INFORMATION - continued

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

The decrease attributable to divestiture of reserves is from the sale of Oklahoma properties - the Chisholm Trail properties in fourth quarter, 2015 and the pending sale of the Cimarron properties in first quarter, 2016. The pending sale of the Cimarron resulted in no reserve value recorded at December 31, 2015 for the Cimarron properties.

The downward revisions of previous estimates of 441,413 Bbls and 1,176,999 MCF results primarily from 2015 reserve report calculations for the Company’s properties driven by industry conditions, particularly the decline in product prices, which further causes future development of properties to be uneconomic resulting in no PUD value for 2015.

52

UNAUDITED SUPPLEMENTARY INFORMATION - continued

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

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

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

53

UNAUDITED SUPPLEMENTARY INFORMATION - continued

Reserve Estimation Process, Controls and Technologies

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

We do not have any employees with specific reservoir engineering qualifications in the company.  Our Chairman and Chief Executive Officer worked closely with Crest Engineering Services Inc. and PeTech Enterprises Inc. in connection with their preparation of our reserve estimates, including assessing the integrity, accuracy, and timeliness of the methods and assumptions used in this process.

CREST Engineering Services, Inc. (CREST) is an independent petroleum engineering company specializing in the evaluation and appraisal of oil and gas reserves. CREST has been employed as an independent provider of these services specifically to provide the appraisal on behalf of us. Neither CREST, nor any of its individual engineers or consultants,  own an interest in either the Company, or any of the properties subject to this evaluation and does not anticipate any future ownership. Waterson Calhoun, P.E. is a petroleum engineer registered with the Texas State Board of Professional Engineers with over 20 years of industry experience providing evaluation services. Mr. Calhoun is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. Mr. Calhoun founded CREST Engineering Services Inc. in 1995 providing evaluation services on behalf of individuals, client companies and lending institutions.

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

Results of Operations for Oil and Gas Producing Activities
For the Year Ended December 31, 2015	Total			Texas			Oklahoma		Kansas
Oil and Gas revenue	$	1,628,034		$	331,314		$	1,214,169	$	82,551
Production costs		814,078			296,639			440,494		76,945
Depreciation, depletion, and amortization		930,934			270,736			650,638		9,560
Exploration expenses		-			-			-		-
		1,745,012			567,375			1,091,132		86,505
Income tax expense		-			-			-		-
Results of Operations (excluding corporate overhead
and interest costs)	$	(116,978	)	$	(236,061	)	$	123,037	$	(3,954	)

54

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not Applicable.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of December 31, 2015. Based on this evaluation, our principal executive officer and principal financial officer concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective to ensure that the information required to be disclosed by us in the reports we submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the applicable rules and forms and that such information was accumulated and communicated to our principal executive officer and principal financial officer, in a manner that allowed for timely decisions regarding disclosure, 

Changes in internal control over financial reporting

During the year ended December 31, 2015, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect internal control over financial reporting.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) of the Exchange Act). Our management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework and Internal Control over Financial Reporting – Guidance for Smaller Public Companies.  Based on this evaluation, management concluded that, our internal control over financial reporting is effective.

Limitations on Effectiveness of Controls and Procedures

Our management, including our principal executive officer and principal financial officer, does not expect that disclosure controls or internal controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake.

 Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people or by management’s override of the control.  The design of any systems of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.  Over time, control may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of these inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.  Individual persons may perform multiple tasks which normally would be allocated to separate persons and therefore extra diligence must be exercised during the period these tasks are combined.

ITEM 9B.  OTHER INFORMATION

Not applicable.

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PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Our executive officers and directors are as follows:

Name	Age	Position(s) and Office(s)
John A. Brda	51	Chief Executive Officer, Secretary and Director
Willard G. McAndrew III	61	Chief Operating Officer and Director
Roger N. Wurtele	69	Chief Financial Officer
Jerry D. Barney	69	Director
Edward J. Devereaux	73	Director
Eunis L. Shockey	79	Director

Below is certain biographical information of our executive officers and directors:

John A. Brda – Mr. Brda has been our Chief Executive Officer since December 2014 and our President and Secretary and a member of the Board of Director since January 2012.  He has been the Managing Member of Brda & Company, LLC since 2002, which provided consulting services to public companies—with a focus in the oil and gas sector—on investor relations, equity and debt financings, strategic business development and securities regulation matters, prior to him becoming President of the company.

We believe Mr. Brda is an excellent fit to our Board of Directors and management team based on his extensive experience in transaction negotiation and business development, particularly in the oil and gas sector as well as other non-related industries.  He has consulted with many public companies in the last ten years, and we believe that his extensive network of industry professionals and finance firms will contribute to our success.

