Meta Materials 10K 2012 Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year endedDecember 31, 2012.

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)

2007 Enterprise Avenue

League City, Texas 77573

(Address of principal executive offices)

(281) 538-5938

(Registrant’s telephone number, including area code)

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

Common Stock ($0.001 Par Value)

(Title of Each Class)

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the 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 .

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. .

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	.	Accelerated filer	.
Non-accelerated filer	.(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 . No X.

At June 30, 2012, the aggregate market value of shares held by non-affiliates of the registrant (based upon 7,977,315 shares held by non-affiliates on June 30, 2012) was approximately $12,683,931.

At March 15, 2013, there were 13,659,815 shares of the registrant’s common stock outstanding (the only class of common stock).

DOCUMENTS INCORPORATED BY REFERENCE

None.

TABLE OF CONTENTS

PART I

Page


Item 1.		Business	3
Item 1A.		Risk Factors	9
Item 1B.		Unresolved Staff Comments	17
Item 2.		Properties	17
Item 3.		Legal Proceedings	19
Item 4.		Mine Safety Disclosures	19


	PART II

Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	20
Item 6.		Selected Financial Data	21
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk	24
Item 8.		Financial Statements and Supplementary Data	24
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	25
Item 9A.		Controls and Procedures	25
Item 9B.		Other Information	26

	PART III

Item 10.		Directors, Executive Officer and Corporate Governance	27
Item 11.		Executive Compensation	29
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	31
Item 13.		Certain Relationships and Related Transactions, and Director Independence	31
Item 14.		Principal Accountant Fees and Services	32
Item 15.		Exhibits, Financial Statement Schedules	33

		Signatures	34

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”). Originally, the company’s business objective was to develop and market fitness dance studios that offered an alternative to traditional gyms. 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”). At closing, the TEI Stockholders transferred all of their shares of TEI common stock to us in exchange for an aggregate of 9,444,500 newly issued shares of our common stock. Also at closing of the Exchange Agreement, certain of the former PPS shareholders transferred to us an aggregate of 14,400,000 shares of our common stock for cancellation in exchange for aggregate consideration of $270,000. Upon closing of these transactions, we had 12,251,420 shares of common stock issued and outstanding. The 9,444,500 shares issued to the TEI Stockholders at closing represented 77.1% of our voting securities after completion of the Exchange Agreement.

As a result of the transactions effected by the Exchange Agreement, at closing (i) TEI became our wholly-owned subsidiary, (ii) we abandoned all of our previous business plans within the health and fitness industries and (iii) the business of TEI became our sole business. TEI is an exploration stage energy company, incorporated under the laws of the State of Nevada in June 2010. It is engaged in the acquisition, exploration, exploitation and/or development of oil and natural gas properties in the United States. Descriptions of our business hereinafter refer to the business of TEI.

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

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

Business Overview

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

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

Key Business Attributes

Experienced People. We build on the expertise and experiences of our executive officers, Thomas Lapinski and John Brda. We will also receive guidance from outside advisors and will align with high quality exploration and technical partners.

Project Focus. We are focusing on exploitation and low risk exploration projects to reduce risk 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. Only enough capital exposure is planned initially to add value to a project and determine its economic viability. Projects are staged and have options before additional capital is invested. We will limit our exposure in any one project by participating at reduced working interest levels, thereby being able to diversify with limited capital. Management has experience in successfully managing risks of projects, finance, and value.

Partnering for Excellence. Partnering with highly select and experienced vendors provides ongoing access to external perspectives, new project opportunities, specialization, networks, operations support, and the ability to test continuously for more effective and cost efficient services.

Project Focus

Generally, we will focus on lower risk exploitation projects (primarily for oil, although gas projects will be considered if the economics are favorable). Projects are first identified, evaluated, and then we will secure a third party operating or financial partner. Subject to overall availability of capital, our interest in large capital projects will be limited. Initially, a large percentage of our assets is and will be allocated to the Marcelina Creek Field Development and the Coulter Field. After we have raised or generated sufficient capital, we will attempt to diversify our portfolio so that not greater than 25-30% of our capital is allocated in a particular project, of which there can be no assurance. An exception for a higher percentage would be an acquisition of a producing property with positive cash flow or smaller investment opportunities. Each opportunity will be investigated on a stand alone basis for both technical and financial merit. High risk exploration prospects are less favored than low risk exploration. 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 exploitation rather than higher risk exploration projects, it is expected that projects will come from the many small producers who find themselves under-funded or over-extended and therefore vulnerable to price volatility. The financial ability to respond quickly to opportunities will ensure a continuous stream of projects and will enable us to negotiate from a stronger position to enhance value.

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

Business Processes

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

Investment Evaluation and Review;

Operations and Field Activities; and

Administrative and Finance Management.

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

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

Administrative and Finance Management. This process will coordinate our initial structuring and capitalization, general operations and accounting, reporting, audit, banking and cash management, regulatory agencies reporting and interaction, timely and accurate payment of royalties, taxes, leases rentals, vendor accounts and performance management that includes budgeting and maintenance of financial controls, and interface with legal counsel and tax and other financial and business advisors. A single outsourced vendor that provides all or a majority of these services has not yet been located. Collectively, however, these services are available from a variety of experienced sources.

Current Projects

We currently have interests in two oil and gas projects, the Marcelina Creek Field Development in Wilson County, Texas and the Coulter Field in Waller County, Texas.

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. The first two wells include a horizontal re-entry well and a vertical development well within the 280 Johnson Unit, known as the Johnson #1 and Johnson #4, respectively. The remaining two wells are to be vertical development wells at locations to be determined within the existing lease.

TEI paid Bayshore an initial $50,000 deposit in July 2010, which amount was credited to the initial $50,000 payment due at the rig move in for the first well, the Johnson #1-BH. TEI was responsible for 100% of total drilling and completion costs for this re-entry well, in return for a 50% working interest. In August 2010, drilling on the first well commenced, with the drilling of a lateral section of the Buda Formation of approximately 1840 feet. The Johnson #1-BH encountered good oil and gas shows and a completion was attempted. The well, however, produced large volumes of water, some introduced by Bayshore during drilling and some from another source, either a deeper formation or from a nearby well. In July 2011 a workover crew was brought in to service the well, replace a broken rod and re-work the downhole pump. On July 27, 2011, the crew dropped two joints of pipe in the hole and on July 28 another six joints. The well was damaged sufficiently to be “shut-in” (meaning the valves at the wellhead have been closed so that the well stops pumping). The service company, Mercer Well Services, was notified of the damage and a meeting was to be arranged to settle the claim Bayshore and TEI would file against Mercer. In May 2012, Mercer informed us that they would re-drill the lateral portion of the Johnson #1, at their sole expense, as soon as was practical. Field operations began in June and the rig was moved in at the end of June. In July and August, the Johnson 1-BH well was successfully drilled and completed by Mercer. The Johnson #1 was originally drilled in the Buda Formation but was completed in the Austin Chalk Formation to avoid water problems. We completed the well for an initial rate of 419 barrels of oil per day (BOPD) and later tested 196 BOPD on an extended 30 day test. We have a 50% working interest in the well.

On April 15, 2011, TEI exercised its option to continue with the development program in Marcelina Creek by committing to the second well in the program (the first vertical development location well), the Johnson #4 well. We paid to Bayshore the $50,000 rig move in and paid drilling and completion costs of approximately $1.6 million for a 75% working interest in the well. We also paid $200,000 when the well was completed pursuant to the contract. A rig was contracted and moved in to drill the well and drilling operations began in July 2011. The well encountered several pay zones and an attempt to complete in the Buda Formation was made. We have encountered several mechanical and pump problems with the well which has delayed completion. After correcting the mechanical problems, in February 2012 the well was acidized (a technique involving pumping hydrochloric acid into the well under high pressure to reopen and enlarge the pores in the oil-bearing formations), and subsequently we have seen more stabilized flow in the well. The Johnson #4 is producing 25 to 30 barrels of oil a day. Although the well is producing in economic quantities, further stimulation techniques may need to be applied to enhance production.

On December 31, 2010 TEI executed an agreement with Bayshore for an extension of its drilling obligation deadline under the Participation Agreement. As a condition for the extension we paid to Bayshore $50,000 and issued it 10,000 shares of our common stock. As additional consideration, Bayshore is no longer obligated to pay its proportionate share of completion costs on the third well (the second vertical well) under the Participation Agreement. As of December 2012, we have paid Bayshore $50,000 for the rig move in fees for the third obligation well. We have entered into extension agreements with Bayshore, pursuant to which, by April 17, 2013 we are required to have paid 100% of the drilling, testing and completion costs of the third well. We are also obligated to pay the equipping or abandoning costs, as the case may be, and thereafter, $200,000 of the acquisition fee for the third well. Also pursuant to the extension agreements, in February 2013 we agreed to issue a total of 20,000 restricted shares of common stock to Bayshore principals and have paid, in advance, $150,000 as the portion of the leasehold money that becomes due and payable at the completion or plug and abandonment of the third well. For the third well, we will be responsible for 100% of the total drilling costs and 100% of the completion costs, for a 75% working interest in the well.

If we opt to continue with the fourth well contemplated by the Participation Agreement, TEI is obligated to pay Bayshore $50,000 at rig move in and $150,000 when the well is completed or plugged and abandoned. For the fourth well, we will be responsible for 100% of the total drilling costs and 75% of the completion costs (with Bayshore to pay 25% of the completion costs), for a 75% working interest in the well. TEI will also receive a 75% working interest on any subsequent wells drilled outside of the Johnson unit, with work to be done, as and when proposed, on a pro rata basis.

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

Coulter Field

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

Pursuant to the Coulter Agreement, we originally acquired a 34% working interest and a 25.5% net revenue interest in La Sal’s interest in the John Coulter #1-R for the purchase price of $350,000, which was to be applied to 100% of the cost of a fracture stimulation treatment on the well. We originally had a 34% interest in the well and the option to purchase an additional interest up to a total of 45%. We exercised the first option and purchased an additional 6% for $50,000, bringing our working interest to 40% and our net revenue interest to 30%. Our option to purchase an additional 5% working interest can be purchased for $50,000 within 30 days of first commercial production from the well. Once production is established the net revenue split will be 80% to us and 20% to La Sal until net revenue is an accumulated $437,500. During this period, expenses above the $350,000 initially paid in will be split according to actual percentage interests in the well. After net revenue is an accumulated $437,500, net revenue will be split according to the actual percentage interests in the well. Our total investment in the project, including fracture stimulation, subsequent testing, the purchase of additional interests and capitalized interest, amounted to $577,658 as of December 31, 2012.

