UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark One)

 

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

 

For the fiscal year ended December 31, 2019.

 

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

 

For the transition period from _______ to _______.

 

Commission file number 000-53473

 

Torchlight Energy Resources, Inc.

(Exact name of registrant in its charter)

 

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

 

5700 W. Plano Parkway, Suite 3600
Plano, Texas 75093
(Address of principal executive offices)
 
(214) 432-8002
(Registrant’s telephone number, including area code)
 
Securities registered pursuant to Section 12(b) of the Exchange Act:
 
Common Stock ($0.001 Par Value)
(Title of Each Class)
 
The NASDAQ Stock Market LLC
(Name of each exchange on which registered)
 
Securities registered pursuant to Section 12(g) of the Exchange Act:
 
None
 

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

 

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

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

 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes x No o

 

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

 

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

 

 

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

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

 

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

 

The aggregate market value of the common stock held by non-affiliates of the registrant on June 30, 2019, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $1.42 on the Nasdaq Stock Market, was approximately $103,835,962.

 

At March 16, 2020, there were 79,968,132 shares of the registrant’s common stock outstanding (the only class of common stock).

 

DOCUMENTS INCORPORATED BY REFERENCE

 

None.

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NOTE ABOUT FORWARD-LOOKING STATEMENTS

 

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

 

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

3

 

TABLE OF CONTENTS

 

PART I

 

      Page
Item 1. Business   5
Item 1A. Risk Factors   9
Item 1B. Unresolved Staff Comments   18
Item 2. Properties   19
Item 3. Legal Proceedings   26
Item 4. Mine Safety Disclosures   26
       
       
PART II
       
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities   27
Item 6. Selected Financial Data   27
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations   28
Item 7A. Quantitative and Qualitative Disclosures About Market Risk   32
Item 8. Financial Statements and Supplementary Data   33
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure   60
Item 9A. Controls and Procedures   60
Item 9B. Other Information   61
       
PART III
       
Item 10. Directors, Executive Officer, and Corporate Governance   62
Item 11. Executive Compensation   64
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters   66
Item 13. Certain Relationships and Related Transactions, and Director Independence   67
Item 14. Principal Accountant Fees and Services   68
Item 15. Exhibits, Financial Statement Schedules   69
       
  Signatures   71

4

 

PART I

 

ITEM 1. BUSINESS

 

Corporate History and Background

 

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

 

On November 23, 2010, we entered into and closed a Share Exchange Agreement (the “Exchange Agreement”) between the major shareholders of PPS and the shareholders of Torchlight Energy, Inc. (“TEI”). As a result of the transactions effected by the Exchange Agreement, at closing TEI became our wholly-owned subsidiary, and the business of TEI became our sole business. TEI is an energy company, incorporated under the laws of the State of Nevada in June, 2010.

 

Business Overview

 

We are an energy company engaged in the acquisition, exploration, exploitation and/or development of oil and natural gas properties in the United States. We are primarily focused on the acquisition of early stage projects, the development and delineation of these projects, and then the monetization of those assets once these activities are completed.

 

Since 2010, our primary focus has been the development of interests in oil and gas projects we hold in the Permian Basin in West Texas, including the Orogrande Project in Hudspeth County, Texas, the Hazel Project in the Midland Basin and the project in Winkler County, Texas in the Delaware Basin. We also hold interests in certain other oil and gas projects that we are in the process of divesting, including the Hunton wells project as part of a partnership with Husky Ventures, Inc., or Husky, in Central Oklahoma.

 

We employ a private equity model within a public platform, with the goal to (i) enter into a play at favorable valuations, (ii) “prove up” and delineate the play through committed capital and exhaustive geologic and engineering review, and (iii) monetize our position through an exit to public and private independents that can continue full-scale development. Rich Masterson, our consulting geologist, has originated several of our current plays, as discussed below, based on his tenure as a geologist since 1974. He is credited with originating the Wolfbone shale play in the Southern Delaware Basin of West Texas and has prepared prospects totaling over 150,000 acres that have been leased, drilled and are currently being developed by Devon Energy Corp., Occidental Petroleum Corporation, Noble Energy, and Samson Oil & Gas Ltd., among others.

 

In April 2018, we announced that we have commenced a process that could result in the monetization of the Hazel Project. Pursuant to our corporate strategy, in our opinion between the development activity at the Hazel Project, coupled with nearby activities of other oil and gas operators, this project has achieved a level of value that suggests monetization. We believe that the liquidity that would be provided from selling the Hazel Project could be redeployed into the Orogrande Project.

The Company is also currently marketing the Orogrande project for an outright sale or farm in partner and is taking measures on its own to market the Winkler Project.

 

These efforts are continuing.

 

We operate our business through five wholly-owned subsidiaries, Torchlight Energy, Inc., a Nevada corporation, or TEI, Torchlight Energy Operating, LLC, a Texas limited liability company, Hudspeth Oil Corporation, a Texas corporation, or Hudspeth, Torchlight Hazel, LLC, a Texas limited liability company, and Warwink Properties, LLC, a Texas limited liability company, or Warwink Properties. We currently have two full-time employees and we employ consultants for various tasks as needed.

 

Our principal executive offices are located at 5700 W. Plano Parkway, Suite 3600, Plano, Texas 75093. The telephone number of our principal executive offices is (214) 432-8002.

 

Key Business Attributes

 

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

 

Project Focus. We are focusing primarily on exploitation projects by pursuing resources in areas where commercial production has already been established but where opportunity for additional and nearby development is indicated. We may pursue high risk exploration prospects which may appear less favored than low risk exploration. We will, however, consider these high risk-high reward exploration prospects in connection with exploitation opportunities in a project that would reduce the overall project economic risk. We will consider such high risk-high reward prospects on their individual merits.