Willard G. McAndrew III – Mr. McAndrew has served as our Chief Operating Officer since September 2013 and as a member of the Board since October 2013.  He has forty three years of experience in the energy industry, from field operations to refining.  From December 2006 to September 2013, Mr. McAndrew served as the Chairman of the Board, CEO and President of Xtreme Oil & Gas, Inc., a company engaged in the acquisition, operation and development of oil and natural gas properties located in Texas and the southeast region of the United States.  He began his career in 1969, gaining experience working for Hercules Drilling Company as a roustabout in South Louisiana.  Mr. McAndrew attended Louisiana State University and then spent two years in the United States Marine Corps.  Later, he joined Exxon Corporation Refinery’s Distillation and Specialties division in Baton Rouge, Louisiana, becoming the fourth generation in his family to work for Exxon. Mr. McAndrew has served as President and owner of several small companies that were involved in all phases of the oil and gas business from drilling, reworking, completion, leases, etc.  He has also been a consultant since 1990 to companies and is responsible for the structure, formation and marketing of partnerships and energy financing.

We believe that Mr. McAndrew’s many years in the oil and gas industry and his vast network of contacts in the investment banking and broker-dealer communities compliments the Board of Directors.

Involvement in certain legal proceedings.  From 2001 through May 2006, Mr. McAndrew served as the CEO, President and Director of Energy & Engine Technology, Inc.  After he left the company, it filed for bankruptcy protection in December 2006.

Roger N. Wurtele – Mr. Wurtele has served as our Chief Financial Officer since September 2013.  He is a versatile, experienced finance executive that has served as Chief Financial Officer for several public and private companies. He has a broad range of experience in public accounting, corporate finance and executive management.  Mr. Wurtele previously served as CFO of Xtreme Oil & Gas, Inc. from February 2010 to September 2013.  From May 2013 to September 2013 he worked as a financial consultant for us.  From November 2007 to January 2010, Mr. Wurtele served as CFO of Lang and Company LLC, a developer of commercial real estate projects.  He graduated from the University of Nebraska and has been a Certified Public Accountant for 40 years.

Involvement in certain legal proceedings.  From 2001 through May 2006, Mr. Wurtele served as the CFO of Energy & Engine Technology, Inc.  After he left the company, it filed for bankruptcy protection in December 2006.

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ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE - continued

Jerry Barney – Dr. Barney has served as member of the Board of Directors since October 2013.  He has over 30 years of experience in various management and consulting positions with technology, oil services and government entities. Dr. Barney was a director of Barney Family Companies, a successful investment firm with holdings in oil and gas properties, office buildings and financial assets. Dr. Barney has a Bachelor of Science from the University of Kansas; a MA and EdD in Education from Columbia University; and a MBA from Rensselaer University.

We believe that Dr. Barney’s broad range of business experience and skills, punctuated by noteworthy higher education credentials, compliments the Board of Directors.

Edward Devereaux – Mr. Devereaux has served as member of the Board of Directors since October 2013.  He is a seasoned investment executive with over three decades of experience in investment management, investment banking and securities sales and marketing.  From 2010 to the present, he has served as a consultant to companies wishing to raise capital within the independent broker dealer and registered investment advisors communities.  From 2006 to 2010, he served as President and CEO of Advanced Marketing Services, a marketing consulting and investment banking firm. Mr. Devereaux has participated in raising more than $10 billion of investment capital in his career.  He has worked for various investment firms, including Prudential Securities and Lightstone Securities.  Mr. Devereaux has a B.A. from Hofstra University.

Edward Devereaux expertise in the securities industry makes him an excellent fit to the Board of Directors.  In particular, we believe his oversight of our capital raising strategies is a valuable asset to the company.

Eunis L. Shockey – Mr. Shockey has served as member of the Board of Directors since October 2013.  He is a successful and experienced entrepreneur and executive.  Mr. Shockey retired in 2000, but since then he has acted as a mentor for many of the companies in his investment portfolio. After completing his service in the U.S. Navy, Mr. Shockey entered the software industry and gained broad knowledge of military software and telephony applications while at GE, RCA, Raytheon, and Northern Telecom. He founded Computerware in 1978 and successfully developed and marketed a telephone company management system for shared tenant services. Computerware was bought by a venture capital fund in 1986. Mr. Shockey then founded Telecommunications Support Systems (TSS) to dispatch substitute teachers for schools. Its customers included 600 of the largest school districts in the U.S. and Canada. TSS was sold in 2000 and currently operates as eSchools Solutions, Inc.