The Coulter #1-R was a replacement well drilled by La Sal for the Coulter #1 which had mechanical problems caused by split casing. In February 2012 the well was fracture stimulated. The results were encouraging and the well appears to be capable of commercial gas production. However, the well is still recovering fluid and has not yet been hooked up to a nearby pipeline for production. The source of the fluid has not been conclusively determined. It may be recovery of drilling and/or fracture stimulation fluid or may be entering the wellbore from one or more downhole formations or an adjacent wellbore in the field. We are continuing to flow water from the well and the well is periodically shut–in for pressure build up tests. We have cemented off the split casing in the Coulter #1 well and are conducting tests to determine productivity. Discussions have already begun with the gas gatherer in the area, and we are working on completing the gas contract and the well.

Project Prospects

We have an ongoing process to identify specific projects that we will consider investing in, pending our ability to obtain adequate funding. We have not yet conducted thorough due diligence on any project prospect, nor had we made any significant commitments on any new projects as of December 31, 2012. There is no assurance we will choose to invest in any of these projects, if and when adequate funding becomes available.

Business Environment

Over half of United States’ crude oil is now imported because growth in demand exceeds domestic production, and this ratio is projected to increase into the foreseeable future. Although crude oil prices have been variable in recent years, longer-term global demand, especially from Asia and the Asian sub-continent is expected to offset growth in global supply, thus creating a continuous, although at times volatile, upward pressure on price. Further, new sources of international oil and gas reserves are located either far inland to existing port facilities or in very deep water. These new discoveries demand large capital investments for pipeline transportation and facilities. In the case of inland discoveries, agreements among sovereign governments may be required. Long negotiations result in long lead times from discovery to markets. Similarly for very deep water discoveries, both confirmation drilling and facilities construction require long lead times.

To complicate the environment even further, the recent BP oil spill in the Gulf of Mexico caused the United States government to place a moratorium on deep water drilling from May to October 2010. The moratorium’s long-term effect on price is still speculative. We believe the short-term effect on activity is that companies that had budgeted for capital projects in the offshore area for 2011 and 2012 have needed to invest in other exploration and production activities. Management envisions the companies that were operating offshore to focus some attention to onshore activities.

For United States natural gas, depressed prices resulted from the past two warm winter that reduced heating demand, the ability of the industry to increase production from shales with horizontal drilling, and increased production from the Gulf of Mexico. Prices will be volatile and subject to market emotions of early cold winters and other climatic conditions. This situation may offer an opportunity to acquire producing properties from numerous small producers who are impaired with high fixed overhead and sizable debt loads from earlier years. We, however, will favor oil projects but will investigate any opportunity on a stand alone basis.

With timely, accessible project finance arrangements, management believes we can profit from the opportunities provided by small producers that are virtually ignored by the major producers and large independents.

Industry Overview

The oil and gas industry has undergone a renaissance in both the balance of supply and demand and in technological advances. In recent years, large petroleum companies have migrated their spending toward exploration and production projects overseas and offshore, particularly deep water, as well as into downstream ventures. Such companies have consolidated their United States onshore investments into core geographic areas. The majors and large independents follow the rule that “90% of our revenue comes from 10% of our properties.”

The majors and large independents are, in varying degrees, burdened with high infrastructure overhead that when allocated to these properties make the properties unattractive for additional investment. The infrastructure for large companies includes services for human resources, information technology, accounting, land and division orders, and legal departments. Divesting of these non-core properties was made to independents and start-up companies. Independents also acquired large areas of leases particularly in the Haynesville, Marcelius, Bakken and now the Eagleford shale. This required the companies to drill quickly or lose the leases. That focus may have left some other on-going fields to be without re-investment. We believe this gradual migration of spending has possibly left onshore opportunities for nimble and experienced, lower cost oil and gas producers.

Competition

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

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

Marketing and Customers

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

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

Governmental Regulation and Environmental Matters

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

Regulation of Oil and Natural Gas Production

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

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; and

impose substantial liabilities for pollution resulting from operations.

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

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

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

Climate Change

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

Employees

We currently have two 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

During the period from June 25, 2010 (inception) to December 31, 2012, we did not spend any funds on research and development activities.

ITEM 1A. RISK FACTORS

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

Risks Related to the Company and the Industry

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

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

our ability to raise adequate working capital;

the success of our development and exploration;

the demand for natural gas and oil;

the level of our competition;

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

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

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

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

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

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

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

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

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

There is substantial doubt about our ability to continue as a going concern

At December 31, 2012, we had not yet achieved profitable operations, had accumulated losses of $5,422,297 since our inception, and expect to incur further losses in the development of our business, all of which casts substantial doubt about our ability to continue as a going concern. 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.

To date we have not implemented various corporate governance measures, in the absence of which, stockholders may have more limited protections against interested director transactions, conflicts of interest and similar matters.

As of the date of this report we have not adopted certain corporate governance measures. Although not required by rules or regulations applicable to us, corporate governance measures such as the establishment of an audit committee and other independent committees of our Board of Directors, would be beneficial to our stockholders. We do not presently maintain any of these protections for our stockholders. It is possible that if we were to adopt corporate governance measures, stockholders would benefit from greater assurance that decisions were being made with impartiality by directors and that policies had been implemented to define conduct of our management and board members.

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

We expect to primarily participate in wells operated by third-parties. Our ability to develop successful business operations depends on the success of our consultants and drilling partners. As a result, we will not control the timing or success of the development, exploitation, production and exploration activities relating to leasehold interests we acquire. If our consultants and drilling partners are not successful in such activities relating to such leasehold interests, or are unable or unwilling to perform, our financial condition and results of operation would be materially adversely affected.

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, we could become insolvent.

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

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

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

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

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

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

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

the level of consumer demand for oil and natural gas;

the domestic and foreign supply of oil and natural gas;

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

the price of foreign oil and natural gas;

domestic governmental regulations and taxes;

the price and availability of alternative fuel sources;

weather conditions;

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

worldwide economic conditions.

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

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

The oil and natural gas business involves a variety of operating hazards and risks such as well blowouts, pipe failures, casing collapse, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, spills, pollution, releases of toxic gas and other environmental hazards and risks. These hazards and risks could result in substantial losses to us from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties and suspension of operations. In addition, we may be liable for environmental damages caused by previous owners of property purchased and leased by us. 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 is expected to place a significant strain on our managerial, operational and financial resources, especially considering that we currently only have a small number of executive officers, employees and advisors. Further, as we enter into additional contracts, we will be required to manage multiple relationships with various consultants, businesses and other third parties. These requirements will be exacerbated in the event of our further growth or in the event that the number of our drilling and/or extraction operations increases. There can be no assurance that our systems, procedures and/or controls will be adequate to support our operations or that our management will be able to achieve the rapid execution necessary to successfully implement our business plan. If we are unable to manage our growth effectively, our business, results of operations and financial condition will be adversely affected, which could lead to us being forced to abandon or curtail our business plan and operations.

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

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

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

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

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.

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 Chief Executive Officer, Thomas Lapinski, and our President, John Brda. Mr. Lapinski and Mr. Brda each 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 Mr. Lapinski and Mr. Brda would be difficult to replace. While neither have plans to leave or retire in the near future, the loss of either 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 Mr. Lapinski or Mr. Brda. We have an employment agreement with Mr. Brda, and there is an employment agreement between Mr. Lapinski and TEI, our wholly owned subsidiary. There can be no assurance, however, that Mr. Lapinski or Mr. Brda will continue to be employed by us.

Our affiliates 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, Thomas Lapinski and John Brda, collectively and beneficially own approximately 40.4% of our outstanding common stock. Further, the four members of our Board of Directors, of which Messrs. Lapinski and Brda are members, collectively and beneficially own approximately 40.7% of our outstanding common stock. This concentration of voting control gives these affiliates substantial influence over any matters which require a stockholder vote, including without limitation the election of directors and approval of merger and/or acquisition transactions, even if their interests may conflict with those of other stockholders. It could have the effect of delaying or preventing a change in control or otherwise discouraging a potential acquirer from attempting to obtain control of us. This could have a material adverse effect on the market price of our common stock or prevent our stockholders from realizing a premium over the then prevailing market prices for their shares of common stock.

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

In the future, we may incur significant legal, accounting and other expenses as a result of operating as a public company. The Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), as well as new rules subsequently implemented by the SEC, have imposed various new 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.

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. Our testing may reveal deficiencies in our internal controls over financial reporting that are deemed to be material weaknesses. 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 hire additional accounting and financial staff with appropriate public company experience and technical accounting knowledge. Moreover, if we are not able to comply with the requirements of Section 404 in a timely manner, or if 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 OTC Bulletin Board. However, our shares 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.

The issuance of preferred stock could adversely affect the rights of the holders of common stock.

The Board of Directors has the authority to issue up to 5,000,000 shares of preferred stock in one or more series, to fix the number of shares constituting any such series, and to fix the rights and preferences of the shares constituting any series, without any further vote or action by the stockholders. The issuance of preferred stock by the Board of Directors could adversely affect the rights of the holders of common stock. For example, such issuance could result in a class of securities outstanding that would have preferences with respect to voting rights and dividends and in liquidation over the common stock, and could (upon conversion or otherwise) enjoy all of the rights appurtenant to common stock. The Board's authority to issue preferred stock could discourage potential takeover attempts and could delay or prevent a change in control of the company through merger, tender offer, proxy contest or otherwise by making such attempts more difficult to achieve or more costly. There are no issued and outstanding shares of preferred stock; there are no agreements or understandings for the issuance of preferred stock, and the Board of Directors has no present intention to issue preferred stock.

We may be subject to penny stock regulations and restrictions, and you may have difficulty selling shares of our common stock.

The SEC has adopted regulations which generally define a “penny stock” as an equity security that has a market price less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exemptions. Our common stock is a “penny stock” and is subject to Rule 15g-9 under the Exchange Act, or the “Penny Stock Rule.” This rule imposes additional sales practice requirements on broker-dealers that sell such securities to persons other than established customers and “accredited investors” (generally, individuals with a net worth in excess of $1,000,000, excluding the value of the primary residence of such individuals, or annual incomes exceeding $200,000, or $300,000 together with their spouses). For transactions covered by Rule 15g-9, a broker-dealer must make a special suitability determination for the purchaser and have received the purchaser's written consent to the transaction prior to sale. As a result, this rule may affect the ability of broker-dealers to sell our securities and may affect the ability of purchasers to sell any of our securities in the secondary market, thus possibly making it more difficult for us to raise additional capital.

For any transaction involving a penny stock, unless exempt, the rules require delivery, prior to any transaction in penny stock, of a disclosure schedule required by the SEC relating to the penny stock market. Disclosure is also required to be made about sales commissions payable to both the broker-dealer and the registered representative and current quotations for the securities. Finally, monthly statements are required to be sent disclosing recent price information for the penny stock held in the account and information on the limited market of penny stocks.

