NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

1. NATURE OF BUSINESS

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

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

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

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

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

 

 

3. SIGNIFICANT ACCOUNTING POLICIES

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

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

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

 

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

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

 

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

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

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

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

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

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

Accounts receivable and Production revenue 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 September 30, 2015 and December 31, 2014 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.

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

3. SIGNIFICANT ACCOUNTING POLICIES - continued

 

Capitalized interest – The Company capitalizes interest on unevaluated properties during the periods in which they are excluded from costs being depleted or amortized.  During the nine months ended September 30, 2015 and the year ended December 31, 2014, the Company capitalized $577,576 and $371,116, respectively, of interest on unevaluated properties.

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

 

Ceiling test – Future production volumes from oil and gas properties are a significant factor in determining the full cost ceiling limitation of capitalized costs. Under the full cost method of accounting, the Company is required to periodically perform a “ceiling test” that determines a limit on the book value of oil and gas properties. If the net capitalized cost of proved oil and gas properties, net of related deferred income taxes, plus the cost of unproved oil and gas properties, exceeds the present value of estimated future net cash flows discounted at 10 percent, net of related tax affects, plus the cost of unproved oil and gas properties, the excess is charged to expense and reflected as additional accumulated DD&A. The ceiling test calculation uses a commodity price assumption which is based on the unweighted arithmetic average of the price on the first day of each month for each month within the prior 12 month period and excludes future cash outflows related to estimated abandonment costs. The Company recognized impairment of $22,438,114 on its oil and gas properties during the three months ended June 30, 2015. No impairment was recognized at September 30, 2015 or at December 31, 2014. Due to the volatility of commodity prices, should oil and natural gas prices decline in the future, it is possible that an additional 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 toproved 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.

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

3. SIGNIFICANT ACCOUNTING POLICIES - continued

 

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

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

Recent accounting pronouncements –

 

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

 

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

 

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

 

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

 

4. RELATED PARTY PAYABLES

As of September 30, 2015, related party payables consisted of accrued and unpaid compensation to two of our executive officers totaling $90,000.

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 September 30, 2015, 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. STOCKHOLDERS’ EQUITY

 

 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

6. STOCKHOLDERS’ EQUITY - continued

 

On June 9, 2015, under a Securities Purchase Agreement, we sold to certain accredited investors an aggregate of $9,800,000 in shares of Series A Convertible Preferred Stock, amounting to a total of 98,000 shares of the Series A Convertible Preferred Stock at a purchase price of $100 per share.  The designations, preferences, limitations, restrictions and relative rights of the Series A Convertible Preferred Stock are as follows: (i) a stated value of $100 per share; (ii) mandatory conversion one year after issuance (provided no insolvency event has occurred and subject to the restriction described in the following clause “(iv)”), with each holder having the right to convert at its election any time before that; (iii) a conversion price of $1.15 per shares of common stock; (iv) until stockholder approval is obtained, holders may not convert (and there shall not be any mandatory conversion) if such conversion will result in such holder beneficially owning in excess of 19.9% of our common stock; (v) a dividend in an annual amount equal to 12% on the outstanding stated value of each share payable in common stock or cash at the holder’s election; (vi) each holder shall be entitled to the number of votes equal to the number of shares of common stock into which such shares of Series A Convertible Preferred Stock could be converted; (vii) in the event of any voluntary or involuntary liquidation, dissolution or winding up, the holders will be entitled to be paid out of the assets available for distribution to our stockholders, before any payment is be made to the holders of common stock; and (viii) the holders will have the right to participate in up to 100%, in the aggregate, on a pro-rata basis, of any subsequent private placement offerings by us of our equity securities, on identical terms and conditions as set forth in such subsequent offering for so long as the holder owns the Series A Convertible Preferred Stock.

 

The preferred investors were provided 20% warrant coverage. A total of 1,704,346 warrants were issued with a five-year term and an exercise price of $1.40 per share of common stock. The warrants also provide that, until stockholder approval is obtained, holders may not exercise if such exercise will result in such holder beneficially owning in excess of 19.9% of our common stock.

 

At closing of the Securities Purchase Agreement, proceeds from the offering were used to pay off, in full, the holders of the 12% Series A Secured Convertible Promissory Notes (the “Senior Notes”), subject to the release of all liens and security interests.

On September 9, 2015, at our Annual Meeting of Stockholders, stockholders approved authorizing holders of Series A Preferred to convert preferred stock and exercise warrants received in connection therewith into a number of shares of common stock that would result in the holder beneficially owning in excess of 19.99% of our common stock.