We believe Mr. Shockey is an excellent fit to our Board of Directors based on his extensive experience in successfully owning and operating multiple successful companies over the years.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires our directors and executive officers, and persons who own beneficially more than ten percent of our common stock, to file reports of ownership and changes of ownership with the Securities and Exchange Commission. Based solely upon a review of Forms 3, 4 and 5 furnished to us during the fiscal year ended December 31, 2015, we believe that the directors, executive officers, and greater than ten percent beneficial owners have complied with all applicable filing requirements during the fiscal year ended December 31, 2015, with the exception of (i) a Form 4 that John Brda, our President and CEO, filed late; (ii) a Form 4 that Willard McAndrew, our COO, filed late; (iii) a Form 4 that Roger Wurtele, our CFO, filed late; (iv) two Form 4’s that Eunis L. Shockey, a director, filed late; (v) a Form 4 and two Form 4/A’s that Edward Devereaux, a director, filed late; (vi) a Form 4 that Jerry Barney, a director, filed late; (vii) two Form 4’s that Robert Kenneth Dulin, a significant beneficial stockholder, filed late; and (viii) a Form 3 and a Form 4 that Greg McCabe, a significant beneficial stockholder, filed late.

Code of Ethics

We have adopted a code of ethics that applies to our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions.  The Code of Ethics is available at our website at torchlightenergy.com.  Further, we undertake to provide by mail to any person without charge, upon request, a copy of such code of ethics if we receive the request in writing by mail to: Torchlight Energy Resources, Inc., 5700 W. Plano Parkway, Suite 3600, Plano, Texas 75093.

Procedures for Stockholders to Recommend Nominees to the Board

There have been no material changes to the procedures by which stockholders may recommend nominees to our Board of Directors since we last provided disclosure regarding this process.

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ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE - continued

Audit Committee

We maintain a separately-designated standing audit committee.  The Audit Committee currently consists of our three independent directors, Eunis L. Shockey, Jerry D. Barney and Edward J. Devereaux. Mr. Devereaux is the Chairman of the Audit Committee, and the Board of Directors has determined that he is an audit committee financial expert as defined in Item 5(d)(5) of Regulation S-K. The primary purpose of the Audit Committee is to oversee our accounting and financial reporting processes and audits of our financial statements on behalf of the Board of Directors. The Audit Committee meets privately with our management and with our independent registered public accounting firm and evaluates the responses by our management both to the facts presented and to the judgments made by our outside independent registered public accounting firm.

ITEM 11. EXECUTIVE COMPENSATION

The following table provides summary information for the years 2015 and 2014 concerning cash and non-cash compensation paid or accrued to or on behalf of certain executive officers.

Summary Executive Compensation Table

	Year	Salary		Bonus		Stock		Option			Non-Equity		Change in		All Other		Total
		($)		($)		Awards		Awards			Incentive		Pension		Compensation		($)
						($)		($)			Plan		Value		($)
								(A)			Compensation		and
Name and											($)		Nonqualified
Principal													Deferred
Position													Compensation
													($)
Thomas Lapinski	2015		-		-		-		-			-		-		-		-
Former CEO (1)	2014	$	180,000		-		-		-			-		-		-	$	180,000
John A. Brda	2015	$	337,500		-		-	$	1,530,000	(2)		-		-		-	$	1,867,500
President and CEO	2014	$	300,000		-		-		-			-		-		-	$	300,000
Willard G. McAndrew III	2015	$	337,500		-		-	$	1,530,000	(2)		-		-		-	$	1,867,500
COO	2014	$	300,000		-		-		-			-		-		-	$	300,000
Roger Wurtele	2015	$	202,500		-		-	$	765,000	(2)		-		-		-	$	967,500
CFO	2014	$	180,000		-		-		-			-		-		-	$	180,000

(A)           Stock Value as applicable is determined using the Black Scholes Method.

(1)           As of December 30, 2014, Mr. Lapinski no longer served as Chief Executive Officer.

(2)           On June 11, 2015, we granted new stock option awards to our executive officers, as follows: (i) 3,000,000 stock options to John Brda, President and Chief Executive Officer; (ii) 3,000,000 stock options to Willard McAndrew, Chief Operating Officer; and (iii) 1,500,000 stock options to Roger Wurtele, Chief Financial Officer. The options were granted under our 2015 Stock Option Plan which plan was approved by stockholders on September 9, 2015.  The options are subject to a two-year vesting schedule with one-half vesting immediately, one-fourth vesting after one year of the grant date, and the remaining one-fourth vesting after the second year, provided however that the options will be subject to earlier vesting under certain events set forth in the 2015 Stock Option Plan, including without limitation a change in control.