There can be no assurance that our common stock will qualify for exemption from the Penny Stock Rule. In any event, even if our common stock were exempt from the Penny Stock Rule, we would remain subject to Section 15(b)(6) of the Exchange Act, which gives the SEC the authority to restrict persons from participating in a distribution of a penny stock, under certain circumstances, if the SEC finds that such a restriction would be in the public interest.

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 trading limitation periods. Such volume could create a circumstance commonly referred to as an “overhang” and in anticipation of which the market price of our common stock could fall. The existence of an overhang, whether or not sales have occurred or are occurring, also could make it more difficult for us to secure additional financing through the sale of equity or equity-related securities in the future at a time and price that we deem reasonable or appropriate.

Our directors and officers have rights to indemnification.

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

We do not anticipate paying any cash dividends.

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not Applicable.

ITEM 2. PROPERTIES

Our principal executive offices are located at 2007 Enterprise Avenue, League City, Texas 77573. The office space for these executive offices is currently being provided to us at no charge by our Chief Executive Officer. Additionally, we lease approximately 500 square feet of office space in west Houston at the rate of $700 per month. We believe that the condition and size of our offices are adequate for our current needs.

Oil and Natural Gas Reserves

Reserve Estimates

SEC Case. The following tables sets forth, as of December 31, 2012, 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.

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, 2012. For purposes of determining prices, we used the average of oil prices received for each month within the 12-month period ended December 31, 2012, adjusted for quality and location differences, which was $98.44 per barrel (“bbl”). 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.


	Oil Reserves		Future Net Revenue (M$)
	Gross	Net		Present Worth
Category	(Bbl)	(Bbl)	Total	at 10%

Proved Developed Producing	55,794	24,804	$ 1,396.8	$ 1,169.1
Proved Undeveloped	751,021	392,745	8,538.2	2,130.5
Total Proved	806,815	417,549	$ 9,935.0	$ 3,299.6

Standardized Measure of Future Net Cash Flows Related to Proved Oil and Gas Properties				$ 2,909.0
Probable Undeveloped	1,875,312	937,053	$ 30,985.5	$ 12,236.6

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 with reserves supporting a probable classification from a probabilistic analysis where those reserves are “as likely as not to be recovered.” Probable reserves have not been discounted for the additional risk associated with future recovery.

Reserve Estimation Process, Controls and Technologies

The reserve estimates, including PV-10 estimates, set forth above were prepared by Netherland, Sewell & Associates, Inc. A copy of their full report with regard to our reserves is attached as Exhibit 99.1 to this annual report on Form 10-K. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards.

Our Chief Executive Officer is an experienced and qualified geoscience professional with a degree in geophysical science, but we do not have any employees with specific reservoir engineering qualifications in the company. Our Chief Executive Officer worked closely with Netherland, Sewell & Associates, Inc. in connection with their preparation of our reserve estimates, including assessing the integrity, accuracy and timeliness of the methods and assumptions used in this process.

Netherland, Sewell & Associates, Inc. is a large Texas-based professional engineering firm specializing in technical and financial evaluation of oil and gas assets. They used a combination of production and pressure performance, simulation studies, offset analogies, seismic data and interpretation, geophysical logs and other relevant field data to calculate our reserves estimates.

Proved Undeveloped Reserves

As of December 31, 2012, our proved undeveloped reserves totaled 392,745 bbls of oil. All of our proved undeveloped reserves at December 31, 2012 were associated with our Marcelina Creek Field property. Our proved undeveloped reserves are comprised of seven proved undeveloped drilling locations targeting the Buda formation and two proved undeveloped wells targeting the Eagle Ford shale formation, as reflected in the following table:


	As of December 31, 2012
			Net Future
Proved Undeveloped Reserves	Net		Development
Marcelina Creek Field	Reserves		Costs
	(Bbls)		($000's)

Buda Formation (7 Wells)	143,407	$	8,195
Eagle Ford Shale (2 Wells)	249,338		10,560

Total	392,745	$	18,755

Note: Net reserves are calculated based on our net revenue interest in the wells, whereas our net future development costs are calculated based on our net working interest in the wells.

Our current drilling plans, subject to sufficient capital resources and the periodic evaluation of interim drilling results and other potential investment opportunities, include drilling substantially all of the Buda wells in our proved undeveloped reserves during 2013 and 2014. We do not currently have plans to drill the Eagle Ford shale wells in the next year. The area of the Marcelina Creek Field is an active area of Eagle Ford shale development, and we intend to actively explore our options with regard to these proved undeveloped locations and other potential Eagle Ford drilling locations on our acreage.

Production, Price and Production Cost History

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

Our oil revenues for the year ended December 31, 2011 were minimal and consisted primarily of test oil production.

Drilling Activity and Productive Wells

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.

As of December 31, 2012, we had two productive wells in the Marcelina Creek Field (1.25 net wells) and one well which was in the process of being tested in the Coulter Field (.40 net wells). Net wells consist of the sum of our fractional working interests in these wells.

ITEM 3. LEGAL PROCEEDINGS

On February 16, 2012, we filed a lawsuit against Hockley Energy, Inc. and Frank O. Snortheim in the District Court of Harris County, Texas in connection with farmout agreements we entered into with Hockley Energy in November 2011 for the Marcelina Creek prospect and the East Stockdale prospect. We allege that Hockley Energy did not perform its obligations under the agreements, which obligations included providing the agreed upon funding, and we seek damages against both Hockley and Mr. Snortheim (who is a shareholder of Hockley Energy) for breach of contract, fraudulent inducement and promissory estoppel. Each defendant has answered our original petition with a general denial. We have also had discussions with the defendants regarding resolving this matter out of court, but we have not reached an agreement to date.

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.

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 Over-the-Counter Bulletin Board under the symbol, “TRCH.” Trading in our common stock in the over-the-counter market has been limited (averaging approximately 10,000 shares per day during 2012) 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, 2012 and 2011, according to OTC Markets Inc., were as follows:


Quarter Ended	High		Low
December 31, 2012	$	2.66	$	1.60
September 30, 2012	$	2.45	$	1.14
June 30, 2012	$	1.60	$	0.73
March 31, 2012	$	2.05	$	0.79
December 31, 2011	$	3.55	$	0.80
September 30, 2011	$	3.58	$	3.05
June 30, 2011	$	4.00	$	2.00
March 31, 2011	$	3.70	$	2.00

Record Holders

As of March 15, 2013, there were approximately 100 stockholders of record holding a total of 13,659,815 shares of common stock. The holders of the common stock are entitled to one vote for each share held of record on all matters submitted to a vote of stockholders. Holders of the common stock have no preemptive rights and no right to convert their common stock into any other securities. There are no redemption or sinking fund provisions applicable to the common stock.

Dividends

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

Equity Compensation Plan Information

As of December 31, 2012, we did not have any compensation plans (including individual compensation arrangements) under which our equity securities are authorized for issuance.

Sales of Unregistered Securities

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

In December 2012, we issued 65,000 warrants to an outside consultant as consideration for oil and gas consulting services. The warrants are immediately exercisable at an exercise price of $1.75 per share for a term of three years. The securities were issued under the exemption from registration provided by Section 4(2) of the Securities Act of 1933 and the rules and regulations promulgated thereunder. The issuance of securities did not involve a “public offering” based upon the following factors: (i) the issuance of the securities was an isolated private transaction; (ii) a limited number of securities were issued to a single offeree; (iii) there was no public solicitation; (iv) the investment intent of the offeree; and (v) the restriction on transferability of the securities issued.

In December 2012, we issued a total of 471,428 warrants to certain note holder in connection with the exchange of certain promissory notes for new promissory notes with different terms. The warrants are immediately exercisable and have a term of four years. 235,714 of the warrants have an exercise price of $1.75 and the other 235,714 have an exercise price of $2.00. The securities were issued under the exemption from registration provided by Section 4(2) of the Securities Act of 1933 and the rules and regulations promulgated thereunder. The issuance of securities did not involve a “public offering” based upon the following factors: (i) the issuance of the securities was an isolated private transaction; (ii) a limited number of securities were issued to a single offeree; (iii) there was no public solicitation; (iv) the investment intent of the offeree; and (v) the restriction on transferability of the securities issued.

In November 2012, we issued a total of 205,000 warrants to certain note holder in connection with the amendment of certain promissory notes. The warrants are immediately exercisable at an exercise price of $1.75 per share for a term of three years. The securities were issued under the exemption from registration provided by Section 4(2) of the Securities Act of 1933 and the rules and regulations promulgated thereunder. The issuance of securities did not involve a “public offering” based upon the following factors: (i) the issuance of the securities was an isolated private transaction; (ii) a limited number of securities were issued to a single offeree; (iii) there was no public solicitation; (iv) the investment intent of the offeree; and (v) the restriction on transferability of the securities issued.

In November 2012, we issued 80,000 warrants to certain consultants for professional services. The warrants are immediately exercisable at an exercise price of $1.75 per share for a term of two years. The securities were issued under the exemption from registration provided by Section 4(2) of the Securities Act of 1933 and the rules and regulations promulgated thereunder. The issuance of securities did not involve a “public offering” based upon the following factors: (i) the issuance of the securities was an isolated private transaction; (ii) a limited number of securities were issued to a single offeree; (iii) there was no public solicitation; (iv) the investment intent of the offeree; and (v) the restriction on transferability of the securities issued.

In December 2012, we issued 50,000 warrants to a consultant for professional services. The warrants are immediately exercisable at an exercise price of $1.75 per share for a term of two years. The securities were issued under the exemption from registration provided by Section 4(2) of the Securities Act of 1933 and the rules and regulations promulgated thereunder. The issuance of securities did not involve a “public offering” based upon the following factors: (i) the issuance of the securities was an isolated private transaction; (ii) a limited number of securities were issued to a single offeree; (iii) there was no public solicitation; (iv) the investment intent of the offeree; 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

The information set forth and discussed in this Management’s Discussion and Analysis and Plan of Operations is derived from the historical financial statements and the related notes thereto of Torchlight Energy, Inc. 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 contains 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 the other risks and uncertainties described in the “Risk Factors” section herein. 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 statement.

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. Because TEI became the successor business to PPS and because the operations and assets of TEI represent our entire business and operations from the closing date of the Exchange Agreement, the Management’s Discussion and Analysis and audited and unaudited financial statements are based on the consolidated financial results of PPS and its wholly owned subsidiary TEI for the relevant periods. Effective February 8, 2011, we changed our name from PPS to Torchlight Energy Resources, Inc.