 

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

 

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

5

 

ITEM 1. BUSINESS - continued

 

Business Processes

 

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

 

Investment Evaluation and Review;

 

Operations and Field Activities; and

 

Administrative and Finance Management.

 

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

 

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

 

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

 

Current Projects

 

As of December 31, 2019, we had interests in four oil and gas projects: the Orogrande Project in Hudspeth County, Texas, the Hazel Project in Sterling, Tom Green, and Irion Counties, Texas, the Winkler Project in Winkler County, Texas, and the Hunton wells in partnership with Husky in Central Oklahoma

 

See the description under “Current Projects” below under Note 4, “Oil & Gas Properties,” of the financial statements included with this report for information and disclosure regarding these projects, which description is incorporated herein by reference.

6

 

ITEM 1. BUSINESS - continued

 

Industry and Business Environment

 

We are experiencing a time of fluctuating oil prices caused by lower demand, higher US Supply, and OPEC’s policies on production. Unfortunately, this is the cyclical nature of the oil and gas industry. We experience highs and lows that seem to come in cycles. Fortunately, advances in technology drive the US market and we feel this will drive the development costs down on our exploration and drilling programs.

 

Competition

 

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

 

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

 

Marketing and Customers

 

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

 

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

 

Governmental Regulation and Environmental Matters

 

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

 

Regulation of Oil and Natural Gas Production

 

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

 

Environmental Matters

 

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

 

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

 

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

 

impose substantial liabilities for pollution resulting from operations; or

 

restrict certain areas from fracking and other stimulation techniques.

7

 

ITEM 1. BUSINESS - continued

 

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

 

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

 

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

 

Hydraulic fracturing is regulated by state and federal oil and gas regulatory authorities, including specifically the requirement to disclose certain information related to hydraulic fracturing operations. Operators must follow applicable legal requirements for groundwater protection in our operations that are subject to supervision by state and federal regulators (including the Bureau of Land Management on federal acreage). Furthermore, well construction practices require the installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers by preventing the migration of fracturing fluids into aquifers. Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies have continued to assess the impacts of hydraulic fracturing, which could spur further action toward federal and/or state legislation and regulation of hydraulic fracturing activities. In addition, in light of concerns about seismic activity being triggered by the injection of produced waters into underground wells and hydraulic fracturing, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. Further restrictions on hydraulic fracturing could make it prohibitive to conduct our operations, and also reduce the amount of oil and natural gas that we or our operators are ultimately able to produce in commercial quantities from our properties.

 

Climate Change

 

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

 

Employees

 

We currently have two full time employees and no part time employees. We employ consultants and contract help as needed. We anticipate, as needed, we will add additional employees, and we will continue using independent contractors, consultants, attorneys, and accountants as necessary to complement services rendered by our employees. We presently have independent technical professionals under consulting agreements who are available to us on an as needed basis.

 

Research and Development

 

We did not spend any funds on research and development activities during the years ended December 31, 2019 or 2018.

8

 

ITEM 1A. RISK FACTORS

 

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

 

Risks Related to our Business and Industry

 

We have a limited operating history relative to larger companies in our industry, and may not be successful in developing profitable business operations.

 

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

 

our ability to raise adequate working capital;

 

the success of our development and exploration;

 

the demand for natural gas and oil;

 

the level of our competition;

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

The financial statements included with this report are presented under the assumption that we will continue as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business over a reasonable length of time. We had a net loss of approximately $9.8 million for the year ended December 31, 2019 and an accumulated deficit in aggregate of approximately $99.2 million at year end. We are not generating sufficient operating cash flows to support continuing operations, and expect to incur further losses in the development of our business.

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ITEM 1A. RISK FACTORS - continued

 

In our financial statements for the year ended December 31, 2019, our auditor indicated that certain factors raised substantial doubt about our ability to continue as a going concern. These factors included our accumulated deficit, as well as the fact that we were not generating sufficient cash flows to meet our regular working capital requirements. Our ability to continue as a going concern is dependent upon our ability to generate future profitable operations and/or to obtain the necessary financing to meet our obligations and repay our liabilities arising from normal business operations when they come due. Management’s plan to address our ability to continue as a going concern includes: (1) obtaining debt or equity funding from private placement or institutional sources; (2) obtaining loans from financial institutions, where possible, or (3) participating in joint venture transactions with third parties. Although management believes that it will be able to obtain the necessary funding to allow us to remain a going concern through the methods discussed above, there can be no assurances that such methods will prove successful. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

The negative covenants contained in our outstanding unsecured promissory notes may limit our activities and make it difficult to run our business.

 

On April 10, 2017, we sold to investors in a private transaction two 12% unsecured promissory notes with a total of $8,000,000 in principal amount (the “2017 Notes”). In addition, on February 6, 2018, we sold to an investor in a private transaction a 12% unsecured promissory note with a principal amount of $4,500,000, (the “2018 Note”), containing substantially the same terms as the 2017 Notes. We refer to the 2017 Notes and the 2018 Note collectively as “the Notes”. Interest only is due and payable on the Notes each month at the rate of 12% per annum, with a balloon payment of the outstanding principal due and payable at maturity on April 10, 2020. The holders of the Notes will also receive annual payments of common stock at the rate of 2.5% of principal amount outstanding, based on a volume-weighted average price. We sold the 2017 Notes at an original issue discount of 94.25% and accordingly, we received total proceeds of $7,540,000 from the investors. We sold the 2018 Note at an original issue discount of 96.27% and accordingly, we received total proceeds of $4,332,150 from the investor. On February 19, 2020, one of the holder of the 2017 Notes agreed to an extension of the maturity date on a $4,000,000 promissory note, extending it from April 10, 2020 to April 10, 2021. We paid the noteholder a fee of $80,000 under the terms of the extension. At the date of this filing, an extension of the remaining $8.5 million of 12% unsecured promissory notes that mature in April 2020 is in the process of negotiation.