Setting Executive Compensation

We fix executive base compensation at a level we believe enables us to hire and retain individuals in a competitive environment and to reward satisfactory individual performance and a satisfactory level of contribution to our overall business goals. We also take into account the compensation that is paid by companies that we believe to be our competitors and by other companies with which we believe we generally compete for executives.

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ITEM 11. EXECUTIVE COMPENSATION - continued

In establishing compensation packages for executive officers, numerous factors are considered, including the particular executive’s experience, expertise, and performance, our company’s overall performance, and compensation packages available in the marketplace for similar positions. In arriving at amounts for each component of compensation, our Compensation Committee strives to strike an appropriate balance between base compensation and incentive compensation. The Compensation Committee also endeavors to properly allocate between cash and non-cash compensation (including without limitation stock and stock option awards) and between annual and long-term compensation. 

Employment Agreements

On June 16, 2015, we entered into new five-year employment agreements with each of John Brda, our President and Chief Executive Officer; Willard McAndrew, our Chief Operating Officer; and Roger Wurtele, our Chief Financial Officer.  Under the new agreements, which replace and supersede their prior employment agreements, each individual’s salary was increased by 25%, so that the salaries of Messrs. Brda, McAndrew and Wurtele are $375,000, $375,000 and $225,000, respectively, provided these salary increases will accrue unpaid until such time as management believes there is adequate cash for such increases.  Each individual will be eligible for a bonus, at the Compensation Committee’s discretion, of up to two times his salary and be eligible for any additional stock options, as deemed appropriate by the Compensation Committee.  Each agreement provides that if we (or our successor) terminate the employee upon the occurrence of a change in control, the employee will be paid in one lump sum his salary and any bonus or other amounts due through the end of the term of the agreement.  Each employment agreement has a covenant not to compete.

Outstanding Equity Awards at Fiscal Year End 

The following table details all outstanding equity awards held by our named executive officers at December 31, 2015:

	Option Awards
	Number of			Number of			Equity Incentive
	Securities			Securities			Plan Awards: Number of
	Underlying			Underlying			Securities
	Unexercised			Unexercised			Underlying		Option
	Options			Options			Unexercised		Exercise		Option
		(#)			(#)		Unearned Options		Price		Expiration
Name	Exercisable			Unexercisable				(#)	($)		Date
John A. Brda		245,000			-			-	$	2.00	9/4/2018
		1,500,000	(5)		1,500,000	(5)		-	$	1.57	6/11/2020
Willard G. McAndrew III		900,000			-			-	$	2.09	4/15/2018
		1,500,000	(1) (2)		-			-	$	2.09	9/9/2018
		1,500,000	(5)		1,500,000	(5)		-	$	1.57	6/11/2020
Roger Wurtele		300,000	(3) (4)		-			-	$	2.09	10/10/2018
		750,000	(5)		750,000	(5)		-	$	1.57	6/11/2020

(1) Mr. McAndrew gifted these options to WMDM Family, Ltd. The general partner and 1% owner of WMDM Family, Ltd. is a limited liability company which is owned by a trust of which Mr. McAndrew is a beneficiary.

(2) These options were awarded to Mr. McAndrew in September 2013, and vested on January 2, 2014.

(3)  Mr. Wurtele gifted these options to Birch Glen Investments Ltd.  Mr. Wurtele and his wife together hold a 98% interest in the general partner of Birch Glen Investments Ltd.

(4) These options were awarded to Mr. Wurtele in October 2013.  100,000 options vested in October 2013 and the remaining 200,000 options vested on January 2, 2014.

(5) The options were awarded on June 11, 2015. The options were granted under our 2015 Stock Option Plan which plan was approved by stockholders on September 9, 2015.  The options are subject to a two-year vesting schedule with one-half vesting immediately, one-fourth vesting after one year of the grant date, and the remaining one-fourth vesting after the second year, provided however that the options will be subject to earlier vesting under certain events set forth in the 2015 Stock Option Plan, including without limitation a change in control.

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ITEM 11. EXECUTIVE COMPENSATION - continued

Compensation of Directors

At present, we do not pay our directors for attending meetings of the Board of Directors, although we may adopt a director compensation policy in the future. We have no standard arrangement pursuant to which directors are compensated for any services they provide or for committee participation or special assignments.  We did, however, provide compensation of $100,000 to  directors in the form of restricted common stock or cash, at their individual option during the year ended December 31, 2015. No Director compensation was paid in 2014.