Summary of Key Results

Overview

Our sole business is that of Torchlight Energy, Inc., an exploration stage company formed as a corporation in the State of Nevada on June 25, 2010. We are engaged in the acquisition, exploration, exploitation and/or development of oil and natural gas properties in the United States.

Results of Operations

The following discussion of our financial condition and results of operations should be read in conjunction with our audited financial statements, included herewith. 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. Due to this fact, comparisons to previous years are not necessarily indicative of actual operating results.

We currently have interests in two oil and gas projects, the Marcelina Creek Field Development in Wilson County, Texas and the Coulter Field in Waller County, Texas. See the description under “Current Projects” above in Item 1 of this report for more information about these projects.

Historical Results for the Year Ended December 31, 2012, Year Ended December 31, 2011 and the Period from June 25, 2010 (Inception) to December 31, 2012.

Revenues and Cost of Revenues

For the year ended December 31, 2012, we had revenue of $1,037,247 compared to $24,152 of revenue for the year ended December 31, 2011. During the quarter ended September 30, 2012, the Johnson #1-BH began production at an initial sustained rate of over 100 barrels of oil per day (36.6 barrels per day net to us), which accounts for the significant increase in revenues for the year. Our net volumes for 2012 were 10,655 barrels at an average price of $97.35 per barrel. Our cost of revenue, consisting of lease operating expenses and production taxes, was $500,053 ($46.93 per barrel) and $25,273 for the years ended December 31, 2012 and 2011, respectively.

We recorded depreciation, depletion and amortization expense of $551,890 ($51.80 per barrel) for the year ended December 31, 2012 as the Johnson wells in the Marcelina Creek Field began commercial production during this period.

General and Administrative Expenses

Our general and administrative expenses for the years ended December 31, 2012 and 2011 were $2,430,884 and $1,872,659, respectively. Our general and administrative expenses consisted of 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, 2012 compared to the year ended December 31, 2011 is primarily related to higher consulting costs and compensation incurred during the latter period.

Non-cash compensation, consisting of stock-based compensation and other non-cash compensation, totaled $1,268,216 for the year ended December 31, 2012 and $1,105,973 for the year ended December 31, 2011. This is the largest component of general and administrative expenses for these periods.

Liquidity and Capital Resources

We have been in the exploration stage since inception. As of December 31, 2012, we had a working capital deficit of $817,036, current assets of $164,495 consisting of cash, accounts receivable and prepaid expenses and total assets of $4,547,050 consisting of current assets, investments in oil and gas properties and goodwill. As of December 31, 2012, we had current liabilities of $981,531, consisting of accounts payable, payables to related parties, notes payable and accrued interest. Stockholders’ equity was $2,972,269 as of December 31, 2012.

For the period from inception until December 31, 2012, our cash flow used in operating activities was $971,936. Cash flow used in operating activities for the year ended December 31, 2012, was $130,274 compared to $800,310 for the year ended December 31, 2011. Cash flow used in operating activities during 2012 can be primarily attributed to net losses from operations, which consists primarily of general and administrative expenses. We expect to continue to use cash flow in operating activities until such time as we achieve sufficient commercial oil and gas production to cover all of our cash costs.

For the period from inception until December 31, 2012, our cash flow used in investing activities was $4,002,055. Cash flow used in investing activities for year ended December 31, 2012 was $830,755 compared to $2,056,342 for the year ended December 31, 2011. Cash flow used in investing activities consists primarily of oil and gas investments in the Johnson wells in the Marcelina Creek Field and Coulter project in Waller County.

For the period from inception until December 31, 2012, our cash flow provided by financing activities was $5,037,243. Cash flow provided by financing activities for the year ended December 31, 2012 was $506,000 as compared to $3,096,742 for the year ended December 31, 2011. Cash flow provided by financing activities in 2012 consists of promissory notes issued for cash, net or repayments of debt. During 2011, we realized $2,699,242 from the private placement of units consisting of common stock and warrants. We expect to continue to have cash flow provided by financing activities as we seek new rounds of financing and continue to develop our oil and gas investments.

Our current assets are insufficient to meet our current obligations or to satisfy our cash needs over the next twelve months and as such we will require additional debt or equity financing. Subsequent to December 31, 2012, we received net proceeds of approximately $1.65 million from the sale of additional 12% convertible promissory notes, but these proceeds will not be sufficient to fund all of our proposed drilling operations and operating needs during 2013. We will seek additional financing to meet these plans and needs. We face obstacles in continuing to attract new financing due to our history and current record of net losses and working capital deficits. Therefore, despite our efforts we can provide no assurance that we will be able to obtain the financing required to meet our stated objectives or even to continue as a going concern.

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

Commitments and Contingencies

We are subject to contingencies as a result of environmental laws and regulations. Present and future environmental laws and regulations applicable to our operations could require substantial capital expenditures or could adversely affect our operations in other ways that cannot be predicted at this time. As of December 31, 2012 and December 31, 2011, 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.

The 12% convertible promissory note agreement requires the Company to set aside and segregate funds on a monthly basis in the amount of 1/24 of the principal amount plus simple interest for two years, beginning in April 2013. Such funds can be used for repayment of the notes at maturity or pro-rata repurchase of the notes under specified circumstances, as well as the payment of interest. Scheduled sinking fund requirements related to the 12% convertible promissory notes are as follows :


For the years ended December 31,
2013	$	413,438
2014	$	551,250
2015	$	137,812

In late August 2011, TEI entered into discussions with Hockley Energy on a farm-in to TEI’s position in Marcelina Creek and nearby acreage in the Stockdale, Texas area. After numerous meetings a Letter of Intent was executed in October 2011 which included the terms of Hockley’s farm-in to TEI’s position. On November 4, 2011, TEI and Hockley Energy executed two farm-in agreements, one for Marcelina Creek and one for the East Stockdale acreage. Under the terms, Hockley was to fund a deposit of $1.5 million by November 6, 2011. To date no funds have been deposited, and we have filed a lawsuit against Hockley Energy alleging breach of contract, fraudulent inducement and promissory estoppel.

Going Concern

The accompanying audited consolidated financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which assumes that we will be able to meet our obligations and continue our operations for our next fiscal year.

At December 31, 2012, we had not yet achieved profitable operations and had accumulated losses of $5,422,297, of which $971,936 resulted in net cash used in operating activities since inception. We expect to incur further losses in the development of our business, which casts substantial doubt about 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) obtain loans from financial institutions, where possible, or (3) participating in joint venture transactions with third parties. Although management believes that we 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 consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not Applicable.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Our comparative financial statements for the fiscal year ended December 31, 2012 are attached hereto.

TABLE OF CONTENTS



	Page

Report of Independent Registered Public Accounting Firm	F-2

Consolidated Balance Sheets	F-3

Consolidated Statements of Operations	F-4

Consolidated Statements of Stockholders’ Equity	F-5

Consolidated Statements of Cash Flows	F-6
Notes to Consolidated Financial Statements	F-7

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Torchlight Energy Resources, Inc. (An Exploration Stage Company)

Houston, Texas

We have audited the accompanying consolidated balance sheets of Torchlight Energy Resources, Inc. (An Exploration Stage Company) (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations, stockholders’ equity and cash flows for the years then ended and for the period from June 25, 2010 (inception) to December 31, 2012. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with 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, 2012 and 2011, and the results of its operations and its cash flows for the years then ended and for the period from June 25, 2010 (inception) to December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has incurred losses since inception and is dependent upon obtaining adequate financing to fulfill its operating activities. Management’s plans regarding those matters are described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Houston, Texas

April 16, 2013

F-2


TORCHLIGHT ENERGY RESOURCES, INC.
(AN EXPLORATION STAGE COMPANY)

CONSOLIDATED BALANCE SHEETS

				DECEMBER 31,		DECEMBER 31,
				2012		2011
ASSETS

Current assets:
	Cash		$	63,252	$	518,281
	Accounts receivable			92,897		17,274
	Prepaid costs			8,346		16,267
		Total current assets		164,495		551,822

Investment in oil and gas properties, net				3,461,686		3,182,128

Debt issuance costs				473,785		-
Goodwill				447,084		447,084

		TOTAL ASSETS	$	4,547,050	$	4,181,034


LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
	Accounts payable		$	89,247	$	45,011
	Accrued liabilities			62,055
	Related party payables			768,648		258,750
	Notes payable to related party			51,000		-
	Convertible promissory notes			-		262,500
	Promissory notes, net of discount of $59,360 at December 31, 2011			-		325,640
	Interest payable			10,581		14,608
		Total current liabilities		981,531		906,509

Convertible promissory notes, net of discount of $521,864				580,636
Asset retirement obligation				12,614		11,369

Commitments and contingencies				-		-

Stockholders' equity:
	Preferred stock, no par value, 5,000,000 shares authorized; no shares issued or outstanding			-		-
	Common stock, par value $0.001 per share; 70,000,000 shares authorized; 13,564,815 issued and outstanding at December 31, 2012 14,664,815 issued and outstanding at December 31, 2011			13,565		14,665
	Additional paid-in capital			8,381,001		5,861,985
	Accumulated deficit			(5,422,297)		(2,613,494)
		Total stockholders' equity		2,972,269		3,263,156

		TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	4,547,050	$	4,181,034

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

F-3



TORCHLIGHT ENERGY RESOURCES, INC.
(AN EXPLORATION STAGE COMPANY)

CONSOLIDATED STATEMENTS OF OPERATIONS

								JUNE 25, 2010
				YEAR		YEAR		(Inception)
				ENDED		ENDED		TO
				DECEMBER 31, 2012		DECEMBER 31, 2011		DECEMBER 31, 2012
Revenue
	Oil and gas sales		$	1,037,247	$	24,152	$	1,061,399

Cost of revenue				500,053		25,273		525,326

Gross income (loss)				537,194		(1,121)		536,073

Operating expenses:
	General and administrative expense			2,430,884		1,872,659		4,948,845
	Depreciation, depletion and amortization			551,890		-		551,890
		Total operating expenses		2,982,774		1,872,659		5,500,735

Other income (expense)
	Interest income			12		186		198
	Interest and accretion expense			(363,235)		(94,598)		(457,833)
		Total other income (expense)		(363,223)		(94,412)		(457,635)

Net loss before taxes				2,808,803		1,968,192		5,422,297

Provision for income taxes				-		-		-

Net loss			$	2,808,803	$	1,968,192	$	5,422,297

Loss per share: Basic and Diluted
Loss per share: Basic and Diluted			$	(0.196)	$	(0.138)	$	(0.382)
Weighted average shares outstanding: Basic and Diluted
				14,334,473		14,288,211		14,212,967

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

F-4


TORCHLIGHT ENERGY RESOURCES, INC.
(AN EXPLORATION STAGE COMPANY)