On September 28, 2015, we sold a total of 37,000 shares of Series B Convertible Preferred Stock (the “Series B Preferred”) to certain investors at a purchase price of $100 per share for total consideration of $3,700,000 (the designation for the Series B Preferred is described below). Under the terms of the sale, we provided each investor 50% warrant coverage and accordingly issued the investors a total of 911,330 five-year warrants to purchase shares of our common stock at an exercise price of $2.23 per share. The warrants provide that holders may not exercise the warrant if such exercise will result in such holder beneficially owning in excess of 4.99% of our common stock. Additionally, under the terms of the transaction, we provided the investors registration rights under which a registration statement covering the shares of common stock underlying the Series B Preferred and warrants is to be filed within 30 days of closing.

This sale of Series B Preferred was effected through a Securities Purchase Agreement which was amended on September 23, 2015.  Under the amendment, the investors were provided the registration rights described above, the conversion price of the Series B Preferred was $2.03, the exercise price of the warrants was $2.23, and a blocker provision was added to the warrants whereby holders may not exercise if such exercise will result in the holder owning in excess of 4.99% of our common stock.

We filed the Certificate of Designation for the Series B Preferred with the Secretary of State of Nevada on September 25, 2015. The designations, preferences, limitations, restrictions and relative rights of the Series B Preferred are as follows: (i) a stated value of $100 per share; (ii) mandatory conversion one year after issuance, with each holder having the right to convert at its election any time before that; (iii) a conversion price of $2.03 per shares of common stock; (iv) a dividend in an annual amount equal to 12% on the outstanding stated value of each share payable in common stock or cash at the holder’s election; (v) each holder shall be entitled to the number of votes equal to the number of shares of common stock into which such shares of Series B Preferred could be converted; and (vi) in the event of any voluntary or involuntary liquidation, dissolution or winding up, the holders will be entitled to be paid out of the assets available for distribution to our stockholders, before any payment is made to the holders of common stock, but after the payment to the holders of Series A Convertible Preferred Stock.

The proceeds from the offering were used to reduce outstanding accounts payable and short term notes payable balances.

 

During the three months ended September 30, 2015 the Company issued 468,734 shares of common stock as compensation for services, with a total value of $783.668.

During the three months ended September 30, 2015 the Company issued 319,390 shares of common stock in payment of dividends payable on Series A Convertible Preferred Stock due on September 30, 2015. The total dividend value was $536.527. The dividend was payable in common stock with the number of shares determined by dividing the dividend payable amount by the conversion price on the preferred of $1.15. The dividend value was increased by $169.227 for accounting purposes to reflect the difference between the closing price of the common stock on September 30 of $1.68 and the $1.15 per share used to compute the number of shares required to pay the preferred dividend at September 30, 2015.

During the three months ended September 30, 2015 the Company issued 600,000 shares of common stock in conversion of a short term note payable, with a total value of $150,000.

 

 

 

At September 30, 2015 the Company had reserved 19,899,198 common shares for future exercise of warrants plus 8,521,739 common shares for future conversion of issued preferred stock.

 

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:

 

 

 

 

 

8. INCOME TAXES

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

 

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

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

 

The Company had a net deferred tax asset related to federal net operating loss carryforwards of $31,095,266 and $24,089,942 at September 30, 2015 and December 31, 2014, respectively.  The federal net operating loss carryforward will begin to expire in 2030.  Realization of the deferred tax asset is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards.  The Company has placed a 100% valuation allowance against the net deferred tax asset because future realization of these assets is not assured.

 

9. PROMISSORY NOTES

Series “A” Convertible Promissory Notes

 

The 12% Series “A” Secured Convertible Promissory  Notes total outstanding principal balance of $8,117,598 plus interest, was due in full at their maturity date of March 31, 2015.  On June 9, 2015, under a Securities Purchase Agreement, we sold to certain accredited investors an aggregate of $9,800,000 in shares of Series A Convertible Preferred Stock. Proceeds from the offering were used to pay off, in full, the holders of the 12% Series A Secured Convertible Promissory Notes (the “Senior Notes”), and all liens and security interests previously held by the Series “A” Convertible Note Holders were released.

 

Series “B” Convertible Subordinated Promissory Notes

 

During the quarter ended June 30, 2014, the Company issued $3,197,500 in principal value of 12% Series B Convertible Unsecured Promissory Notes. The Series B Notes due and payable on June 30, 2017, provide for conversion into common stock at a price of $4.50 per share and included the issuance of one warrant for each $22.50 of principal amount purchased.  The Company issued a total of 142,111 of these five-year warrants to purchase common stock at an exercise price of $6.00 per share.  The value of the warrant shares was $405,016 and the amount recorded for the beneficial conversion feature was $195,466.  These amounts were recorded as a discount on the Series B Notes.