Summary Director Compensation Table

Compensation to directors during the year ended December 31, 2015 was as follows:

	Fees Earned						Option Awards				Nonqualified
	Paid								Non-Equity		Deferred		All
	in			Stock			Option		Incentive Plan		Compensation		Other
	Cash			Awards			Awards		Compensation		Earnings		Compensation		Total
Name	($)			($) (A)			($)		($)		($)		($)		($)
Jerry Barney		-			100,000	(1)		-		-		-		-	$	100,000
Edward Devereaux	$	50,000	(1)		50,000	(1)		-		-		-		-	$	100,000
Eunis L. Shockey		-			100,000	(1)		-		-		-		-	$	100,000

(1)  On June 30, 2015, the Board of Directors approved paying its independent members of the Board of Directors $100,000 as director compensation for the time, commitment and service rendered by the Directors, payable, at the election of each director, either (i) in common stock of the Company, based upon the closing price of our common stock as of June 30, 2015, plus $0.05 (equaling $2.29 per share), (ii) in cash when funds are deemed available, or (iii) in a combination thereof.  It was provided that if any director elected for us to pay him in common stock, the issuance of such shares would be subject to stockholder approval.  Of our independent directors, Jerry D. Barney and Eunis L. Shockey both elected to receive all $100,000 in such compensation in common stock (amounting to 43,668 shares, each), and Edward J. Devereaux elected to receive $50,000 in cash when funds are available and $50,000 in common stock (amounting to 21,834 shares).  Stockholders approved these stock issuances to these directors on September 9, 2015.

(A)           Stock Value as applicable is determined using the Black Scholes Method.

Compensation Policies and Practices as they Relate to Risk Management

We attempt to make our compensation programs discretionary, balanced and focused on the long term.  We believe goals and objectives of our compensation programs reflect a balanced mix of quantitative and qualitative performance measures to avoid excessive weight on a single performance measure. Our approach to compensation practices and policies applicable to employees and consultants is consistent with that followed for its executives.  Based on these factors, we believe that our compensation policies and practices do not create risks that are reasonably likely to have a material adverse effect on us.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth information, as of March 24, 2016, concerning, except as indicated by the footnotes below, (i) each person whom we know beneficially owns more than 5% of our common stock, (ii) each of our directors, (iii) each of our named executive officers, and (iv) all of our directors and executive officers as a group. The table includes these persons’ beneficial ownership of common stock. Unless otherwise noted below, the address of each beneficial owner listed in the table is c/o Torchlight Energy Resources, Inc., 5700 W. Plano Parkway, Suite 3600, Plano, Texas 75093.  We have determined beneficial ownership in accordance with the rules of the SEC. Except as indicated by the footnotes below, we believe, based on the information furnished to us, that the persons and entities named in the table below have sole voting and investment power with respect to all shares of common stock that they beneficially own, subject to applicable community property laws. Applicable percentage ownership is based on 35,050,806 shares of common stock outstanding at March 24, 2016. In computing the number of shares of common stock beneficially owned by a person and the percentage ownership of that person, we deemed outstanding shares of common stock subject to stock options or warrants held by that person that are currently exercisable or exercisable within 60 days of March 24, 2016 and shares of common stock issuable upon conversion of other securities held by that person that are currently convertible or convertible within 60 days of March 24, 2016. We did not deem these shares outstanding, however, for the purpose of computing the percentage ownership of any other person. Unless otherwise noted, stock options and warrants referenced in the footnotes below are currently fully vested and exercisable. Beneficial ownership representing less than 1% is denoted with an asterisk (*).

Shares Beneficially Owned
	Common Stock
Name of beneficial owner	Shares				% of Class
John A. Brda		4,262,000	(1	)		11.58
President, CEO, Secretary and Director
Willard G. McAndrew III		3,900,000	(2	)		10.01
COO and Director
Roger N. Wurtele		1,050,000	(3	)		2.91
Chief Financial Officer
Jerry D. Barney		88,668	(4	)		*
Director
Edward J. Devereaux		58,834				*
Director
Eunis L. Shockey		697,668	(5	)		1.96
Director
All directors and executive officers as a group (six persons)		10,057,170				23.73
Thomas Lapinski		3,165,000	(6	)		8.97
Robert Kenneth Dulin (7)		4,194,432	(8	)		11.18
Zenith Petroleum Corporation (9)		1,908,356				5.44
Greg McCabe (10)		8,002,172	(11	)		20.68
David Moradi (12)		2,585,851	(13	)		7.18	(14)

(1) Includes 187,000 shares of common stock and stock options that are exercisable into 1,745,000 shares of common stock, both held individually by Mr. Brda.  Also includes 2,330,000 shares of common stock held by Brda & Company LLC.  Mr. Brda is the sole owner and Managing Director of this entity and has voting and investment authority over the shares held by it.