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
FOR THE PERIOD FROM JUNE 25, 2010 (INCEPTION) TO DECEMBER 31, 2012

											Deficit
											accumulated
					Common		Common		Additional		during the
				Preferred	stock		stock		paid-in		exploration
				stock	shares		amount		capital		stage		Total

Balance, June 25, 2010			$	-	-	$	-	$	-	$	-	$	-

	Shares issued to management			-	8,000,000		8,000		2,000		-		10,000

	Shares issued in private placement			-	1,444,500		1,444		1,443,057		-		1,444,501

	Reverse merger transaction:
		Recapitalization on reverse merger		-	17,206,920		17,207		429,877		-		447,084
		Cancellation of common shares		-	(14,400,000)		(14,400)		(255,600)		-		(270,000)

	Issuance of common stock for services			-	450,000		450		312,550		-		313,000


	Warrants issued in connection with promissory notes			-	-		-		65,250		-		65,250

	Net loss			-	-		-		-		(645,302)		(645,302)

Balance, December 31, 2010			$	-	12,701,420	$	12,701	$	1,997,134	$	(645,302)	$	1,364,533

	Issuance of common stock for services			-	420,971		421		1,105,552		-		1,105,973

	Shares issued in private placement			-	1,542,424		1,543		2,580,915		-		2,582,458

	Warrants issued in private placement			-	-		-		116,784		-		116,784

	Warrants issued in connection with promissory notes			-	-		-		61,600		-		61,600

	Net loss			-	-		-		-		(1,968,192)		(1,968,192)

Balance, December 31, 2011			$	-	14,664,815	$	14,665	$	5,861,985	$	(2,613,494)	$	3,263,156

	Issuance of common stock for services			-	425,000		425		329,450		-		329,875

	Shares issued in connection with promissory notes			-	75,000		75		67,650		-		67,725

	Warrants issued in connection with promissory notes			-	-		-		791,376		-		791,376

	Beneficial conversion feature on convertible notes			-	-		-		390,600		-		390,600

	Warrants issued for services			-	-		-		938,340		-		938,340

	Common stock retired			-	(1,600,000)		(1,600)		1,600		-		-

	Net loss			-	-		-		-		(2,808,803)		(2,808,803)

Balance, December 31, 2012			$	-	13,564,815	$	13,565	$	8,381,001	$	(5,422,297)	$	2,972,269


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

F-5


TORCHLIGHT ENERGY RESOURCES, INC.
(AN EXPLORATION STAGE COMPANY)

CONSOLIDATED STATEMENTS OF CASH FLOW

									JUNE 25, 2010
					YEAR		YEAR		(Inception)
					ENDING		ENDING		TO
					DECEMBER 31, 2012		DECEMBER 31, 2011		DECEMBER 31, 2012
Cash Flows From Operating Activities
	Net loss			$	(2,808,803)	$	(1,968,192)	$	(5,422,297)
	Adjustments to reconcile net loss to net cash from operating activities:

		Stock based compensation			1,268,216		1,105,973		2,687,139
		Accretion of convertible note discounts			313,963		68,031		382,044
		Depreciation, depletion and amortization			551,890		-		551,890
		Change in:
			Accounts receivable		(75,623)		(17,274)		(92,897)
			Prepaid expenses		7,921		(15,267)		(8,346)
			Accounts payable and accrued liabilities		106,291		(206,939)		151,302
			Related party payable		509,898		218,750		768,648
			Interest payable		(4,027)		14,608		10,581
Net cash used in operating activities					(130,274)		(800,310)		(971,936)

Cash Flows From Investing Activities
	Investment in oil and gas properties				(905,326)		(2,056,342)		(4,076,626)
	Proceeds from the sale of oil and gas properties				74,571		-		74,571
Net cash used in investing activities					(830,755)		(2,056,342)		(4,002,055)

Cash Flows From Financing Activities
	Proceeds from promissory notes				1,049,000		647,500		1,946,500
	Repayment of promissory notes				(543,000)		(250,000)		(793,000)
	Shares issued to management				-		-		10,000
	Proceeds from private placements				-		2,699,242		4,143,743
	Cancellation of common shares				-		-		(270,000)
Net cash provided by financing activities					506,000		3,096,742		5,037,243

Net increase in cash					(455,029)		240,090		63,252

Cash - beginning of period					518,281		278,191		-

Cash - end of period				$	63,252	$	518,281	$	63,252

Supplemental disclosure of cash flow information:
	Non cash transactions:
		Recapitalization on reverse merger		$	-	$	-	$	447,084
		Common stock issued in connection with promissory notes		$	67,725	$	-	$	67,725
		Warrants issued in connection with promissory notes		$	791,376	$	61,600	$	918,226
		Beneficial conversion feature on promissory notes		$	390,600	$	-	$	252,000
		Exchange of promissory notes		$	412,500	$	-	$	412,500
		Retirement of common stock		$	1,600	$	-	$	1,600
		Asset retirement obligation		$	693	$	10,828	$	11,521
	Interest paid			$	105,488	$	12,501	$	117,989

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

F-6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. NATURE OF BUSINESS

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”). At closing, the TEI Stockholders transferred all of their shares of TEI common stock to us in exchange for an aggregate of 9,444,500 newly issued shares of our common stock. This transaction was recorded as a reverse acquisition for accounting purposes where TEI is the accounting acquirer. The assets and liabilities of PPS were recorded at fair value of $0. The Company recorded $447,084 of goodwill which represents the estimated fair value of the consideration exchanged. Also at closing of the Exchange Agreement, certain of the former PPS shareholders transferred to us an aggregate of 14,400,000 shares of our common stock for cancellation in exchange for aggregate consideration of $270,000. Upon closing of these transactions, we had 12,251,420 shares of common stock issued and outstanding. The 9,444,500 shares issued to the TEI Stockholders at closing represented 77.1% of our voting securities after completion of the Exchange Agreement.

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, 2012, the Company had not yet achieved profitable operations, had accumulated losses of $5,422,297 since its inception and may incur further losses in the development of its business. This casts substantial doubt about the Company’s 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.

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.

F-7

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 subsidiary, Torchlight Energy, Inc. All significant intercompany balances and transactions have been eliminated.

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 notes to related party 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 remeasurement 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, 2012 and 2011 no valuation allowance was considered necessary.

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.

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. Prior to December 31, 2011, the investment in oil and gas properties included only unevaluated oil and gas properties and other costs excluded from amortization; therefore, no depreciation, depletion or amortization was recognized in those periods.

F-8

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 unweighed 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 did not recognize impairment on its oil and gas properties during the year ended December 31, 2012, nor any prior period. 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. 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.

Goodwill - Goodwill represents the excess of the purchase price over the fair value of the net identifiable tangible and intangible assets of acquired companies. Goodwill is not amortized; instead, it is tested for impairment annually or more frequently if indicators of impairment exist.

Goodwill was $447,084 as of December 31, 2012 and December 31, 2011 and was acquired on November 23, 2010 in connection with the Company’s reverse acquisition (Note 1).

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.

F-9

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.

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 – In January 2010, the Financial Accounting Standards Board (“FASB”) issued its updates to oil and gas accounting rules to align the oil and gas reserve estimation and disclosure requirements of Extractive Industries — Oil and Gas with the requirements in the SEC’s final rule, Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008. It is intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. The amendments are also designed to modernize the oil and gas disclosure requirements to align them with current practices and changes in technology. Revised requirements in this guidance include, but are not limited to:

Oil and gas reserves must be reported using the average price over the prior 12-month period, determined as an un-weighted arithmetic average of the first-day-of-the-month price for each month within such period, rather than year-end prices;

Companies are allowed to report, on an optional basis, probable and possible reserve;

Non-traditional reserves, such as oil and gas extracted from coal and shales, are included in the definitions of “oil and gas producing activities”;

Companies are permitted to use new technologies to determine proved reserves, as long as those technologies have been demonstrated empirically to lead to reliable conclusions with respect to reserve volumes;

Companies are required to disclose, in narrative form, additional details on their proved undeveloped reserves (PUDs), including the total quantity of PUDs at year end, any material changes to PUDs to developed oil and gas reserves and an explanation of the reasons why material concentrations of PUDs in individual fields or countries have remained undeveloped for five years or more after disclosure as PUDs;

Companies are required to report the qualifications and measures taken to assure the independence and objectivity of any business entity or employee primarily responsible for preparing or auditing the reserves estimates.

In December 2010, the FASB issued amended accounting guidance relating to goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform “Step two” of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not, that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist.

In May 2011, the FASB issued updated accounting guidance related to fair value measurements and disclosures. This guidance includes amendments that clarify the application of existing fair value measurement requirements, in addition to other amendments that change principles or requirements for measuring fair value and for disclosing information about fair value measurements. This guidance is effective for annual periods beginning after December 15, 2011. The adoption of this guidance did not have a material effect on the Company’s consolidated financial statements.

In September 2011, the FASB issued guidance that amends and simplifies the rules related to testing goodwill for impairment. The revised guidance allows an entity to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination whether it is more likely than not that the fair value of reporting unit is less than its carrying amount. The results of this assessment will determine whether it is necessary to perform the currently required two-step impairment test. Under this update, an entity also has the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the two-step goodwill impairment test.

The two preceding amendments listed above were effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, with early adoption permitted. The impact on this guidance on the consolidated financial statements was not material.

F-10

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 all subsequent events through April 15, 2013, the date of issuance of the financial statements. Subsequent events are disclosed in Note 11.

Reclassifications – Certain amounts from the prior year have been reclassified to conform to the current year presentation. The reclassifications had no impact on total assets or the net loss.

4. RELATED PARTY TRANSACTIONS

Since inception, the Company’s Chief Executive Officer has charged the Company a management fee for his services through an entity that he controls, Opal Marketing & Consulting, Inc., in the amount of $240,000 per year. As a result of limited cash flow, payments under this arrangement have been deferred since April 1, 2011. Accordingly, the Company had a related party payable of $420,000 and $180,000 as of December 31, 2012 and 2011, respectively. Cash payments under this arrangement have totaled $180,000 since the inception of the Company on June 25, 2010.

In February and March of 2012, the Company issued three non-interest bearing promissory notes totaling $59,000 to the Chief Executive Officer of the Company, for cash received. The first of these notes, totaling $8,000, was repaid in November 2012. The balance of $51,000 is reflected in notes payable to related parties and is due on demand. Subsequent to December 31, 2012, the Company repaid both remaining notes in the amount of $51,000.

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, 2012 and 2011, 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.

