June 30, 2013 10-Q

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

FORM 10-Q
(Mark One)

X . Quarterly report under Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Quarter Ended June 30, 2013.

. 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.
(Name of registrant in its charter)


Nevada	74-3237581
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)

5700 West Plano Pkwy, Suite 3600

Plano, Texas 75093
(Address of Principal Executive Offices)

(214) 432-8002
(Issuer'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 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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes X . No .

Indicate by check mark 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 . 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 .

As of August 14, 2013, there were 13,779,815 shares of the registrant’s common stock outstanding (the only class of voting common stock).

FORM 10-Q

TABLE OF CONTENTS


PART I	FINANCIAL INFORMATION	3

Item 1.	Consolidated Financial Statements	3

	Consolidated Condensed Balance Sheets (Unaudited)	3

	Consolidated Condensed Statements of Operations (Unaudited)	4

	Consolidated Condensed Statements of Cash Flows (Unaudited)	5

	Notes to Consolidated Condensed Financial Statements (Unaudited)	6

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	13

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	18

Item 4.	Controls and Procedures	18

PART II	OTHER INFORMATION	19

Item 1.	Legal Proceedings	19

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	19

Item 5.	Other Information	19

Item 6.	Exhibits	20

	Signatures	20

PART I FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS


TORCHLIGHT ENERGY RESOURCES, INC.
CONSOLIDATED CONDENSED BALANCE SHEETS
				June 30,		December 31,
				2013		2012
				(Unaudited)		(Audited)
ASSETS

Current assets:
	Cash		$	784,247	$	63,252
	Accounts and Note receivable			1,120,053		92,897
	Prepaid costs			36,574		8,346
		Total current assets		1,940,874		164,495

Investment in oil and gas properties, net				7,838,528		3,461,686
Debt issuance costs, net				1,123,574		473,785
Goodwill				447,084		447,084

		TOTAL ASSETS	$	11,350,060	$	4,547,050

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
	Accounts payable		$	1,388,542	$	89,247
	Accrued liabilities			80,893		62,055
	Related party payables			788,500		768,648
	Notes payable to related party			-		51,000
	Advances from working interest owners			325,000		-
	Interest payable			150,503		10,581
		Total current liabilities		2,733,438		981,531

Convertible promissory notes, net of discount of $2,640,523 and $521,864 at June 30, 2013 and December 31, 2012, respectively				4,503,777		580,636
Asset retirement obligation				13,306		12,614

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; 13,779,815 issued and outstanding at June 30, 2013 13,564,815 issued and outstanding at December 31, 2012			13,780		13,565
	Additional paid-in capital			11,428,340		8,381,001
	Warrants outstanding			1,046,000		-
	Accumulated deficit			(8,388,581)		(5,422,297)
		Total stockholders' equity		4,099,539		2,972,269

		TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	11,350,060	$	4,547,050

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

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


TORCHLIGHT ENERGY RESOURCES, INC.
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOW

					SIX MONTHS		SIX MONTHS
					ENDING		ENDING
					June 30, 2013		June 30, 2012
					(Unaudited)		(Unaudited)
Cash Flows From Operating Activities
	Net loss			$	(2,966,285)	$	(1,550,306)
	Adjustments to reconcile net loss to net cash from operating activities:
		Stock based compensation			1,352,005		1,106,452
		Accretion expense			574,895		62,760
		Depreciation, depletion and amortization			354,584		541
		Change in:
			Accounts and note receivable		(37,156)		(57,297)
			Prepaid expenses		(28,228)		(4,257)
			Debt issuance costs		(601,101)		-
			Accounts payable and accrued liabilities		(166,439)		153,327
			Accounts payable - related party		19,852		161,250
			Interest payable		107,587		36,273
Net cash provided (used) in operating activities					(1,390,286)		(91,257)

Cash Flows From Investing Activities
	Investment in oil and gas properties, net				(3,879,519)		(640,573)

Cash Flows From Financing Activities
	Issuance of promissory notes, net				6,041,800		214,000
	Payment of promissory notes				(51,000)		-
Net cash provided by financing activities					5,990,800		214,000