(2) Includes stock options that are exercisable into 1,500,000 shares of common stock held individually by Mr. McAndrew. Also includes securities held by WMDM Family, Ltd., including warrants that are exercisable into 900,000 shares of common stock and stock options that are exercisable into 1,500,000 shares of common stock. The general partner and 1% owner of WMDM Family, Ltd. is a limited liability company of which Mr. McAndrew is the manager. He has voting and investment authority over the shares held by WMDM Family, Ltd.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT - continued

(3) Includes stock options that are exercisable into 750,000 shares of common stock held individually by Mr. Wurtele. Also includes stock options held by Birch Glen Investments Ltd. that are exercisable into 300,000 shares of common stock.   Mr. Wurtele and his wife together hold a 98% interest in the general partner of Birch Glen Investments Ltd., and Mr. Wurtele shares voting and investment authority over the shares held by Birch Glen Investments Ltd.  Additionally, the general partner and 1% owner of WMDM Family, Ltd. (see footnote “(2)” above) is a limited liability company which is owned by a trust of which Mr. Wurtele is the trustee.  Securities held by WMDM Family, Ltd. are not included, however, because Mr. Wurtele is not deemed to have voting or investment authority over the shares held by WMDM Family, Ltd.

(4) Includes (a) 68,668 shares of common stock held individually by Dr. Barney; and (b) a Series A Warrant that is exercisable into 20,000 shares of common stock held by an entity that is wholly-owned by the Barney 2012 Children’s Trust.  Dr. Barney is a beneficiary of the Barney 2012 Children’s Trust and historically has had influence over decisions made by the trustee who has voting and investment authority over the shares held by the trust.

(5) Includes 77,668 shares of common stock and warrants that are exercisable into 620,000 shares of common stock.

(6) Includes 2,920,000 shares of common stock and stock options that are exercisable into 245,000 shares of common stock. Mr. Lapinski’s address is 2007 Enterprise Avenue, League City, Texas  77573.

(7) Address: 8449 Greenwood Drive, Niwot, Colorado, 80503.

(8)  Includes (a) securities held individually by Robert Kenneth Dulin, including (i) 27,000 shares of common stock and (ii) warrants that are exercisable into 150,000 shares of common stock; (b) 243,360 shares of common stock held in trust for the benefit of immediate family members of Mr. Dulin; (c) securities held by Sawtooth Properties, LLLP (“Sawtooth”), including (i) 600,000 shares of common stock, (ii) warrants that are exercisable into 234,745 shares of common stock and (iii) Series A Convertible Preferred Stock (“Series A Preferred”) that is convertible into 260,870 shares of common stock; (d) securities held by Black Hills Properties, LLLP (“Black Hills”), including (i) 125,000 shares of common stock, (ii) warrants that are exercisable into 189,956 shares of common stock and (iii) Series A Preferred that is convertible into 434,782 shares of common stock; (e) securities held by Pine River Ranch, LLC (“Pine River”), including (i) 120,000 shares of common stock, (ii) warrants that are exercisable into 450,024 shares of common stock and (iii) Series A Preferred that is convertible into 608,695 shares of common stock; and (f) securities held by Pandora Energy, LP (“Pandora”), including warrants that are exercisable into 750,000 shares of common stock.  Mr. Dulin is trustee/custodian of each of the trusts and/or accounts referenced in “(b)” above and has voting and investment authority over the shares held by them. Mr. Dulin is the Managing Partner of Sawtooth Properties, LLLP, the Managing Partner of Black Hills, the Managing Member of Pine River, and the General Partner of Pandora, and he has voting and investment authority over the shares held by each entity.  Each holder of shares of Series A Preferred Stock is entitled to the number of votes equal to the number of shares of common stock into which such shares of Series A Preferred could be converted.  Presently, all issued and outstanding shares of Series A Preferred are convertible at the election of the holder.

(9) Address: 7790 E. Arapahoe Rd., #190, Centennial, Colorado 80112.

(10) Address: 500 West Texas Ave., Suite 890, Midland, Texas 79701.