 

The Notes contain negative covenants which may make it difficult for us to run our business. Under the Notes, we may not, directly or indirectly, consolidate with or merge into another person or sell, lease, convey or transfer all or substantially all of our assets (computed on a consolidated basis), unless either (i) in the case of a merger or consolidation, we are the surviving entity or (ii) the resulting, surviving or transferee entity expressly assumes by supplemental agreement all of the obligations of us in connection with the Notes.

 

In addition, the Notes also contain certain covenants under which we have agreed that, except for financing arrangements with established commercial banking or financial institutions and other debts and liabilities incurred in the normal course of business, we will not issue any other notes or debt offerings which have a maturity date prior to the payment in full of the respective Note, unless consented to by the holder. Further, our subsidiaries cannot sell or otherwise dispose of any shares of capital stock or assets unless the transaction is for fair value and approved by our disinterested directors or is pursuant to any contractual obligation entered into by us in the ordinary course of business in connection with drilling, exploration and development of our oil and gas properties.

 

The Notes also restrict us and our subsidiaries from (i) issuing any preferred stock or any other comparable equity interest which are mandatorily redeemable at a date prior to the maturity date of the Notes, without the consent or approval of the holder, (ii) distributing any cash or other assets to any holders of our common stock prior to payment in full of the Notes, without the consent of the holder, (iii) entering into any transaction with an affiliate, subject to limited exceptions, and (iv) issuing any other notes or debt offerings which have a maturity date prior to the payment in full of the Notes, unless consented to by the holder.

 

Failure to comply with the negative covenants could accelerate the repayment of any debt outstanding under the Notes. Additionally, as a result of these negative covenants, we may be at a disadvantage compared to our competitors that have greater operating and financing flexibility than we do.

 

Lastly, we may have difficulty securing additional sources of capital through debt financing. If we do not succeed in raising additional capital, our resources may not be sufficient to fund our planned operations.

 

We have a large amount of debt obligations coming due in April and May of 2020 which we may be unable to adequately extend or refinance which could result in defaults

 

As described above, the 2017 Notes and the 2018 Note have balloon payments of outstanding principal of $8.5 million due and payable at maturity on April 10, 2020—as referenced above, the maturity date of $4 million in 2017 Notes was extended to April 10, 2021. Additionally, certain 14% Series D Unsecured Convertible Promissory Notes with a total of $2 million in principal amount mature on May 11, 2020. The 2017 Notes and 2018 Note are held by affiliates of a high-net-worth estate, and we are in the process of negotiating an extension. We believe we have a strong relationship with the broker of the decedent of the estate and believe an extension will be finalized. We have also begun communication with other lenders to address the maturities of these notes. If we are unable to adequately address the large amount of upcoming debt maturities, there would be a material adverse impact to our financial condition.

10

 

ITEM 1A. RISK FACTORS - continued

 

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

 

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

 

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

 

We are mainly concentrated in one geographic area, which increases our exposure to many of the risks enumerated herein.

 

Operating in a concentrated area increases the potential impact that many of the risks stated herein may have upon our ability to perform. For example, we have greater exposure to regulatory actions impacting Texas, natural disasters in the geographic area, competition for equipment, services and materials available in the area and access to infrastructure and markets. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

 

We may be unable to monetize the Orogrande, Hazel and Warwink Projects at an attractive price, if at all, and the disposition of such assets may involve risks and uncertainties.

 

We have commenced a process that could result in the monetization of the Orogrande, Hazel and Warwink Projects. Such dispositions may result in proceeds to us in an amount less than we expect or less than our assessment of the value of the assets. We do not know if we will be able to successfully complete such disposition on favorable terms or at all. In addition, the sale of these assets involves risks and uncertainties, including disruption to other parts of our business, potential loss of customers or revenue, exposure to unanticipated liabilities or result in ongoing obligations and liabilities to us following any such divestiture.

 

For example, in connection with a disposition, we may enter into transition services agreements or other strategic relationships, which may result in additional expense. In addition, in connection with a disposition, we may be required to make representations about the business and financial affairs of the business or assets. We may also be required to indemnify the purchasers to the extent that our representations turn out to be inaccurate or with respect to certain potential liabilities. These indemnification obligations may require us to pay money to the purchasers as satisfaction of their indemnity claims. It may also take us longer than expected to fully realize the anticipated benefits of this transaction, and those benefits may ultimately be smaller than anticipated or may not be realized at all, which could adversely affect our business and operating results. Any of the foregoing could adversely affect our financial condition and results of operations.

 

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

 

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

 

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

 

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

11

 

ITEM 1A. RISK FACTORS - continued

 

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

 

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

 

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

 

the level of consumer demand for oil and natural gas;

 

the domestic and foreign supply of oil and natural gas;

 

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

 

the price of foreign oil and natural gas;

 

domestic governmental regulations and taxes;

 

the price and availability of alternative fuel sources;

 

weather conditions;

 

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

 

worldwide economic conditions.

 

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

 

The recent global downturn in the price of oil may materially and adversely affected our results of operations, cash flows and financial condition, and this trend could continue during 2020 and potentially beyond.