Net increase (decrease) in cash					720,995		(517,830)

Cash - beginning of period					63,252		518,281

Cash - end of period				$	784,247	$	451

Supplemental disclosure of cash flow information:
	Non cash transactions:
		Common stock issued in connection with promissory notes		$	-	$	67,725
		Warrants issued in connection with promissory notes		$	914,449	$	45,076
		Beneficial conversion feature on promissory notes		$	1,827,100	$	-
		Liabilities assumed in purchase of oil and gas properties		$	1,809,572	$	-
		Sale of oil and gas properties in exchange for note receivable		$	990,000	$	-
		Capitalized interest cost		$	32,335	$	-
		Reclassification of paid in capital to common stock		$	-	$	9,837
	Interest paid			$	26,665	$	-

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

NATURE OF BUSINESS

Torchlight Energy Resources, Inc. was incorporated in October 2007 under the laws of the State of Nevada as Pole Perfect Studios, Inc. (“PPS”). From its incorporation to November 2010, the company was primarily engaged in business start-up activities.

On November 23, 2010, we entered into and closed a Share Exchange Agreement (the “Exchange Agreement”) between the major shareholders of PPS and the shareholders of Torchlight Energy, Inc (“TEI”). 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.

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.

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

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

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

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 June 30, 2013, the Company had not yet achieved profitable operations, had accumulated losses of $8,388,581 since its inception and expects to incur further losses in the development of its business, which 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.

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. These interim period unaudited financial statements should be read in conjunction with the audited financial statements and footnotes which are included as part of the Company’s Form 10-K for the year ended December 31, 2012. Accounting principles followed and the methods of applying those principles, which materially affect the determination of financial position, results of operations and cash flows are summarized below:

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

Basis of presentation—The financial statements are presented on a consolidated basis and include all of the accounts of Torchlight Energy Resources Inc. and its wholly owned 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 re-measurement to fair value the Company categorizes them in a three-level fair value hierarchy as follows:

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

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

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

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

Accounts receivable – Accounts receivable consist of uncollateralized oil and natural gas revenues due under normal trade terms, as well as amounts due from working interest owners of oil and gas properties for their share of expenses paid on their behalf by the Company. Management reviews receivables periodically and reduces the carrying amount by a valuation allowance that reflects management’s best estimate of the amount that may not be collectible. As of June 30, 2013 and December 31, 2012 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.

Capitalized interest - The Company capitalizes interest on unevaluated properties during the periods in which they are excluded from costs being depleted or amortized. During six months ended June 30, 2013, the Company capitalized $32,335 of interest on unevaluated properties.

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

Ceiling test – Future production volumes from oil and gas properties are a significant factor in determining the full cost ceiling limitation of capitalized costs. Under the full cost method of accounting, the Company is required to periodically perform a “ceiling test” that determines a limit on the book value of oil and gas properties. If the net capitalized cost of proved oil and gas properties, net of related deferred income taxes, plus the cost of unproved oil and gas properties, exceeds the present value of estimated future net cash flows discounted at 10 percent, net of related tax affects, plus the cost of unproved oil and gas properties, the excess is charged to expense and reflected as additional accumulated DD&A. The ceiling test calculation uses a commodity price assumption which is based on the unweighted arithmetic average of the price on the first day of each month for each month within the prior 12 month period and excludes future cash outflows related to estimated abandonment costs. The Company did not recognize impairment on its oil and gas properties during the quarter ended June 30, 2013, 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 June 30, 2013 and December 31, 2012, 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.

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 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. 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.

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

Subsequent events – The Company evaluated subsequent events through August 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.

RELATED PARTY PAYABLES

As of June 30, 2013, related party payables consisted of accrued and unpaid compensation to our two executive officers totaling $715,000 and compensation to directors payable in common stock with a total value of $73,500. The Company has agreed to issue 25,000 common shares to each of its two outside directors for services rendered in 2012. The Company accrued $73,500 in compensation expense related to the issuance of these shares. The balance at June 30, 2013 also consisted entirely of accrued compensation and travel expenses due to our executive officers and directors.