6. CAPITALIZED COSTS

The following table presents the capitalized costs of the Company as of December 31, 2012 and 2011:


			2012		2011


Evaluated costs subject to amortization		$	3,435,918	$	-
Unevaluated costs			577,658		3,182,128
	Total capitalized costs		4,013,576		3,182,128
Less accumulated depreciation, depletion and amortization			(551,890)		-
	Net capitalized costs	$	3,461,686	$	3,182,128

The unevaluated costs reflected above as of December 31, 2012, consist entirely of the Company’s interest in the Coulter #1 well which was re-entered and extended horizontally during 2012. This well is undergoing production and test operations with the goal of removing sufficient water from the wellbore to allow production of natural gas.

7. STOCKHOLDERS’ EQUITY

F-11

During 2011, the Company conducted a private placement of common stock units consisting of (a) two shares of common stock and (b) a warrant to purchase one share of common stock at an exercise price of $5.00 per share for a period of three years from the purchase date. The Company sold 771,212 units for aggregate proceeds of $2,699,242. Of the total proceeds, $116,784 was allocated to the value of the warrants issued and $2,582,458 was allocated to the value of 1,542,424 common shares issued.

As discussed in Note 9, below, the company issued 75,000 common shares in connection with promissory notes during the year ended December 31, 2012.

The Company also issued common shares as compensation for services. For the year ended December 31, 2012, the Company issued 425,000 common shares in exchange for services, with a total value of $329,875. During the year ended December 31, 2011, the Company issued 420,971 common shares in exchange for services, with a total value of $1,105,973.

During the year ended December 31, 2012, the Company issued 1,245,000 warrants as compensation for services, with a total value of $938,340 and also issued 952,428 warrants in connection with debt transactions for total value of $791,376.

During the year ended December 31, 2011, the Company issued 385,000 warrants in connection with debt transactions for total value of $61,600.

A summary of warrants outstanding as of December 31, 2012 by exercise price and year of expiration is presented below:


Exercise	Expiration Date in
Price	2014	2015	2016	2017	Total

$ 1.75	80,000	855,000	1,235,714	-	2,170,714
$ 2.00	-	-	235,714	126,000	361,714
$ 2.50	225,000	50,000	-	-	275,000
$ 5.00	771,212	-	-	-	771,212
	1,076,212	905,000	1,471,428	126,000	3,578,640

As of December 31, 2012, all warrants issued were still outstanding as no warrants had expired or been exercised. The Company had reserved 3,578,640 shares for future exercise of warrants. For all periods presented, the shares from the potential exercise of the warrants were excluded from the calculation of diluted earnings per share as the effects would have been anti-dilutive.

Warrants issued in relation to the promissory notes issued (see note 9), the equity Units above and warrants issued for services 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	.68% - 0.64%
Expected volatility of common stock	103.00% - 40.00%
Dividend yield	0.00% - 0.00%
Discount due to lack of marketability	30.00% - 30.00%
Expected life of warrant	4 years- 2 years

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 carryforwards. 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.

F-12

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 during the period from June 25, 2010 (inception) to December 31, 2012.

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, 2012 and 2011and the period from June 25, 2010 (inception) to December 31, 2012:


		Year ended		Year ended		June 25, 2010 (inception) through
		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2012
Federal income tax benefit at statutory rate	$	(954,993)	$	(669,185)	$	(1,843,581)
Permanent Differences		84,574		22,947		107,521
Other		(22,185)		-		(22,185)
Change in valuation allowance		892,604		646,238		1,758,245
Provision for income taxes	$	-	$	-	$	-

The tax effects of temporary differences that gave rise to significant portions of deferred tax assets and liabilities are as follows:


		Dec. 31, 2012		Dec. 31, 2011
Deferred tax assets:
Net operating loss carryforward	$	1,988,631	$	1,241,407
Accruals		163,200		61,200
Reserves		372		-
Deferred tax liabilities:
IntaIntangible drilling and other costs for oil and gas properties		(393,958)		(436,966)
Net deferred tax assets and liabilities		1,758,245		865,641
Less valuation allowance		(1,758,245)		(865,641)
Total deferred tax assets and liabilities	$	-	$	-

The Company had a net deferred tax asset related to federal net operating loss carryforwards of $5,848,916 and $3,651,197 at December 31, 2012 and December 31, 2011, 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

On December 28, 2010, the Company issued a convertible promissory note and a warrant to purchase 225,000 shares of common stock to an accredited investor who paid $250,000 in aggregate consideration for the securities. The convertible promissory note bore interest at the rate of 10% per annum, had a principal amount of $250,000 and was convertible into shares of common stock in the event the Company undertook a private offering of securities to one or more third parties. The note was convertible on the same terms and conditions offered to such third parties. The warrant is exercisable into 225,000 shares of common stock at a price of $2.50 per share and expires on December 28, 2014. The note was collateralized by 750,000 shares of pledged securities of a related party. The convertible note was recorded net of discount consisting of the fair value of the warrants calculated under the Black Scholes option pricing model as $62,250. The discount is accreted over the life of the debt using the effective interest method. On June 28, 2011, the Company paid $262,500 to the holder of the convertible promissory note representing full payment of principal and interest.

F-13

On June 24, 2011, the Company issued a total of three 10% Convertible Promissory Notes with an aggregate principal amount of $262,500 for aggregate consideration of that amount. Each of the notes carried an interest rate of 10% per annum and the original due date was December 31, 2011. The Company entered into an extension agreement, effective January 1, 2012, with the note holders. Under the terms of the extension agreement, the Note Holders agreed to extend the maturity date of each of the notes to December 31, 2012 in consideration of the following: (i) the pro-rata issuance of a total of 75,000 shares of common stock to the Note Holders, (ii) the continued right to convert any of the outstanding principal and interest of the notes into Units of the Company’s securities at the conversion price of $3.50 per Unit, which Units each consist of two shares of common stock and one three-year warrant to purchase a share of common stock at the price of $5.00 per share, and (iii) for each Unit the Note Holder receives upon such conversion set forth in “(ii)” above, the Note Holder will receive two additional three-year warrants to purchase a share of common stock at the exercise price of $1.75 per share and one additional three-year warrant to purchase a share of common stock at the exercise price of $5.00 per share. The 75,000 shares of common stock were valued at $67,725, which was recorded as debt issuance costs and was amortized over the one-year term of the extension agreement. In November 2012, the note holders agreed to extend the maturity dates of these notes to June 30, 2013 in exchange for three-year warrants to purchase an aggregate of 125,000 shares of common stock, valued at $83,750.

On December 21, 2011, the Company issued a 10% promissory note and a warrant to purchase shares of common stock to an accredited investor who paid $385,000 in aggregate consideration for the securities. The 10% promissory note bears interest at the rate of 10% per annum, has a principal amount of $385,000 and a maturity date of September 21, 2012. The warrant is exercisable into 385,000 shares of common stock at a price of $1.75 per share and expires on December 21, 2015. The note was collateralized by 1,000,000 shares of pledged securities of a related party. The convertible note was recorded net of discount consisting of the relative fair value of the warrants calculated under the Black Scholes option pricing model at $61,600. The discount is accreted over the life of the debt using the effective interest method. Accretion expense for the years ended December 31, 2012 and 2011 was $59,360 and $2,240, respectively. In November 2012, the note holder agreed to extend the maturity date of this note to June 30, 2013. Pursuant to the extension, the note’s interest rate increased to 18% per annum as of September 21, 2012. This note was repaid in December 2012 from the proceeds of the 12% convertible promissory notes described below.

On March 26, 2012, the Company issued two Series A 10% Convertible Promissory Notes for aggregate consideration of $150,000. The notes were originally due on September 26, 2012 and bore interest at the rate of 10% per annum. Each of the notes is convertible on and after the earlier to occur of (i) August 26, 2012, (ii) an un-cured event of default or (iii) the Company’s election to pre-pay the note. The notes are convertible into shares of common stock at the conversion price of $1.75 per share. The notes are collateralized with (i) a first lien on the Company’s interest in the Johnson #4 well, (ii) a second lien on the Company’s interest in the two John Coulter wells, and (iii) shares of stock pledged by the Company’s Chief Executive Officer. In connection with the issuance of the notes, the Company also issued the holders three-year warrants to purchase an aggregate of 150,000 shares of common stock at the exercise price of $1.75 per share. Also in connection with the issuance of the notes, the Company amended the $262,500 of convertible promissory notes it had previously issued on June 24, 2011. The new amendments to the notes give the holders collateral in the Company’s interest in the Johnson #4 well and the two John Coulter wells. The new amendments also provide that each holder will not have the right to convert outstanding principal and interest of the note or the right to receive additional warrants to purchase shares of common stock until the earlier to occur of (i) December 1, 2012, (ii) an un-cured event of default and (iii) the Company’s election to pre-pay the note. The Series A Convertible Promissory Notes were recorded net of discount for the fair value of the 150,000 warrants amounting to $42,900. The discount is accreted over the life of the debt using the effective interest method. Accretion expense was $42,900 for the nine months ended September 30, 2012. In November 2012, the note holders agreed to extend the maturity dates of these notes to June 30, 2013. In connection with the extension, the Company issued the holders three-year warrants to purchase an aggregate of 80,000 shares of common stock, valued at $53,600.

On December 18, 2012, the Company exchanged the $262,500 of convertible promissory notes and the $150,000 of Series A Convertible Promissory Notes for new 12% Convertible Promissory Notes described below. The 12% Convertible Promissory Notes were issued as part of a larger offering with senior liens on the Company’s oil and gas properties. In order to induce the holders of the notes described above to exchange such promissory notes and to relinquish their priority liens on the Company’s oil and gas properties in favor of all 12% Convertible Promissory Note Holders, the Company agreed to grant the note holders a total of 235,714 four year warrants to purchase common stock at $1.75 per share, valued at $240,428, and 235,714 four year warrants to purchase common stock at $2.00 per share, valued at $233,357. The total of these warrants, $473,785, is reflected as debt issuance costs on the balance sheet as these costs relate to the larger offering of 12% Convertible Promissory Notes. In connection with this conversion, the un-accreted cost of the warrants issued in exchange for the November 2012 extension agreements were charged to interest expense.

F-14

On December 18, 2012, the Company issued $690,000 of 12% Convertible Promissory Notes (12% Notes) to new investors. Together with the conversion described above, there was $1,102,500 of principal amount outstanding as of December 31, 2012. The 12% Notes are due and payable on March 31, 2015 and provide for conversion into common stock at a price of $1.75 per share and include the issuance of 8,000 warrants for each $70,000 of principal amount purchase. The warrants carry a five year term ending December 31, 2017 and have an exercise price of $2.00 per share. They were valued at $137,340, which is reflected as a discount on the 12% Notes, to be amortized over the life of the debt under the effective interest method. Since the conversion price on the 12% Notes was below the market price on the date of issuance, this constitutes a beneficial conversion feature. The amount is calculated as the difference between the market price of the common stock on the date of closing and the effective conversion price as adjusted by the discount for the warrants granted. The amount of the beneficial conversion feature was $390,600, and is also reflected as a discount on the 12% Notes. The fair value of the Convertible Promissory Notes is determined utilizing Level 2 measurements in the fair value hierarchy.