 

In early March of 2020, the market has experienced a precipitous decline in oil prices in response to oil demand concerns due to the economic impacts of the a highly transmissible and pathogenic coronavirus known as COVID-19 and anticipated increases in supply from Russia and OPEC, particularly Saudi Arabia. Generally, demand for oil has declined substantially. These trends materially and adversely affect our results of operations, cash flows and financial condition, and, unless conditions in our industry improve, this trend will continue during 2020 and potentially beyond.

 

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

 

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

 

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

 

The Company recognized an impairment charge of $1,494,769 in 2019 and $139,891 in 2018.

12

 

ITEM 1A. RISK FACTORS - continued

 

During the year ended December 31, 2017 the Company performed assessments of evaluated and unevaluated costs in the cost pool to conform the cumulative value of the Full Cost Pool to the combined amount of Reserve Value of evaluated, producing properties (as determined by independent analysis at December 31, 2017), plus the lesser of cumulative historical cost or estimated realizable value of unevaluated leases and projects expected to commence production in future operating periods. The Company identified impairment of $2,300,626 in 2017 related to its unevaluated properties. Although we had no recognized impairment expense in 2017, the Company has adjusted the separation of evaluated versus unevaluated costs within its full cost pool to recognize the value impairment related to the expiration of unevaluated leases in 2017 in the amount of $2,300,626. The impact of this change will be to increase the basis for calculation of future period’s depletion, depreciation and amortization to include $2,300,626 of cost which will effectively recognize the impairment on the Statement of Operations over future periods. The $2,300,626 has also become an evaluated cost for purposes of future period’s Ceiling Tests and which may further recognize the impairment expense recognized in future periods. At December 31, 2019 an additional impairment of unevaluated costs of $756,964 was added to the basis for future period’s depletion.

 

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

 

The oil and natural gas business involves a variety of operating hazards and risks such as well blowouts, pipe failures, casing collapse, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, spills, pollution, releases of toxic gas and other environmental hazards and risks. These hazards and risks could result in substantial losses to us from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties and suspension of operations. In addition, we may be liable for environmental damages caused by previous owners of property purchased and leased by us. In recent years, there has also been increased scrutiny on the environmental risk associated with hydraulic fracturing, such as underground migration and surface spillage or mishandling of fracturing fluids including chemical additives. This technology has evolved and continues to evolve and become more aggressive. We believe that new techniques can increase estimated ultimate recovery per well to over 1.0 million barrels of oil equivalent, and have increased initial production two or three fold. We believe that recent designs have seen improvement in, among other things, proppant per foot, barrels of water per stage, fracturing stages, and clusters per fracturing stage. As a result, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of our properties and/or force us to expend substantial monies in connection with litigation or settlements. In addition, we will need to quickly adapt to the evolving technology, which could take time and divert our attention to other business matters. We currently have no insurance to cover such losses and liabilities, and even if insurance is obtained, it may not be adequate to cover any losses or liabilities. We cannot predict the availability of insurance or the availability of insurance at premium levels that justify our purchase. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and operations. We may elect to self-insure if management believes that the cost of insurance, although available, is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations.

 

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

 

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

 

As a result, we may not be able to compete successfully and competitive pressures may adversely affect our business, results of operations, and financial condition. If we are not able to successfully compete in the marketplace, we could be forced to curtail or even abandon our current business plan, which could cause any investment in us to become worthless.

 

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

 

Any growth of the company may place a significant strain on our managerial, operational and financial resources, especially considering that we currently only have a small number of executive officers, employees and advisors. Further, as we enter into additional contracts, we will be required to manage multiple relationships with various consultants, businesses and other third parties. These requirements will be exacerbated in the event of our further growth or in the event that the number of our drilling and/or extraction operations increases. Our systems, procedures and/or controls may not be adequate to support our operations or that our management will be able to achieve the rapid execution necessary to successfully implement our business plan. If we are unable to manage our growth effectively, our business, results of operations and financial condition will be adversely affected, which could lead to us being forced to abandon or curtail our business plan and operations.

 

The due diligence undertaken by us in connection with all of our acquisitions may not have revealed all relevant considerations or liabilities related to those assets, which could have a material adverse effect on our financial condition or results of operations.

13

 

ITEM 1A. RISK FACTORS - continued

 

The due diligence undertaken by us in connection with the acquisition of our properties may not have revealed all relevant facts that may be necessary to evaluate such acquisitions. The information provided to us in connection with our diligence may have been incomplete or inaccurate. As part of the diligence process, we have also made subjective judgments regarding the results of operations and prospects of the assets. If the due diligence investigations have failed to correctly identify material issues and liabilities that may be present, such as title defects or environmental problems, we may incur substantial impairment charges or other losses in the future. In addition, we may be subject to significant, previously undisclosed liabilities that were not identified during the due diligence processes and which may have a material adverse effect on our financial condition or results of operations.

 

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

 

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

 

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

 

We believe that we will be in substantial compliance with applicable environmental laws and regulations. To date, we have not expended any amounts to comply with such regulations, and we do not currently anticipate that future compliance will have a materially adverse effect on our consolidated financial position, results of operations or cash flows. However, if we are deemed to not be in compliance with applicable environmental laws, we could be forced to expend substantial amounts to be in compliance, which would have a materially adverse effect on our financial condition.

 

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

 

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

 

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

 

Hydraulic fracturing is typically regulated by state oil and gas commissions. Some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, and/or well construction requirements on hydraulic fracturing operations.