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 June 30, 2013 and December 31, 2012, 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.

STOCKHOLDERS’ EQUITY

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. As of June 30, 2013 there were no issued and outstanding shares of preferred stock and there were no agreements or understandings for the issuance of preferred stock.

During the quarter ended June 30, 2013, the Company issued 120,000 shares of common stock as compensation for services, with a total value of $175,000. Of this amount, $175,000 had been accrued during the quarter ended March 31, 2013.

During the quarter ended June 30, 2013, the Company issued 721,014 warrants in connection with financing transactions discussed in Note 9, including 240,345 warrants issued to the placement agent, and 1,200,000 warrants for consulting services to the Company.

A summary of warrants outstanding as of June 30, 2013 by exercise price and year of expiration is presented below:


Exercise	Expiration Date in
Price	2014	2015	2016	2017	2018	Total

$ 1.75	80,000	855,000	1,235,714	-	-	2,170,714
$ 2.00	-	-	775,259	126,000	690,798	1,592,057
$ 2.14					1,000,000	1,000,000
$ 2.50	225,000	50,000	-	-	-	275,000
$ 5.00	771,212	-	-	-	-	771,212
	1,076,212	905,000	2,010,973	126,000	1,690,798	5,808,983

At June 30, 2013 the Company had reserved 5,808,983 shares for future exercise of warrants.

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


Risk-free interest rate	0.78%
Expected volatility of common stock	102%
Dividend yield	0.00%
Discount due to lack of marketability	30.00%
Expected life of warrant	3 years - 5 years

CAPITALIZED COSTS

The following table presents the capitalized costs of the Company as of June 30, 2013 and December 31, 2012:


			2013		2012


Evaluated costs subject to amortization		$	8,136,000	$	3,435,918
Unevaluated costs			609,001		577,658
	Total capitalized costs		8,745,001		4,013,576
Less accumulated depreciation, depletion and amortization			(906,473)		(551,890)
	Net capitalized costs	$	7,838,528	$	3,461,686

Unevaluated costs as of June 30, 2013 consisted of $609,001 associated with the Company’s interest in the Coulter #1 well. The Coulter #1 wells is undergoing production and test operations with the goal of removing sufficient water from the wellbore to allow production of natural gas. The unevaluated costs as of December 31, 2012 consisted entirely of the Company’s interest in the Coulter #1 well.

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

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. The Company has placed a 100% valuation allowance against the net deferred tax asset because future realization of these assets is not assured.

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

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

As of June 30, 2013, the Company had federal net operating loss carryforwards of approximately $7.1 million available to offset future taxable income, and has incurred additional taxable losses during 2013. These loss carryforwards will expire in various years through 2031, if not previously utilized. Utilization of these net operating loss carryforwards is dependent, in part, on generating sufficient taxable income prior to the expiration of such loss carryforwards. In addition, the Company’s ability to utilize its net operating loss carryforwards may be substantially limited or eliminated pursuant to Internal Revenue Code Section 382.

PROMISSORY NOTES

On December 18, 2012, the Company exchanged $412,500 of outstanding convertible promissory notes for new 12% Series A Secured Convertible Promissory Notes (12% Notes) described below. The 12% 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 previously outstanding convertible promissory notes 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 of December 31, 2012, as these costs relate to the larger offering of 12% Convertible Promissory Notes.

On December 18, 2012, the Company issued $690,000 of 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 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 of the Company’s common stock 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 issued. 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.

During the quarter ended June 30, 2013, the Company issued an additional $4,205,850 in principal value of 12% Notes. Such notes carry the same terms as described above. In connection therewith, the Company also issued a total of 480,669 five-year warrants to purchase common stock at an exercise price of $2.00 per share. The value of the warrant shares was $432,602 and the amount recorded for the beneficial conversion feature was $1,233,930. These amounts were recorded as a discount on the 12% Notes. In addition, the Company engaged a placement agent to source investors for the majority of these additional notes. This placement agent was paid a fee of 10% of the principal amount of the notes plus a non-accountable expense reimbursement of up to 2% of the principal raised by the agent. The placement agent also received 240,345 warrants to purchase common shares at $2.00 per share for a period of three years, valued at $187,469. All the amounts paid to the placement agent have been included in debt issuance costs and will be amortized into interest expense over the life of the 12% Notes.