The 12% Notes have a first priority lien on all of the assets of the Company. Additionally, the note agreement requires the Company to set aside and segregate funds on a monthly basis in the amount of 1/24 of the principal amount plus simple interest for two years, beginning in April 2013. Such funds can be used for repayment of the notes at maturity or pro-rata repurchase of the notes under specified circumstances, as well as the payment of interest.

Scheduled sinking fund requirements related to the 12% Notes are as follows :


For the years ended December 31,

2013	$	13,438
2014	$	51,250
2015	$	37,812

10. ASSET RETIREMENT OBLIGATIONS

The following is a reconciliation of the asset retirement obligation liability for the years ended December 31, 2011 and 2012:


Asset retirement obligation – January 1, 2011	$	-
Estimated liabilities recorded		10,828
Accretion expense		541
Asset retirement obligation – December 31, 2011		11,369
Adjustment to estimated liability		693
Accretion expense		552
Asset retirement obligation – December 31, 2011	$	12,614

11. SUBSEQUENT EVENTS

Subsequent to December 31, 2012, the Company sold additional 12% convertible promissory notes to investors for total gross proceeds of $1,836,000. The majority of these notes were sold through one or more placement agents for cash fees of 10% of the gross proceeds.

12. SUPPLEMENTARY OIL & GAS INFORMATION - UNAUDITED

The supplementary data presented reflects information for all of our oil and gas producing activities. Cost incurred for oil and gas leasehold and drilling activity is as follows:


Capitalized Costs Incurred in Oil and Gas Operations
Years ended December 31, 2012 and 2011 and the period from June 25, 2010
(inception) to December 31, 2012

		2012		2011		Cumulative

Unproved property acquisition costs	$	50,000	$	344,986	$	602,486
Drilling and exploration costs		854,602		1,705,456		3,392,945
Geological and geophysical costs		724		5,900		81,195
	$	905,326	$	2,056,342	$	4,076,626

F-15

On June 22, 2012 we entered into an agreement with Fossil Energy pertaining to the Kimball Nebraska exploration program. Under the terms of the agreement Fossil returned to us $74,571 representing cumulative costs paid by us for Geo-chemical studies in the exploration area. We have no further interest in the area.


Torchlight Energy
Standardized Measure of Discounted Future Net Cash
Flows Relating to Proved Oil and Gas Reserves
Year Ended December 31, 2012
		2012
		($000's)

Future cash flows	$	41,103

Future production costs		(12,413)
Future development costs		(18,755)
Future income tax expense		(1,012)

Future net cash flows		8,923

10% annual discount for estimated
timing of cash flows		(6,014)

Standardized measure of discounted
future net cash flows	$	2,909


Proved Reserves
As of December 31, 2012

		2012
		(Bbls)

Balance, January 1, 2012		-

Extensions, discoveries and other additions		428,204
Production		(10,655)

Balance, December 31, 2012		417,549

Proved developed reserves		24,804

F-16

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

Not Applicable.

ITEM 9A. CONTROLS AND PROCEDURES

Thomas Lapinski, our Chief Executive Officer, is our principal executive officer and principal financial officer.

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, 2012. 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 and adequately designed 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.

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) under the Exchange Act). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that:

(i)

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

(ii)

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements; and

(iii)

provide reasonable assurance regarding prevention or timely detection of unauthorized transactions.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

In making this assessment, our management used 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.

We evaluated control deficiencies identified through our test of the design and operating effectiveness of controls over financial reporting to determine whether the deficiencies, individually or in combination, are significant deficiencies or material weaknesses. In performing the assessment, our management has identified material weaknesses in internal control over financial reporting existing as of December 31, 2012. Our evaluation of the significance of each deficiency included both quantitative and qualitative factors. Based on that evaluation, our management concluded that as of December 31, 2012, our internal controls are not effective, for the reason discussed below:


1.	We did not yet have written documentation of our internal control policies and procedures. Written documentation of key internal controls over financial reporting is a requirement of Section 404 of the Sarbanes-Oxley Act and may be applicable to us in future years.

2.	We did not have sufficient segregation of duties within accounting functions, which is a basic internal control. Due to our extremely small size and the fact that we had only two management employees as of December 31, 2012, both of whom are also executive officers and directors, segregation of all conflicting duties may not be possible and may not be economically feasible. To the extent possible, the initiation of transactions, the custody of assets and the recording of transactions should be performed by separate individuals.

3.	We did not have any full-time accounting employees. This means that we lacked the requisite expertise internally in the key functional areas of finance and accounting and we had to rely on outside contractors and other resources in this area. In addition, this means we did not have available personnel to properly implement control procedures.



4.	We did not have a functioning audit committee of our board of directors. An audit committee is one method to provide oversight in the establishment and monitoring of required internal controls and procedures.

5.	We had not established adequate financial reporting monitoring activities to mitigate the risk of management override. We had only two employees as of December 31, 2012 and both were executive officers. In this environment, the risk of management override of controls over financial reporting is increased and there are few effective methods to mitigate this risk.

6.	There was a strong reliance on contract accounting personnel and the external auditors to review and adjust the annual and quarterly financial statements, to monitor new accounting principles, and to ensure compliance with GAAP and SEC financial disclosure requirements. There was also a strong reliance on the external attorneys and contract financial reporting personnel to review and edit the annual and quarterly filings and to ensure compliance with SEC disclosure requirements. Reliance on these external resources may increase the risk that information about the company’s operations and financial transactions may not be identified and reported accurately in the financial statements.

In light of the material weaknesses described above, we performed additional analysis and other post-closing procedures to ensure our financial statements were prepared in accordance with generally accepted accounting principles. Accordingly, we believe that the financial statements included in this report fairly present, in all material respects, our financial condition, results of operations and cash flows for the periods presented.

In addition, although our controls are not effective, these material weaknesses did not result in any material misstatements in our financial statements. Our management is committed to improving our internal controls and (1) will continue to use third party specialists to address shortfalls in staffing and to assist us with accounting and financial reporting responsibilities, (2) will increase the frequency of independent reconciliations of significant accounts to mitigate the lack of segregation of duties until there are sufficient personnel, and (3) anticipates establishing an audit committee in the future.

Changes in internal control over financial reporting

Other than the weaknesses identified above, there were no changes in our internal control over financial reporting during the year ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

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.

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)
Thomas Lapinski	68	Chief Executive Officer, Interim Principal Financial Officer and Director
John A. Brda	48	President, Secretary and Director
Kenneth I. Danneberg	85	Director
Wayne Turner	63	Director

Currently, Thomas Lapinski and John Brda are our only executive officers. We presently rely on the assistance of outside advisors and consultants to supplement our management. At such time as adequate funding is available, we anticipate adding additional executive officers, including a Chief Financial Officer. Further, additional staff will be added as projects become successful and the company’s operations grow.

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

Thomas Lapinski – Mr. Lapinski has served as our Chief Executive Officer, Interim Principal Financial Officer and director since November 2010. He also previously served as our President from November 2010 to January 2012. He is the founder of Torchlight Energy, Inc., our wholly owned subsidiary, and has served as its Chief Executive Officer, President and director since its incorporation in June 2010. From 2002 to the present, he has engaged in consulting work on evaluating exploration, acquisition and re-development opportunities in the Rocky Mountain Region, Texas Gulf Coast, Mid-Continent, the Middle East, and South America. From September 1996 to June 2002, Mr. Lapinski served as President of Stephens Energy International of The Stephens Group, LLC. While there, he was involved in oil and gas exploration and production project development. Prior to that, he spent over 30 years in senior positions with Amoco Corporation before retiring. His expertise is in project evaluations, operations management and strategic planning with experience throughout the Rocky Mountain region, Alaska, U.S. mid-continent, the U.S. Gulf Coast and international arenas. With Amoco, he has held numerous positions, including Division Geophysicist for Rocky Mountain Area, Regional Geophysicist for Africa and the Middle East, Exploration Manager for North and West Africa, President-Amoco Morocco, President-Amoco Turkey, General Manager-Amoco Kenya, Exploration Manager Gulf Coast, Regional Exploration Manager for Southern and Eastern U.S. and Manager for Resource and Business Development in Southern Rocky Mountain Area. He also spent time on a special project for the Chairman of Amoco on key strategic planning issues where he was responsible for long-term monetization of Amoco’s North American asset base. Mr. Lapinski received a degree in Geophysical Engineering from the Colorado School of Mines in 1966.

We appointed Mr. Lapinski as an executive officer and a member of the Board of Directors based on his knowledge and experience in the oil and gas industry. His ability to identify and evaluate opportunities is an important part of our continued success.

John A. Brda – Mr. Brda has been 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 provides 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.

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.

Involvement in certain legal proceedings. In November 2007, Mr. Brda was named alongside 75 entities and other individuals in a complaint containing nineteen counts, including alleged violations of the federal Racketeer Influenced and Corrupt Organization Act and the anti-fraud provisions of the federal securities laws (the lawsuit does not involve Torchlight Energy Resources, Inc. in any way). Several months later, Mr. Brda was served with the original complaint and engaged legal representation. Based on Mr. Brda’s minimal connection to the investments at issue in the complaint, he instructed his attorney to contact plaintiffs’ counsel and try to negotiate a prompt resolution of the case and dismissal of the claims against him. His attorney contacted plaintiffs’ counsel and thereafter told Mr. Brda that the claims against him had been resolved when – in fact – they had not. Unknown to Mr. Brda, he remained a defendant in the suit, and in part because no answer was filed on his behalf, and in part because he was never served with any of the relevant papers after the original complaint, the court entered a default judgment against him in September 2012. Mr. Brda received no actual notice of any kind regarding the continued existence of any claims against him, any entry of default, any motion or hearing for default judgment, or the default judgment itself, until March 2013. He promptly retained legal counsel who filed a motion to vacate the default judgment on April 11, 2013, which motion is now pending. A motion for leave to file an answer to plaintiffs’ first amended complaint was also filed on that date. Discussions with plaintiffs’ counsel for the possible resolution of this matter are ongoing. Mr. Brda contends that all claims against him in the litigation are without merit, and that the court should dismiss the counts against him.

Kenneth I. Danneberg – Mr. Danneberg has been a member of the Board of Directors since June 2011. He brings to the company over 45 years of experience covering all aspects of oil and gas exploration and operation in the United States and Canada and is a member of the Rocky Mountain Oil and Gas Hall of Fame. For the past 15 years he has been the President and CEO of Danneberg Oil Inc., a company engaged in the drilling and production of oil and gas wells. Several career highlights are listed below:

Founder of Zoller and Danneberg, Inc which later became Premier Resources, Ltd.