 

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

 

Further, the EPA has asserted federal regulatory authority over hydraulic fracturing involving “diesel fuels” under the Solid Waste Disposal Act’s Underground Injection Control Program. The EPA is also engaged in a study of the potential impacts of hydraulic fracturing activities on drinking water resources in the states where the EPA is the permitting authority. These actions, in conjunction with other analyses by federal and state agencies to assess the impacts of hydraulic fracturing could spur further action toward federal and/or state legislation and regulation of hydraulic fracturing activities.

14

 

ITEM 1A. RISK FACTORS - continued

 

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

 

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

 

Estimates of reserves and of future net revenues prepared by different petroleum engineers may vary substantially depending, in part, on the assumptions made and may be subject to adjustment either up or down in the future. Our actual amounts of production, revenue, taxes, development expenditures, operating expenses, and quantities of recoverable oil and gas reserves may vary substantially from the estimates. Oil and gas reserve estimates are necessarily inexact and involve matters of subjective engineering judgment. In addition, any estimates of our future net revenues and the present value thereof are based on assumptions derived in part from historical price and cost information, which may not reflect current and future values, and/or other assumptions made by us that only represent our best estimates. If these estimates of quantities, prices and costs prove inaccurate, we may be unsuccessful in expanding our oil and gas reserves base with our acquisitions. Additionally, if declines in and instability of oil and gas prices occur, then write downs in the capitalized costs associated with any oil and gas assets we obtain may be required. Because of the nature of the estimates of our reserves and estimates in general, reductions to our estimated proved oil and gas reserves and estimated future net revenues may not be required in the future, and/or that our estimated reserves may not present and/or commercially extractable. If our reserve estimates are incorrect, we may be forced to write down the capitalized costs of our oil and gas properties.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Challenges to our properties may impact our financial condition.

 

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

15

 

ITEM 1A. RISK FACTORS - continued

 

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

 

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

 

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

 

Our future success is dependent, in a large part, on retaining the services of our current management team. Our executive officers possess a unique and comprehensive knowledge of our industry and related matters that are vital to our success within the industry. The knowledge, leadership and technical expertise of these individuals would be difficult to replace. The loss of one or more of our officers could have a material adverse effect on our operating and financial performance, including our ability to develop and execute our long-term business strategy. We do not maintain key-man life insurance with respect to any employees. We do have employment agreements with each of our executive officers.

 

We have limited management and staff and are dependent upon partnering arrangements and third-party service providers.

 

We currently have two full-time employees, including our Chief Executive Officer and Chief Financial Officer. The loss of these individuals would have an adverse effect on our business, as we have very limited personnel. We leverage the services of other independent consultants and contractors to perform various professional services, including engineering, oil and gas well planning and supervision, and land, legal, environmental and tax services. We also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. Our dependence on third-party consultants and service providers create a number of risks, including but not limited to:

 

the possibility that such third parties may not be available to us as and when needed; and

 

the risk that we may not be able to properly control the timing and quality of work conducted with respect to its projects.

 

If we experience significant delays in obtaining the services of such third parties or they perform poorly, our results of operations and stock price could be materially adversely affected.

 

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

 

As of the date of this report, our executive officers and directors collectively and beneficially own approximately 26% of our outstanding common stock (see Item 12 of this report for an explanation of how this number is computed). This concentration of voting control gives these affiliates substantial influence over any matters which require a stockholder vote, including without limitation the election of directors and approval of merger and/or acquisition transactions, even if their interests may conflict with those of other stockholders. It could have the effect of delaying or preventing a change in control or otherwise discouraging a potential acquirer from attempting to obtain control of us. This could have a material adverse effect on the market price of our common stock or prevent our stockholders from realizing a premium over the then prevailing market prices for their shares of common stock.

 

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

 

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

 

In addition, the Sarbanes-Oxley Act requires, among other things, that we maintain effective internal controls for financial reporting and disclosure controls and procedures. In particular, we are required to perform system and process evaluation and testing on the effectiveness of our internal controls over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act. In performing this evaluation and testing, management concluded that our internal control over financial reporting is effective as of December 31, 2019. Our continued compliance with Section 404, will require that we incur substantial accounting expense and expend significant management efforts. We do not have an internal audit group. We have however, engaged independent professional assistance for the evaluation and testing of internal controls.

16

 

ITEM 1A. RISK FACTORS - continued

 

Terrorist attacks or cyber-incidents could result in information theft, data corruption, operational disruption and/or financial loss.

 

Like most companies, we have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our business partners, analyze mine and mining information, estimate quantities of coal reserves, as well as other activities related to our businesses. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cyber-attacks than other targets in the United States. Deliberate attacks on, or security breaches in, our systems or infrastructure, or the systems or infrastructure of third parties, or cloud-based applications could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third-party liability. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, results of operations and cash flows. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

 

We have adopted an Information Security Policy and Acceptable Use Statement to address precautions with respect to data security and we have created an Incident Response Plan which outlines appropriate responses in case of a reported breach. These policies and plan have been executed in coordination with our independent Information Technology Service provider.

 

Certain Factors Related to Our Common Stock

 

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

 

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

 

Securities analysts may not initiate coverage or continue to cover our shares of common stock and this may have a negative impact on the market price of our shares of common stock.

 

The trading market for our shares of common stock will depend, in part, on the research and reports that securities analysts publish about our business and our shares of common stock. We do not have any control over these analysts. If securities analysts do not cover our shares of common stock, the lack of research coverage may adversely affect the market price of those shares. If securities analysts do cover our shares of common stock, they could issue reports or recommendations that are unfavorable to the price of our shares of common stock, and they could downgrade a previously favorable report or recommendation, and in either case our share prices could decline as a result of the report. If one or more of these analysts does not initiate coverage, ceases to cover our shares of common stock or fails to publish regular reports on our business, we could lose visibility in the financial markets, which could cause our share prices or trading volume to decline.