 

 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

9. PROMISSORY NOTES - continued

 

During the quarter ended September 30, 2014, the Company issued an additional $1,372,000 in principal value of Series B Convertible Unsecured Promissory Notes. The Series B Notes due and payable on June 30, 2017, provide for conversion into common stock at a price of $4.50 per share and included the issuance of one warrant for each $22.50 of principal amount purchased.  The Company issued a total of 60,974 of these five-year warrants to purchase common stock at an exercise price of $6.00 per share.  The value of the warrant shares was $157,388 and the amount recorded for the beneficial conversion feature was $-0-.  These amounts were recorded as a discount on the Series B Notes. The Company previously offered a reset of the conversion price downward to $1.00 to holders of the Series “B” Notes in exchange for a deferral of payment of accrued interest due on the Notes until December 31, 2015. Holders of notes totaling $2,000,000 of the total outstanding of $4,569,500 participated.

 

Notes Payable within one year

 

The Company is obligated on short term notes payable to third parties totaling $451,704 as of September 30, 2015.  The total of the balances will be payable on December 31, 2015.

Notes payable to related parties included in the detail above total $200,000.

 

11. SUBSEQUENT EVENTS

 

On October 14, 2015, Husky Ventures, (Husky) the operator of the Company’s properties in the Chisholm Trail AMI in Oklahoma, entered into an agreement to sell Husky’s Chisholm Trail working interests to Gastar Exploration Inc. with an expected closing date of November 30, 2015.

 

On November 5, 2015 Torchlight entered into an agreement with Husky Ventures to transfer its interests in Chisholm Trail assets to Husky in exchange for the cancellation of the Company’s entire liability to Husky on Joint Interest Billings in the approximate amount of $2.9 million. The agreement was executed with the intention of Husky including the Torchlight interests in producing properties and undeveloped acreage in Chisholm Trail as part of the Husky sale to Gastar. Torchlight will then participate in the proceeds of Husky’s sale to Gastar in accordance with the terms of Torchlight’s agreement with Husky.  Alternatively, if the Gastar transaction does not close, Torchlight and Husky will work to locate a different purchaser, and Torchlight will participate in the proceeds of any other sale of the Chisholm Trail assets if Husky effects such sale within one-year from October 31, 2015.  Regardless of whether Husky effects a sale to Gastar or any other party, the liability to Husky on Joint Interest Billings will remain extinguished, under the terms of Torchlight’s agreement with Husky.

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.  In addition to TEI, we also operate our business through our subsidiaries Torchlight Energy Operating, LLC and Hudspeth Oil Corporation.

Summary of Key Results

Overview

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

 

The following discussion of our financial condition and results of operations should be read in conjunction with our unaudited financial statements included herewith and our audited financial statements included with our Form 10-K for the year ended December 31, 2014.  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.  

Current Projects

As of September 30, 2015 the Company had interests in five oil and gas projects: the Marcelina Creek Field Development in Wilson County, Texas, the Coulter Field in Waller County, Texas, the Ring Energy Joint Venture in Southwest Kansas, the Hunton play in partnership with Husky Ventures in Central Oklahoma and the Orogrande Project in Hudspeth 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. Three of the obligation wells have been drilled.  The first three wells include a horizontal re-entry well known as the Johnson-1-H, a vertical well known as the Johnson #4, and a lateral well known as the Johnson #2-H.  These three wells are presently producing a total of approximately 60 BOPD.  The remaining well is to be a vertical development well at a location to be determined within the existing lease. Drilling is anticipated in 2015.

Coulter Field

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

Our total investment in the project, including fracture stimulation, subsequent testing, purchase of additional interests and capitalized interest, amounted to $696,948 as of September 30, 2015.

 

The Coulter is a non-core, non-producing asset which we will attempt to monetize by sale of the lease. We presently have approximately 940 acres.

 

The Ring Energy Joint Venture, Southwest Kansas

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

 

 

 

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

 

We have made the initial $3.1 million deposit and the first five well drilling program is completed. Drilling operations commenced in March, 2014. Seven wells have been drilled – three are producing, one can be converted to a salt water disposal well, one was not completed, and two were plugged and abandoned.  Based upon results from drilling, the participants elected to suspend further drilling and obtain seismic data to guide continuing development. The seismic data is being analyzed at the date of this filing.   As of September 30, 2015, the Company had invested approximately $5,359,000 in the Ring Joint Venture.  The Company believes this project is still considered to be in the testing phase.