The 12% Notes have a first priority lien on all of the assets of the Company. Additionally, the Company is required to set aside in a separate account, monthly, in arrears, an amount of funds equal to the (x) outstanding principal amount of each 12% Note divided by the total number of full calendar months after the date of issuance of that 12% Note until the maturity date, plus (y) the annual amount of simple interest to accrue on the outstanding principal amount of that 12% Note divided by 12. Such funds can be used for payment principal and interest on the notes. Scheduled sinking fund requirements on the 12% Notes are as follows:


Requirement as of June 30,2013	$	790,256

Projected requirement to June 30,2014	$	3,693,762

Projected requirement to March 15, 2015 Maturity	$	2,770,321

Total	$	7,254,339

As of June 30, 2013, there was a deficiency of $639,753 in the sinking fund account, after accounting for the quarterly interest payment that was timely made on interest due for that quarter. Subsequent to June 30, 2013, the Company placed $200,000 in the sinking fund account whereby the deficiency was reduced. The Company has had conversations with the agent for the holders of the 12% Notes and intends to remedy this deficiency by either modifying the notes or allocating additional funds to the sinking fund account.

10.

ASSET RETIREMENT OBLIGATIONS

The following is a reconciliation of the asset retirement obligation liability through June 30, 2013:


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, 2012		12,614
Adjustment to estimated liability		-
Accretion expense		346
Asset retirement obligation – March 31, 2013		12,960
Accretion expense		346
Asset retirement obligation – June 30, 2013	$	13,306

11.

SUBSEQUENT EVENTS

Subsequent to June 30, 2013, the Company issued an additional $1.45 million in 12% convertible promissory notes, with the same terms and maturity dates described in Note 9. The Company continued to sell 12% convertible promissory notes through July 31, 2013. Substantially all of these notes were sold through a placement agent and carried placement fees and debt issuance costs similar to those described in Note 9.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The information set forth and discussed in this Management’s Discussion and Analysis and Results of Operations is derived from our historical financial statements and the related notes thereto which are included in this Form 10-Q. The following information and discussion should be read in conjunction with such financial statements and notes. Additionally, this Management’s Discussion and Analysis and Plan of Operations contain certain statements that are not strictly historical and are “forward-looking” statements within the meaning of the Private Securities Litigation Reform Act of 1995 and involve a high degree of risk and uncertainty. Actual results may differ materially from those projected in the forward-looking statements due to other risks and uncertainties that exist in our operations, development efforts and business environment, and due to other risks and uncertainties relating to our ability to obtain additional capital in the future to fund our planned expansion, the demand for oil and natural gas, and other general economic factors. All forward-looking statements included herein are based on information available to us as of the date hereof, and we assume no obligation to update any such forward-looking statements.

Basis of Presentation of Financial Information

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

Summary of Key Results

Overview

Our sole business is that of Torchlight Energy, Inc., a company engaged in oil and gas acquisition and development, 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.

The following discussion of our financial condition and results of operations should be read in conjunction with our unaudited financial statements included herewith and our audited financial statements for the year ended December 31, 2012, included in Form 10-K. This discussion should not be construed to imply that the results discussed herein will necessarily continue into the future, or that any conclusion reached herein will necessarily be indicative of actual operating results in the future. Such discussion represents only the best present assessment by our management.

We had no active operations prior to the inception of TEI on June 25, 2010 and had limited revenues prior to the year ended December 31, 2012. Due to this fact, results from previous years may not present a relevant comparison to current operations.

Current Projects

We currently have interests in four oil and gas projects, the Marcelina Creek Field Development in Wilson County, Texas, the Coulter Field in Waller County, Texas, the Smokey Hills Prospect in McPherson County, Kansas and the Cimarron Area, Hunton play in Logan and Kingfisher Counties, Oklahoma.

Marcelina Creek Field Development.