Served as CEO of Premier Resources, Ltd, an AMEX listed company, conducting oil and gas operations in the U.S. and Canada

Drilling projects resulted in 22 field discoveries and averaged over 20 drilling projects per year

Extensive domestic and international drilling experience

Previously served on the boards of the following companies:

Alco Oil & Gas (predecessor to Ladd Petroleum a GE Subsidiary)

Premier Resources, Ltd

Zoller & Danneberg

International Bank of Denver

Great Horn, Inc.

We appointed Ken Danneberg to our Board because he brings a tremendous depth of knowledge and professional contacts in the oil and gas industry.

Wayne Turner – Mr. Turner has served as one of our directors since March 2011. He is presently the Managing Partner of JEBCO Seismic, LP, a position he has held since 1989, and is the Managing Partner of Big Thicket Oil & Gas, L.P., a position he has held since 2001. Mr. Turner took over management of JEBCO in 1989, when he acquired an ownership interest in the company. JEBCO is an independent international geophysical data acquisition contractor. Jebco’s non-exclusive surveys and third party datasets represent a unique and readily available source of information for both mature and frontier regions. JEBCO has operated both offshore and onshore in Canada and the U.S. JEBCO has also conducted surveys in the North Sea, Africa, Asia, and South America. One of JEBCO’s most significant accomplishments was signing an agreement with the Ministry of Geology in the USSR in 1989. The company was active in Russia, Kazakhstan, Uzbekistan, and Azerbaijan before and after the break-up of the USSR. The company has provided oil and gas exploration information to the industry, assisted in license rounds, and assisted in direct negotiations for oil and gas properties in these countries. Mr. Turner spent significant time in these countries and personally negotiated the major contract agreements involved.

Mr. Turner started Big Thicket Oil & Gas, L.P. in 2001. This company is active in oil and gas exploration in Texas, Louisiana, Oklahoma, and New Mexico. Most of the activity is through partnerships, which allows the company to remain small in staff, but have access to expertise in different areas. Big Thicket does not operate wells, but is involved in generating and evaluating prospects. Mr. Turner graduated in 1971 from the University of Houston with a degree in Electrical Engineering. He is active in various charitable organizations including the Houston Livestock Show and Rodeo and Houston Children’s Charities.

Wayne Turner’s expertise in the oil and gas industry makes him an excellent fit to the Board of Directors. In particular, we believe his experience in geophysical data acquisition is a valuable asset to the company.

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, 2012, 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, 2012, with the exception of a Form 4 that our director, Wayne Turner, was two days late in filing.

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 was filed as Exhibit 14.1 to our S-1 Registration Statement filed with the SEC on May 2, 2008. 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., 2007 Enterprise Avenue, League City, Texas 77573.

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.

Audit Committee

The Board of Directors has not yet established a separately-designated standing audit committee, and accordingly, the entire Board is currently acting as our audit committee. None of the members of our Board of Directors is deemed an audit committee financial expert. At some point in the future, we anticipate adding an audit committee financial expert to the Board, but we have not yet identified an ideal candidate.

ITEM 11. EXECUTIVE COMPENSATION

The following table provides summary information for the years 2012 and 2011 concerning cash and non-cash compensation paid or accrued to or on behalf of certain executive officers.

Summary Executive Compensation Table



Name and Principal Position	Year	Salary ($)	Bonus ($)	Stock Awards ($)	Option Awards ($)	Non-Equity Incentive Plan Compensation ($)	Change in Pension Value and Nonqualified Deferred Compensation ($)	All Other Compensation ($)	Total ($)
Thomas Lapinski CEO and Director (1)	2012 2011	$240,000(2) $240,000(2)	- -	- -	- -	- -	- -	- -	$240,000 $240,000

John Brda President and Director (1)	2012 2011	$240,000(3) $ -	- -	- -	- -	- -	- -	- -	$240,000 $ -

(1) See “Employment Agreements,” below for discussion of Mr. Lapinski’s and Mr. Brda’s compensation arrangements.

(2) For the year ended December 31, 2011, $60,000 of Mr. Lapinski’s compensation was paid in cash, while remaining $180,000 was accrued and remains unpaid. For the year ended December 31, 2012, the entire amount of $240,000 was accrued and remains unpaid.

(3) For the year ended December 31, 2012, the entire amount of Mr. Brda’s compensation was accrued and remains unpaid.

Employment Agreements

In July 2010, Torchlight Energy, Inc., our wholly owned subsidiary (“TEI”), entered into an employment agreement with Opal Marketing and Consulting, Inc. (“Opal”). Our Chief Executive Officer and director, Thomas Lapinski, owns and is the President of Opal. The agreement states that Opal will provide the services of Mr. Lapinski to serve as the company’s CEO and Chairman of the Board of Directors. The agreement had an original term of two years and has been extended by mutual agreement through June 30, 2013. The agreement provides that TEI is to pay Opal a base fee equal to $240,000 per year, payable monthly. Further, Mr. Lapinski is eligible to receive stock options and an additional annual bonus as determined by the Board of Directors in its sole discretion in an amount not to exceed 100% of the base fee.

In January 2012 we appointed John A. Brda as President and a director. We entered into an Employment Agreement with Mr. Brda that provides that Mr. Brda will serve as President and Secretary for a term of two years and will receive annual compensation of $240,000 in addition to any performance bonuses the Board may choose to grant at its discretion.

Outstanding Equity Awards at Fiscal Year End

We do not have any unexercised options, stock that has not vested or equity incentive plan awards for any of our executive officers or directors outstanding as of the end of our fiscal year ended December 31, 2012.

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 special assignments. We did not provide compensation to any members of the Board of Directors for their service on the Board for the year ended December 31, 2012.

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.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information at March 15, 2013 with respect to the beneficial ownership of shares of common stock by (i) each person known to us who owns beneficially more than 5% of the outstanding shares of common stock (based upon reports which have been filed and other information known to us), (ii) each of our directors, (iii) each of our executive officers and (v) all of our executive officers and directors as a group. Unless otherwise indicated, each stockholder has sole voting and investment power with respect to the shares shown. As of March 15, 2013, there were 13,659,815 shares of common stock outstanding.


Name and address of beneficial owner	Amount of beneficial ownership	Percent of class

Thomas Lapinski	3,000,000 shares	21.96%
Chief Executive Officer and Director
2007 Enterprise Avenue
League City, Texas 77573

John A. Brda	2,512,500 shares (1)	18.39%
President, Secretary and Director
1425 Frontenay
Warson Woods, Missouri 63122

Kenneth I. Danneberg	25,000 shares	0.18%
Director
4505 South Yosemite #379
Denver, Colorado 80237

Wayne Turner	25,000 shares	0.18%
Director
2450 Fondren, Suite 112
Houston, Texas 77063

All directors and executive officers as a group (4 persons)	5,562,500 shares	40.72%

Ken Dulin	1,308,571 shares (2)	8.74%
8449 Greenwood Drive
Niwot, Colorado, 80503


	(1)	Includes 182,500 shares held individually by John A. Brda and 2,330,000 shares held by Brda & Company LLC, of which Mr. Brda is the sole owner and Managing Director.
	(2)	Includes a total of 435,000 shares of common stock and a total of 873,571 currently exercisable warrants to purchase stock held by entities controlled by Mr. Dulin (Black Hills Properties, LLLP, Pine River Ranch, LLC and Sawtooth Properties, LLLP).

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Since inception, our Chief Executive Officer has charged us a management fee for his services through an entity that he controls, Opal Marketing & Consulting, Inc., in the amount of $240,000 per year. As a result of limited cash flow, payments under this arrangement have been deferred since April 1, 2011. Accordingly, we had a related party payable of $420,000 and $180,000 as of December 31, 2012 and 2011, respectively. Cash payments under this arrangement have totaled $180,000 since our inception on June 25, 2010.

In February and March of 2012, we issued three non-interest bearing promissory notes totaling $59,000 our Chief Executive Officer for cash received. The first of these notes, totaling $8,000, was repaid in November 2012. The balance of $51,000 is reflected in notes payable to related parties and is due on demand. Subsequent to December 31, 2012, we repaid both remaining notes in the amount of $51,000.

Director Independence

Currently two of our four directors are independent. Our independent directors are Kenneth Danneberg, and Wayne Turner. The definition of “independent” used herein is based on the independence standards of The NASDAQ Stock Market LLC, which is one of several exchanges and regulatory bodies that maintain such standards. The Board performed a review to determine the independence of Kenneth Danneberg and Wayne Turner 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 & Wagner, our independent registered public accountants, during the years ended December 31, 2012 and 2011.



	2012		2011
Audit Fees⁽¹⁾	$	68,640	$	29,000
Audit Related Fees⁽²⁾		1,000		11,477
Tax Fees⁽³⁾		4,491		780
All Other Fees		-		-

Total Fees	$	74,131	$	41,257


⁽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.

Pre-Approval of Audit and Non-Audit Services

We do not have a standing audit committee of the board of directors. Therefore, for the fiscal years ended December 31, 2012 and 2011, all audit services, audit-related services and tax services, as described above, were provided to us by Calvetti, Ferguson & Wagner based upon prior approval of the Board of Directors.

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		Amended and Restated Bylaws (Incorporated by reference from Form 8-K filed with the SEC on January 12, 2011.) *

10.1		Employment Agreement between Thomas Lapinski and Torchlight Energy, Inc. (Incorporated by reference from Form 8-K filed with the SEC on November 24, 2010.) *

10.2		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) *

10.3		Employment Agreement with John A. Brda (Incorporated by reference from Form 8-K filed with the SEC on January 24, 2012.) *

14.1		Code of Ethics (Incorporated by reference from Form S-1 filed with the SEC on May 2, 2008.) *

21.1		Subsidiaries. (Incorporated by reference from Form 8-K filed with the SEC on November 24, 2010) *

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 pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and Section 1350 of 18 U.S.C. 63.

32.2		Certification of 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 Netherland, Sewell & Associates, 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

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/ Thomas Lapinski
	By: Thomas Lapinski
	Chief Executive Officer

Date:	April 16, 2013

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/ Thomas Lapinski
Thomas Lapinski	Director, Chief Executive Officer, Principal Financial Officer and Principal Accounting Officer	April 16, 2013

/s/ John A. Brda		April 16, 2013
John A. Brda	Director, President and Secretary

/s/ Kenneth I. Danneberg
Kenneth I. Danneberg	Director	April 16, 2013

/s/ Wayne Turner
Wayne Turner	Director	April 16, 2013

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