(11) Includes (a) 4,350,000 shares owned beneficially and of record by Mr. McCabe, (b) 2,608,695 shares issuable upon conversion of shares of Series A Preferred held by Mr. McCabe, (c) 521,739 shares issuable upon exercise of warrants held by Mr. McCabe and (d) 521,738 shares beneficially held by G Mc Exploration, LLC (“GME”) (comprised of 434,782 shares of common stock issuable upon conversion of shares of Series A Preferred and 86,956 shares of common stock issuable upon exercise of warrants), of which McCabe may be deemed to hold beneficial ownership as a result of his ownership of 50% of the outstanding membership interests of GME.  Each holder of shares of Series A Preferred Stock is entitled to the number of votes equal to the number of shares of common stock into which such shares of Series A Preferred could be converted.  Presently, all issued and outstanding shares of Series A Preferred are convertible at the election of the holder.

(12) Address: 379 West Broadway, New York, New York 10012

(13) This information is based on information in the Schedule 13G filed jointly by David Moradi and Anthion Partners II LLC on December 23, 2015. The Schedule 13G reports beneficial ownership of 2,585,851 shares of common stock for which each of Mr. Moradi and Anthion Partners II LLC have shared dispositive power and shared voting power.

(14) This percentage is calculated based on the assumption that Anthion Partners II LLC owns 20,000 shares of Series B Convertible Preferred Stock that is convertible into 985,221 shares of common stock.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

On November 4, 2014, Eunis L. Shockey loaned us $500,000 under a 30 day promissory note.  The promissory note accrues interest at an annual rate of 10%.  The balance of the note at December 31, 2015 was $205,000. The due date of the note has been extended to March 31, 2016.

Director Independence

We currently have three independent directors on our Board, Jerry Barney, Edward Devereaux, and Eunis L. Shockey.  The definition of “independent” used herein is based on the independence standards of The NASDAQ Stock Market LLC.  The Board performed a review to determine the independence of Jerry Barney, Edward Devereaux, and Eunis L. Shockey and made a subjective determination as to each of these directors that no transactions, relationships, or arrangements exist that, in the opinion of the Board, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director of Torchlight Energy Resources, Inc.  In making these determinations, the Board reviewed information provided by these directors with regard to each Director’s business and personal activities as they may relate to us and our management.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table sets forth the fees paid or accrued by us for the audit and other services provided or to be provided by Calvetti Ferguson, our independent registered public accountants, during the years ended December 31, 2015 and 2014.

	2015		2014
Audit Fees(1)	$	101,758	$	123,655
Audit Related Fees(2)		0		0
Tax Fees(3)		39,680		13,825
All Other Fees		0		17,704
Total Fees	$	141,438	$	155,184

(1)      Audit Fees: This category represents the aggregate fees billed for professional services rendered by the principal independent accountant for the audit of our annual financial statements and review of financial statements included in our Form 10-K and services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements for the fiscal years.

(2)      Audit Related Fees: This category consists of the aggregate fees billed for assurance and related services by the principal independent accountant that are reasonably related to the performance of the audit or review of our financial statements and are not reported under “Audit Fees.”

(3)      Tax Fees: This category consists of the aggregate fees billed for professional services rendered by the principal independent accountant for tax compliance, tax advice, and tax planning.