 

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

 

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

 

Our directors and officers have rights to indemnification.

 

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

17

 

ITEM 1A. RISK FACTORS - continued

 

We do not anticipate paying any cash dividends on our common stock.

 

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

 

NASDAQ may delist our common stock from trading on its exchange, which could limit shareholders’ ability to trade our common stock; further, we are presently not in compliance with NASDAQ’s minimum bid price rule.

 

As a listed company on NASDAQ, we are required to meet certain financial, public float, bid price and liquidity standards on an ongoing basis in order to continue the listing of our common stock. If we fail to meet these continued listing requirements, our common stock may be subject to delisting. If our common stock is delisted and we are not able to list our common stock on another national securities exchange, we expect our securities would be quoted on an over-the-counter market. If this were to occur, our shareholders could face significant material adverse consequences, including limited availability of market quotations for our common stock and reduced liquidity for the trading of our securities. In addition, we could experience a decreased ability to issue additional securities and obtain additional financing in the future.

 

Further, on November 21, 2019, we received a letter from the Listing Qualifications Staff (the “Staff”) of NASDAQ advising us that the Staff has determined that for the last 30 consecutive business days, we no longer meet the requirement of Listing Rule 5550(a)(2) which requires us to maintain a minimum bid price of $1 per share. The Listing Rules provide us with a compliance period of 180 calendar days in which to regain compliance. Accordingly, we will regain compliance if at any time during this 180-day period the closing bid price of our common stock is at least $1 for a minimum of ten consecutive business days. In the event we do not regain compliance by the end of the 180-day compliance period on May 19, 2020, we may be eligible for additional time. To qualify, we will be required to meet the continued listing requirement for market value of publicly held shares and all other initial listing standards for The NASDAQ Capital Market, with the exception of the bid price requirement, and will need to provide written notice of our intention to cure the deficiency during the second compliance period, by effecting a reverse stock split, if necessary. If we meet these requirements, the Staff will inform us that we have been granted an additional 180 calendar days. However, if it appears to the Staff that we will not be able to cure the deficiency, or if we are otherwise not eligible, the Staff will provide us notice that our common stock will be subject to delisting. At that time, we may appeal the delisting determination to a Hearings Panel.

 

We are currently reviewing our options to regain compliance with the NASDAQ Listing Rules, but we have made no decisions at this time.

 

Issuance of our stock in the future could dilute existing shareholders and adversely affect the market price of our common stock.

 

We have the authority to issue up to 150,000,000 shares of common stock and 10,000,000 shares of preferred stock, and to issue options and warrants to purchase shares of our common stock. We are authorized to issue significant amounts of common stock in the future, subject only to the discretion of our board of directors. These future issuances could be at values substantially below the price paid for our common stock by investors. In addition, we could issue large blocks of our stock to fend off unwanted tender offers or hostile takeovers without further shareholder approval. Because the trading volume of our common stock is relatively low, the issuance of our stock may have a disproportionately large impact on its price compared to larger companies.

 

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

 

An issuance of preferred stock could result in a class of outstanding securities that would have preferences with respect to voting rights and dividends and in liquidation over the common stock and could, upon conversion or otherwise, have all of the rights of our common stock. Our board of directors’ authority to issue preferred stock could discourage potential takeover attempts or could delay or prevent a change in control through merger, tender offer, proxy contest or otherwise by making these attempts more difficult or costly to achieve.

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

 

Not Applicable.

18

 

ITEM 2. PROPERTIES

 

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

 

Investments in oil and gas properties during the years ended December 31, 2019 and 2018 are detailed as follows:

 

   2019   2018 
Property acquisition costs  $-   $1,072,047 
Development costs  $6,641,467   $9,191,041 
Exploratory costs  $-   $- 
           
Totals  $6,641,467   $10,263,088 

 

Property development costs presented above exclude interest capitalized into the full cost pool of $2,858,753 in 2019 and $2,020,019 in 2018.

 

The development costs for 2019 include work in the Orogrande, Hazel, and Warwink projects in west Texas. No development costs were incurred for Oklahoma properties in 2019.

 

Oil and Natural Gas Reserves

 

Reserve Estimates

 

SEC Case. The following tables sets forth, as of December 31, 2019, our estimated net proved oil and natural gas reserves, the estimated present value (discounted at an annual rate of 10%) of estimated future net revenues before future income taxes (PV-10) and after future income taxes (Standardized Measure) of our proved reserves and our estimated net probable oil and natural gas reserves, each prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with assumptions prescribed by the Securities and Exchange Commission (“SEC”). All of our reserves are located in the United States.

 

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

19

 

ITEM 2. PROPERTIES - continued

 

The estimates of our proved reserves and the PV-10 set forth herein reflect estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions at December 31, 2019. For purposes of determining prices, we used the average of prices received for each month within the 12-month period ended December 31, 2019, adjusted for quality and location differences, which was $52.19 per barrel of oil and $2.58 per MCF of gas. This average historical price is not a prediction of future prices. The amounts shown do not give effect to non-property related expenses, such as corporate general administrative expenses and debt service, future income taxes or to depreciation, depletion and amortization.