On July 6, 2010, TEI entered into a participation agreement with Bayshore Operating Corporation, LLC (“Bayshore”), which is currently the holder of an oil, gas and mineral lease covering approximately 1,045 acres in Wilson County, Texas, known as the Marcelina Creek Field Development. The Participation Agreement provides for the drilling of four wells. Three of the obligation wells have been drilled. The first three wells include a horizontal re-entry well known as the Johnson-1-H, a vertical well known as the Johnson #4, and a lateral well known as the Johnson #2-H. All are presently producing. The remaining well is to be a vertical development well at a location 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 at 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. This well averaged gross production of approximately 40 BOPD during the quarter ended June 30, 2013.

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, another acid job is planned for the third quarter.

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, TEI was responsible for 100% of the total drilling costs and 100% of the completion costs, for a 75% working interest in the well. Drilling operations began the third week of May and the well was successfully completed at the end of June 2013. Subsequent to the quarter, the well is presently being tested with rates of 200 barrels of oil per day. Total estimated costs of the well, including contingent amounts for unexpected problems that may or may not be encountered in drilling operations, are $3.5 million. Actual well costs, including costs subsequent to the quarter, are $2.62 million.

If we 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 acquired a 34% working interest and a 25.5% net revenue interest from La Sal’s interest in the John Coulter #1-R for the purchase price of $350,000, which was to be applied to 100% of the costs of a fracture stimulation treatment on the well. Under the agreement, we had options to purchase additional working interests up to a total of 45%. We exercised the first option and purchased an additional 6% for $50,000, bringing our working interest to 40% and our net revenue interest to 30%. Our option to purchase an additional 5% working interest can be exercised by the payment of $50,000 within 30 days of first commercial production from the well. If commercial production is established, the net revenue split will be 80% to us and 20% to La Sal until net revenue totals $437,500, after which the net revenue will be split according to the interests in the well. Expenses above the initial $350,000 will be split according to the working interests in the well. Our total investment in the project, including fracture stimulation, subsequent testing, purchase of additional interests and capitalized interest, amounted to $609,001 as of June 30, 2013.

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

Smokey Hills Prospect, McPherson County, Kansas

The Smokey Hills acquisition included approximately 10,000 gross acres and a well, the Hoffman 1-H within the greater Lindsborg Field area. Our working interest is nearly 18%. Wells had been drilled vertically in the 1960’s to present at depths of less than 4,000 feet looking for production from Mississippian carbonated fractured reservoirs. The Hoffman well, which was drilled laterally 4,200 feet, had not been fracked. Core analysis and logs indicated good porosity at 14 to 22%. Following our acquisition, the well was hydraulically fractured, but the results were disappointing. We presently are evaluating our next efforts to monetize the investment of nearly $940,000. Allocated costs are high due to the large acreage position.

Cimarron Area Hunton Play, Logan and Kingfisher Counties, Oklahoma

The Xtreme transaction also included the acquisition of three Hunton wells, the Hancock, Robinson and Lenhart. The Hancock and Robinson are producing wells but have small working interests of 1% and ¼ of 1%, respectively. The Lenhart well is a 62% working interest and was being prepared for a fracture stimulation when it was previously damaged, prior to our acquisition, by the service contractor. The well bore at the Hunton level has an irretrievable pipe in the hole and cannot be used to produce from the Hunton. Although Xtreme won the litigation against the contractor, he failed to pay for the replacement of the well bore, and Xtreme was responsible for costs primarily to Baker-Hughes for work done on the well. We took responsibility for those charges and negotiated a settlement of approximately $600,000.

Subsequent to the above, we have identified a shallow sandstone that could potentially be productive and are planning on testing that zone in the third quarter. We are the operator of the well.

While doing the due diligence for the above projects, we met with the operator of the Hancock and Robinson well, Husky Ventures of Oklahoma City. At that time Husky had completed 17 successful wells in the Hunton formation and was expanding its acreage position. We were able to negotiate a 15% working interest in approximately 3,700 acres in the Cimarron Area of Logan County in May 2013. Within a week the Boeckman #1-H well was spud and was subsequently completed and fracture stimulated in July. At present the well is “unloading” but initial results are exceeding our expectations, and after only 14 days of returning the frac fluids injected, the well is making 275 barrels of oil per day and over 500 thousand cubic feet of gas per day. We and our partner plan on at least two more wells to be drilled in the Cimarron Area this year.