Hunton Play, Central Oklahoma

During the second quarter of 2013, Torchlight entered into an agreement with Husky Ventures to participate in the drilling of wells to the Hunton Formation in central Oklahoma. We continued to expand this relationship with Husky Ventures on a monthly basis as we expand our lease acreage in the contracted Areas of Mutual Interest (AMI’s). The transaction wherein the Company acquired Hunton properties from Xtreme Oil and Gas Inco included the acquisition of three Hunton wells, the Hancock, Robinson and Lenhart.  The Hancock and Robinson were producing wells but had small working interests of 1% and .25 of 1%, respectively. 

 

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

 

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

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

 

The first well in the Cimarron AMI, the Boeckman #1-H well, was spud and was subsequently completed and fracture stimulated in July, 2013.   We acquired a working interest in the Boeckman #1-H well and subsequently sold part of our ownership in the Boeckman well for $990,000. We agreed to a preferential payout to the purchaser equal to 50% of his acquired interest.  The agreement was amended in the first quarter of 2014 to include our agreement to advance funds under a note receivable from the purchaser to be repaid from the purchaser’s revenue preference subsequent to October, 2014.  

In the third quarter of 2013, we acquired from a third party for stock, a 15.3% working interest in 5011+/- acres in the Chisolm Trail AMI with Husky Ventures Inc. as the operator. Leasing also continued monthly in this AMI increasing the total acreage in which the Company has an interest to approximately 11,300 as of September 30, 2015 (Net undeveloped acres = 1,700).  Our net cumulative investment through September 30, 2015 in undeveloped acres in the Chisholm Trail AMI was $4,391,160.

In the fourth quarter of 2013 we entered into our third Area of Mutual Interest (AMI) with Husky Ventures, the Viking Prospect.  This AMI covers four townships in size. We acquired a 25% interest in 3,945 acres in the Viking. We subsequently acquired an additional 5% in May, 2014.   Leasing is continuing monthly so that we had an interest in approximately 8,800 total acres in which the Company has an interest as of September 30, 2015. (Net undeveloped acres = 2,600) Husky drilled the first two wells in the AMI in second quarter, 2014.  Our net cumulative investment through September 30, 2015 in undeveloped acres in the Viking AMI was $1,358,254.

In January of 2014, we again elected to continue to expand in the Hunton Play with Husky Ventures.  We contracted for a 25% Working Interest in approximately 5,000 acres in the R4 AMI consisting of eight townships in South Central Oklahoma. We subsequently acquired an additional 5% in May, 2014.  Leasing is continuing monthly so that the Company had an interest in approximately 11,600 total acres as of September 30, 2015 (Net undeveloped acres = 3,500). Our cumulative investment through September 30, 2015 in the R4 AMI was $2,834,514.

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

In July of 2014, we elected to further expand in the Hunton Play with Husky Ventures.  We contracted for a 25% Working Interest in the T4 AMI.  There is an active ongoing leasing program in this AMI so that the total acres in which the Company has an interest at September 30, 2015 totals approximately 4,300 acres (Net undeveloped acres = 1.100). Our cumulative investment through September 30, 2015 in the T4 AMI was $949,530.

 

 

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

 

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

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

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

 

Revenues and Cost of Revenues

For the nine months ended September 30, 2015, we had production revenue of $1,442,857 compared to $4,214,720 for the nine months ended September 30, 2014.  Refer to the table of production and revenue included below for quarterly changes in revenue.  Our cost of revenue, consisting of lease operating expenses and production taxes, was $669,626, and $1,005,588 for the nine months ended September 30, 2015 and 2014, respectively.

 

Results of operations for the nine months ended September 30, 2015 includes Impairment expense of $22,438,114 (which was recorded at June 30, 2015) to recognize the impact of industry conditions (decline in oil price of $46 per barrel ) on the carrying value of the Investment in Oil and Gas Properties on the Company’s Balance Sheet. The Impairment expense was substantially attributable to the Hunton properties in Oklahoma.

 

Impairment was calculated in two steps. The Ceiling Test as of June 30, 2015 comparing PV10 value of reserves to cumulative costs of evaluated properties (those in production or in development) resulted in Impairment expense of $16,406,993. The $6,031,121 balance of Impairment expense represents the downward adjustment in cumulative costs of unevaluated properties calculated by comparison of cumulative costs per books to fair value indicated by recent industry transactions.

No Impairment adjustment was recorded for the three months ended September 30, 2015.