 

   December 31, 2019   December 31, 2019 
   Reserves   Future Net Revenue (M$) 
                   Present Value 
                   Discounted 
Category  Oil (Bbls)   Gas (Mcf)   Total (BOE)   Total   at 10% 
                     
Proved Producing   14,700    21,100    18,217   $634   $514 
Proved Nonproducing   0    0    0   $-   $- 
Total Proved   14,700    21,100    18,217   $634   $514 
                          
Standardized Measure of Future Net Cash Flows Related to Proved Oil and Gas Properties                      $539 
                          
Probable Undeveloped   0    0    0   $-   $- 
                     
   December 31, 2018   December 31, 2018             
   Reserves   Future Net Revenue (M$)             
                   Present Value
Discounted
 
Category  Oil (Bbls)   Gas (Mcf)   Total (BOE)   Total   at 10% 
                     
Proved Producing   177,300    51,100    185,817   $4,027   $2,029 
Proved Undeveloped   797,500    105,800    815,133   $15,313   $2,895 
Total Proved   974,800    156,900    1,000,950   $19,340   $4,924 
                          
Standardized Measure of Future Net Cash Flows Related to Proved Oil and Gas Properties                      $5,341 
                          
Probable Undeveloped   0    0    0   $-   $- 

 

The decrease in producing reserves from 2018 to 2019 from 185,817 to 18,217 BOE is related to the shut in of the Hazel Flying B #3 well in May, 2019 and the decline in production in the Oklahoma properties. Neither of these properties were economic under the 2019 Reserve Report.

 

The upward revisions of previous estimates from 2017 to 2018 of proved reserves of 972,500 BBLS and 113,100 MCF resulted primarily from 2018 reserve report calculations for the Company’s properties which included reserves from producing properties in the Hazel and Warwink Projects for the first time.

 

Reserve values as of December 31, 2019 are related to a single producing well in the Warwink Project.

 

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

20

 

ITEM 2. PROPERTIES - continued

 

Standardized Measure of Oil & Gas Quantities - Volume Rollforward
Year Ended December 31, 2019

 

The following table sets forth the Company’s net proved reserves, including the changes therein, and proved developed reserves:

 

   Crude Oil (Bbls)   Natural Gas (Mcf)   BOE 
TOTAL PROVED RESERVES:               
Beginning of period   974,780    156,940    1,000,937 
Revisions of previous estimates   (944,985)   (121,400)   (965,218)
Extensions, discoveries and other additions   -    -    - 
Divestiture of Reserves   -    -    - 
Acquisition of Reserves   -    -    - 
Production   (15,085)   (14,410)   (17,487)
End of period   14,710    21,130    18,232 

 

Standardized Measure of Oil & Gas Quantities - Volume Rollforward
Year Ended December 31, 2018

 

The following table sets forth the Company’s net proved reserves, including the changes therein, and proved developed reserves:

 

   Crude Oil (Bbls)   Natural Gas (Mcf)   BOE 
TOTAL PROVED RESERVES:               
Beginning of period   2,300    43,800    9,600 
Revisions of previous estimates   21,257    (7,709)   19,972 
Extensions, discoveries and other additions   974,110    138,670    997,222 
Divestiture of Reserves   -    -    - 
Acquisition of Reserves   -    -    - 
Production   (22,887)   (17,821)   (25,857)
End of period   974,780    156,940    1,000,937 

21

 

ITEM 2. PROPERTIES - continued

 

Standardized Measure of Oil & Gas Quantities
Year Ended December 31, 2019 & 2018

 

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows:

 

   2019   2018 
         
Future cash inflows  $843,040   $46,335,070 
Future production costs   (196,670)   (15,042,900)
Future development costs   -    (11,740,000)
Future income tax expense   -    - 
Future net cash flows   646,370    19,552,170 
10% annual discount for estimated timing of cash flows   (107,070)   (14,210,840)
Standardized measure of discounted future net cash flows related to proved reserves  $539,300   $5,341,330 

 

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves is as follows:

 

   2019   2018 
Balance, beginning of period  $5,341,330   $123,268 
Net change in sales and transfer prices and in production (lifting) costs          
related to future production   1,176,090    40,762 
Changes in estimated future development costs   1,851,760    (8,718,999)
Net change due to revisions in quantity estimates   (5,896,344)   289,740 
Accretion of discount   (868,787)   1,036 
Other   (1,763,161)   (385,278)
           
Net change due to extensions and discoveries   -    14,467,005 
Net change due to sales of minerals in place   -    - 
Sales and transfers of oil and gas produced during the period   (294,912)   (476,204)
Previously estimated development costs incurred during the period   993,324    - 
Net change in income taxes   -    - 
Balance, end of period  $539,300   $5,341,330 

 

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

 

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

 

Reserve Estimation Process, Controls and Technologies

 

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

22

 

ITEM 2. PROPERTIES - continued

 

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

 

PeTech Enterprises, Inc. (“PeTech”), who provided 2019 and 2018 reserve estimates for our properties, is a Texas based family owned oil and gas production and investment company that provides reservoir engineering, economics and valuation support to energy banks, energy companies and law firms as an expert witness. PeTech has been in business since 1982. Amiel David is the President of PeTech and the primary technical person in charge of the estimates of reserves and associated cash flow and economics on behalf of the company for the results presented in its reserves report to us. He has a PhD in Petroleum Engineering from Stanford University. He is a registered Professional Engineer in the state of Texas (PE #50970), granted in 1982, a member of the Society of Petroleum Engineers and a member of the Society of Petroleum Evaluation Engineers.

 

Proved Nonproducing Reserves

 

As of December 31, 2019, our proved non producing reserves totaled -0- barrels of oil equivalents (BOE) compared to 815,133 as of December 31, 2018, a decrease of 815,133 BOE.