The Company acquired a working interest in the Boeckman #1-H well and subsequently sold part of its ownership in the Boeckman well for $990,000. The purchaser executed a promissory note dated May 1, 2013 for the purchase. The Company has collected $631,500 as of the date of these financial statements, and the purchaser has committed full payment within a few more days. The Company agreed to a preferential payout to the purchaser equal to 50% of his acquired interest.

Salt Water Disposal Facility

We also acquired, at no associated cost, a 22.5% net royalty on a salt water disposal facility in Seminole, Oklahoma. The facility which was newly commissioned in January 2013 is a state of the art disposal facility which can handle 20,000 barrels of produced and injected fluids per day. Oil and gas wells produce large quantities of saltwater that must be trucked and disposed of at a cost to the producer. During the second quarter, the facility averaged only approximately 2,000 barrels of fluids per day. But with increasing activity in the area, we anticipate that volume increasing in the future. With only a royalty, we have no working interest and are therefore not responsible for any operating expenses. We do however have the right to a working interest of 37.5% when the original investors in the facility receive a payout of their investment.

Historical Results for the Six Months Ended June 30, 2013 and 2012

Revenues and Cost of Revenues

For the six months ended June 30, 2013, we had revenue of $399,390 compared to $275,629 of revenue for the six months ended June 30, 2012. During the first half of 2013, production began a natural decline in both the Johnson #1-BH and the Johnson #4 wells. For the six months ended June 30, 2013 the wells produced an average of approximately 70 BOPD for the Johnson #1-BH and 35 BOPD for the Johnson #4. Our net volumes for the six months ended June 30, 2013 were 3,926 barrels at an average price of $99.36 per barrel. Our cost of revenue, consisting of lease operating expenses and production taxes, was $161,021 ($41.01 per barrel) and $263,745 for the six months ended June 30, 2013 and 2012, respectively.

We recorded depreciation, depletion and amortization expense of $354,584 ($90.31 per barrel) for the six months ended June 30, 2013.

General and Administrative Expenses

Our general and administrative expenses for the six months ended June 30, 2013 and 2012 were $2,114,651 and $1,450,959, 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 six months ended June 30, 2013 compared to the prior six months is primarily related to higher consulting costs and compensation incurred during the latter period as the Company has grown and increased operations.

Historical Results for the Three Months Ended June 30, 2013 and 2012

Revenues and Cost of Revenues

For the three months ended June 30, 2013, we had revenue of $170,186 compared to $251,412 of revenue for the three months ended June 30, 2012. During the first half of 2013, production began a natural decline in both the Johnson #1-BH and the Johnson #4 wells. In June 2013 the Company recognized the need to stimulate the Johnson #4 with another acid job and to work over the pumping unit on the Johnson #1-BH. Both procedures were done in early July, subsequently increasing production in the Johnson #1-BH to an un stabilized rate of 100 BOPD and 40 BOPD for the Johnson #4. Our net volumes for the three months ended June 30, 2013 were 1,672 barrels at an average price of $96.22 per barrel. Our cost of revenue, consisting of lease operating expenses and production taxes, was $93,021 ($55.63 per barrel) and $247,221 for the three months ended June 30, 2013 and 2012, respectively.

We recorded depreciation, depletion and amortization expense of $237,737 ($142.19 per barrel) for the three months ended June 30, 2013.

General and Administrative Expenses

Our general and administrative expenses for the three months ended June 30, 2013 and 2012 were $1,581,102 and $1,219,738, 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 three months ended June 30, 2013 compared to the prior year’s quarter is primarily related to higher consulting costs and compensation incurred during the latter period as the Company has grown and increased operations.