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PART IV

ITEM 15. EXHIBITS

Exhibit No.	Description
2.1	Share Exchange Agreement dated November 23, 2010.  (Incorporated by reference from Form 8-K filed with the SEC on November 24, 2010.) *
3.1	Articles of Incorporation.  (Incorporated by reference from Form S-1 filed with the SEC on May 2, 2008.) *
3.2	Certificate of Amendment to Articles of Incorporation dated December 10, 2014. (Incorporated by reference from Form 10-Q filed with the SEC on May 15, 2015.) *
3.3	Certificate of Amendment to Articles of Incorporation dated September 15, 2015. (Incorporated by reference from Form 10-Q filed with the SEC on November 12, 2015.) *
3.4	Amended and Restated Bylaws (Incorporated by reference from Form 8-K filed with the SEC on January 12, 2011.) *
4.1	Certificate of Designation for Series A Convertible Preferred Stock (Incorporated by reference from Form 8-K filed with the SEC on June 9, 2015.) *
4.2	Certificate of Designation for Series B Convertible Preferred Stock (Incorporated by reference from Form 8-K filed with the SEC on September 30, 2015.) *
10.1	Agreement to Participate in Oil and Gas Development Joint Venture between Bayshore Operating Corporation, LLC and Torchlight Energy, Inc. (Incorporated by reference from Form 8-K filed with the SEC on November 24, 2010) *
10.2	Purchase and Sale Agreement between Torchlight Energy Inc. and Xtreme Oil and Gas Inc..effective April 1, 2013. (Incorporated by reference from Form 10-Q filed with the SEC on May 15, 2013)*
10.3	Development Agreement between Ring Energy, Inc. and Torchlight Energy Resources, Inc. (Incorporated by reference from Form 8-K filed with the SEC on October 22, 2013.) *
10.4	Coulter Limited Partnership Agreement dated January 10, 2012 (Incorporated by reference from Form 10-Q filed with the SEC on August 14, 2014.) *
10.5	Promissory Note with Boeckman Well LLC dated May 1, 2013 and amendments thereto (Incorporated by reference from Form 10-Q filed with the SEC on August 14, 2014.) *
10.6	Securities Purchase Agreement (form of), January 2014  (Incorporated by reference from Form 10-Q filed with the SEC on August 14, 2014.) *
10.7	Registration Rights Agreement (form of), January 2014  (Incorporated by reference from Form 10-Q filed with the SEC on August 14, 2014.) *
10.8	Purchase Agreement with Hudspeth Oil Corporation, McCabe Petroleum Corporation and Greg McCabe dated August 7, 2014 (Incorporated by reference from Form 10-Q/A filed with the SEC on October 21, 2014.) *
10.9	Purchase and Sale Agreement between Torchlight Energy, Inc. and Zenith Petroleum Corporation (Incorporated by reference from Form 8-K filed with the SEC on June 10, 2014) *
10.10	Securities Purchase Agreement with Castleton Commodities Opportunities Master Fund, L.P. (Incorporated by reference from Form 8-K filed with the SEC on August 20, 2014) *
10.11	Purchase Agreement with Hudspeth Oil Corporation, McCabe Petroleum Corporation and Greg McCabe dated August 7, 2014 (Incorporated by reference from Form 10-Q/A filed with the SEC on October 21, 2014) *
10.12	12% Series B Unsecured Convertible Promissory Note (form of) (Incorporated by reference from Form 10-Q filed with the SEC on August 14, 2015.) *

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ITEM 15. EXHIBITS - continued

10.13	Securities Purchase Agreement (for Series A Convertible Preferred Stock) (Incorporated by reference from Form 10-Q filed with the SEC on August 14, 2015.) *
10.14	Employment Agreement (with John A. Brda) (Incorporated by reference from Form 8-K filed with the SEC on June 16, 2015.) *
10.15	Employment Agreement (with Willard G. McAndrew) (Incorporated by reference from Form 8-K filed with the SEC on June 16, 2015.) *
10.16	Employment Agreement (with Roger Wurtele) (Incorporated by reference from Form 8-K filed with the SEC on June 16, 2015.) *
10.17	Loan documentation and warrants with Eunis L. Shockey (Incorporated by reference from Form 10-Q filed with the SEC on August 14, 2015.) *
10.18	Farmout Agreement between Hudspeth Oil Corporation, Founders Oil & Gas, LLC and certain other parties (Incorporated by reference from Form 8-K filed with the SEC on September 29, 2015) *
10.19	Securities Purchase Agreement and Amendment to Securities Purchase Agreement (for Series B Convertible Preferred Stock) (Incorporated by reference from Form 10-Q filed with the SEC on November 12, 2015) *
10.20	Purchase and Sale Agreement with Husky Ventures, Inc. (Incorporated by reference from Form 8-K filed with the SEC on November 12, 2015) *
14.1	Code of Ethics (Incorporated by reference from Form S-1 filed with the SEC on May 2, 2008.) *

21.1	Subsidiaries
31.1	Certification of principal executive officer required by Rule 13a – 14(1) or Rule 15d – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of principal financial officer required by Rule 13a – 14(1) or Rule 15d – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of principal executive officer and principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and Section 1350 of 18 U.S.C. 63.
99.1	Report of CREST Engineering Services, Inc.
99.2	Report of PeTech Enterprises, Inc.

101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definitions Linkbase
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

* Incorporated by reference from our previous filings with the SEC

65

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Torchlight Energy Resources, Inc.
	/s/ John A. Brda
	By: John A. Brda
	President and Chief Executive Officer
Date:	March 30, 2016

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:

Signature	Title	Date
/s/ John A. Brda
John A. Brda	Director, President, Chief Executive Officer and Secretary (Principal Executive Officer)	March 30, 2016
/s/ Willard G. McAndrew III
Willard G. McAndrew III	Director and Chief Operating Officer	March 30, 2016
/s/ Roger N. Wurtele
Roger N. Wurtele	Chief Financial Officer (Principal Financial and Accounting Officer)	March 30, 2016
/s/ Jerry D. Barney
Jerry D. Barney	Director	March 30, 2016
/s/ Edward J. Devereaux
Edward J. Devereaux	Director	March 30, 2016
/s/ Eunis L. Shockey
Eunis L. Shockey	Director	March 30, 2016

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