Liquidity and Capital Resources

As June 30, 2013, we had working capital of $(792,564), current assets of $1,940,874 consisting of cash, accounts receivable and prepaid expenses and total assets of $11,350,060 consisting of current assets, investments in oil and gas properties and goodwill. As of June 30, 2013, we had current liabilities of $2,733,438, consisting of the balance due on acquisition of properties of $1,120,023, accounts payable, payables to related parties, notes payable and accrued interest and stockholders’ equity was $4,099,539.

Cash flow used in operating activities for the six months ended June 30 2013, was $(1,390,286) compared to $(91,257) for the six months ended June 30, 2012. Cash flow used in operating activities during 2013 can be primarily attributed to net losses from operations, which consists primarily of general and administrative expenses, a substantial portion of which are non-cash in nature, offset by increases in accounts and note receivable and increases in accounts payable. We expect to continue to use cash flow in operating activities until such time as we achieve sufficient commercial oil and gas production to cover all of our cash costs.

Cash flow used in investing activities for six months ended June 30, 2013 was $3,879,519 compared to $640,573 for the six months ended June 30, 2012. Cash flow used in investing activities consists primarily of oil and gas investments in the Johnson wells in the Marcelina Creek Field and the Oklahoma properties acquired during the six months ended June 30, 2013.

Cash flow provided by financing activities for the six months ended June 30, 2013 was $5,990,800 as compared to $214,000 for the six months ended June 30, 2012. Cash flow provided by financing activities in 2013 consists of convertible promissory notes issued for cash, net of repayments of debt. 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 June 30, 2013, we received net proceeds of approximately $1.45 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 June 30, 2013 and December 31, 2012, no amounts have been recorded because no specific liability has been identified that is reasonably probable of requiring us to fund any future material amounts.

We currently have interests in three oil and gas projects, the Marcelina Creek Field Development in Wilson County, Texas, the Coulter Field in Waller County, Texas, and projects in Logan and Kingfisher counties, Oklahoma. See the description under “Current Projects” above for more information and disclosure regarding commitments and contingencies relating to these projects. During the three months ended June 30, 2013, the Company signed an Authority for Expenditure to drill the third well in the Marcelina Creek Field, the Johnson #2, and the drilling is substantially complete at June 30, 2013. Total estimated costs of the well, including contingent amounts for unexpected problems that may or may not be encountered in drilling operations, are approximately $3.5 million.

Additionally, we have undertaken certain financial obligations in connection with an agreement signed April 15, 2013 with Xtreme Oil and Gas, Inc. as described in Note 11, Subsequent Events, to the financial statements.

The Company is required to set aside in a separate account, monthly, in arrears, an amount of funds equal to the (x) outstanding principal amount of each 12% Note divided by the total number of full calendar months after the date of issuance of that 12% Note until the maturity date, plus (y) the annual amount of simple interest to accrue on the outstanding principal amount of that 12% Note divided by 12. Such funds can be used for payment principal and interest on the notes. Scheduled sinking fund requirements on the 12% Notes are as follows:


Requirement as of June 30,2013	$	790,256

Projected requirement to June 30,2014	$	3,693,762

Projected requirement to March 15, 2015 Maturity	$	2,770,321

Total	$	7,254,339

Going Concern

The accompanying unaudited 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 June 30, 2013, we had not yet achieved profitable operations and had accumulated losses of $8,388,581. 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 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not Applicable.

ITEM 4. 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 June 30, 2012. Based on this evaluation, our principal executive officer and our 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.

Our principal executive officer and principal financial officer have also indicated that, upon evaluation, there were no changes in our internal control over financial reporting or other factors during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

On February 16, 2012, we filed a lawsuit against Hockley Energy, Inc. and Frank O. Snortheim in the District Court of Harris County, Texas in connection with farmout agreements we entered into with Hockley Energy in November 2011 for the Marcelina Creek prospect and the East Stockdale prospect. We allege that Hockley Energy did not perform its obligations under the agreements, which obligations included providing the agreed upon funding, and we seek damages against both Hockley and Mr. Snortheim (who is a shareholder of Hockley Energy) for breach of contract, fraudulent inducement and promissory estoppel. Each defendant has answered our original petition with a general denial, and we have filed a motion for default judgment which is pending. 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 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

In April, 2013, we issued a total of 120,000 shares of restricted common stock to individuals as consideration for consulting services. 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 issuances of the securities were isolated private transactions; (ii) a limited number of securities were issued to a limited number of offerees; (iii) there was no public solicitation; (iv) the investment intent of the offerees; and (v) the restriction on transferability of the securities issued.

In April, 2013, we granted 1,000,000 warrants to purchase shares of common stock to Willard G. McAndrew, III as consideration under his consulting agreement. The warrants have an exercise price of $2.09 and a term of five years. Additional warrants are issuable to Mr. McAndrew if and when the Company’s net production reaches specified levels. The valuation of those future warrants computed under the Black Scholes Model as if they were all issued at June 30, 2013 is $1,335,000. 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 issuances of the securities were isolated private transactions; (ii) a limited number of securities were issued to a limited number of offerees; (iii) there was no public solicitation; (iv) the investment intent of the offerees; and (v) the restriction on transferability of the securities issued.

In May, 2013, we granted 200,000 warrants to purchase shares of common stock to an individual as consideration for consulting services. The warrants have an exercise price of $2.00 and 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 issuances of the securities were isolated private transactions; (ii) a limited number of securities were issued to a limited number of offerees; (iii) there was no public solicitation; (iv) the investment intent of the offerees; and (v) the restriction on transferability of the securities issued.

ITEM 5. OTHER INFORMATION

Other Events - In Item 10 of our Form 10-K for the year ended December 31, 2012, we disclosed information regarding a lawsuit brought against John Brda, our President, in November 2007 (the lawsuit does not involve Torchlight Energy Resources, Inc. in any way). As of August 2013, the court has vacated the default judgment against Mr. Brda and dismissed all claims against him, in connection with a settlement.

ITEM 6. 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.) *

10.4		Purchase and Sale Agreement between Torchlight Energy, Inc. and Xtreme Oil and Gas, Inc. effective April 1, 2013. (Incorporated by reference from Form 10-Q filed with the SEC on May 15, 2013.) *

31.1		Certification of principal executive officer required by Rule 13a – 14(1) or Rule 15d – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of principal financial officer required by Rule 13a – 14(1) or Rule 15d – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of principal executive officer and principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and Section 1350 of 18 U.S.C. 63.

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 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.

Date: August 16, 2013	/s/ Thomas Lapinski
	By: Thomas Lapinski
	Chief Executive Officer and Principal Financial Officer


TORCHLIGHT ENERGY RESOURCES, INC.
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

				THREE MONTHS		THREE MONTHS		SIX MONTHS		SIX MONTHS
				ENDING		ENDING		ENDING		ENDING
				JUNE 30, 2013		JUNE 30, 2012		JUNE 30, 2013		JUNE 30, 2012
				(Unaudited)		(Unaudited)		(Unaudited)		(Unaudited)
Revenue:
	Oil and gas sales		$	160,882	$	251,412	$	390,086	$	275,629
	Royalty			9,304		-		9,304		-

Cost of revenue				(93,021)		(247,221)		(161,021)		(263,745)

Gross income				77,165		4,191		238,369		11,884

Operating expenses:
	General and administrative expenses			1,581,102		1,219,738		2,114,651		1,450,959
	Depreciation, depletion and amortization			237,737		-		354,584		-
		Total operating expenses		1,818,839		1,219,738		2,469,235		1,450,959

Other income (expense)
	Interest income			40		-		40		12
	Interest expense			(566,458)		(49,597)		(735,459)		(111,243)
		Total other income (expense)		(566,418)		(49,597)		(735,419)		(111,231)

Net (loss) before taxes				(2,308,092)		(1,265,144)		(2,966,285)		(1,550,306)

Provision for income taxes				-		-		-		-

Net (loss)			$	(2,308,092)	$	(1,265,144)	$	(2,966,285)	$	(1,550,306)

Loss per share: Basic and Diluted			$	(0.168)	$	(0.085)	$	(0.218)	$	(0.104)

Weighted average shares outstanding: Basic and Diluted				13,758,277		14,928,277		13,614,318		14,845,202