 

At the end of 2019 reserve calculations did not include any value for proved undeveloped properties as had been the case for the Hazel and Warwink properties at the end of 2018. This was due to the lack of additional development intentions by the operator of the Warwink property and similar lack of intent to drill additional wells in the Hazel area by the Company which reflects the decision to focus capital and attention to development in the Orogrande area. Provision was made to maintain the Hazel leases in effect through renegotiation of the terms of the mineral leases.

 

We made investments and development progress during 2019 to further develop proved producing reserves in the Orogrande, Hazel, and Warwink Projects in the Permian Basin in West Texas. As of December 31, 2019 six test wells have been developed in the Orogrande Project and six test wells have been developed in the Hazel Project including the Flying B #3 which was in continuous production from September, 2017 to May, 2019. The Warwink Project which was initiated in 2018 has continuing production from the Warwink # 47H well which began in October, 2018.

 

Our current drilling plans, subject to sufficient capital resources and the periodic evaluation of interim drilling results and other potential investment opportunities, include drilling additional evaluation wells in the Orogrande and Hazel AMI’s to continue to derisk the prospects and obtain initial production from the development efforts. The next scheduled wells in the Hazel Project are scheduled to spud near the end of May, 2020.

 

Production, Price, and Production Cost History

 

During the year ended December 31, 2019, we produced and sold 13,784 barrels of oil net to our interest at an average sale price of $51.95 per bbl. We produced and sold 22,208 MCF of gas net to our interest at an average sales price of $1.36 per MCF. Our average production cost including lease operating expenses and direct production taxes was $25.81 per BOE. Our depreciation, depletion, and amortization expense was $251.25 per BOE.

 

During the year ended December 31, 2018, we produced and sold 22,887 barrels of oil net to our interest at an average sale price of $54.93 per bbl. We produced and sold 17,821 MCF of gas net to our interest at an average sales price of $1.41 per MCF. Our average production cost including lease operating expenses and direct production taxes was $31.17 per BOE. Our depreciation, depletion, and amortization expense was $45.39 per BOE.

 

The changes in production, revenue, and operating costs for 2019 as compared to 2018 were impacted by the production from the Flying B #3 well in the Hazel Project which began in late September, 2017 but was suspended in May, 2019 due to the high operating cost driven by lack of infrastructure in the field. Production from the Warwink 47 H began in October, 2018 and continued through 2019.

 

Our 2019 production was from properties located in central Oklahoma and in west Texas. Reserves at the end of 2019 were 100% from the Warwink properties in west Texas. For 2019, approximately 1,367 BOE was produced in Oklahoma and 16,120 BOE produced in Texas, or 8% from Oklahoma and 92% from wells in west Texas.

23

 

ITEM 2. PROPERTIES - continued

 

Quarterly Revenue and Production by State for 2019 and 2018 are detailed as follows:

 

Property  Quarter  Oil Production {BBLS}  Gas Production {MCF}  Oil Revenue   Gas Revenue   Total Revenue 
                      
Oklahoma  Q1 - 2019  56  1,072  $2,567   $2,333   $4,900 
Hazel (TX)  Q1 - 2019  2,864  0   131,901    -    131,901 
MECO (TX)  Q1 - 2019  3,525  2,565   167,677    6,359    174,036 
Total Q1-2019     6,445  3,637  $302,145   $8,692   $310,837 
                         
Oklahoma  Q2 - 2019  43  1,770  $2,477   $2,450   $4,927 
Hazel (TX)  Q2 - 2019  1,123  0   64,302    -    64,302 
Meco (TX)  Q2 - 2019  2,585  2,623   156,259    11,587    167,846 
Total Q2-2019     3,751  4,393  $223,038   $14,037   $237,075 
                         
Oklahoma  Q3 - 2019  0  0  $-   $-   $- 
Hazel (TX)  Q3 - 2019  0  0  $-   $-   $- 
Meco (TX)  Q3 - 2019  1,320  4,522  $71,064   $78   $71,142 
Total Q3-2019     1,320  4,522  $71,064   $78   $71,142 
                         
Oklahoma  Q4 - 2019  166  3,766  $8,873   $1,895   $10,768 
Hazel (TX)  Q4 - 2019  0  0  $-   $-   $- 
Meco (TX)  Q4 - 2019  2,102  5,890  $110,894   $5,547   $116,441 
Total Q4-2019     2,268  9,656   119,767    7,442    127,209 
                         
2019 Year To Date     13,784  22,208  $716,014   $30,249   $746,263 
                         
Oklahoma  Q1 - 2018  72  2,008  $4,463   $5,202   $9,665 
Hazel (TX)  Q1 - 2018  7,786  0   471,498    -    471,498 
Total Q1-2018     7,858  2,008  $475,961   $5,202   $481,163 
                         
Oklahoma  Q2 - 2018  446  1,857  $10,912   $2,690   $13,602 
Hazel (TX)  Q2 - 2018  4,368  0   266,506    -    266,506 
Meco (TX)  Q2 - 2018  51  0   3,155    -    3,155 
Total Q2-2018     4,865  1,857  $280,573   $2,690   $283,263 
                         
Oklahoma  Q3 - 2018  41  2,324  $1,264   $3,845   $5,109 
Hazel (TX)  Q3 - 2018  2,283  0   123,566    -    123,566 
Meco (TX)  Q3 - 2018  0  0   -    -    - 
Total Q3-2018     2,324  2,324  $124,830   $3,845   $128,675 
                         
Oklahoma  Q4 - 2018  94  986  $4,878   $1,104   $5,982 
Hazel (TX)  Q4 - 2018  3,779  0   178,015    -    178,015 
Meco (TX)  Q4 - 2018  3,967  10,646   192,916    12,348    205,264 
Total Q4-2018     7,840  11,632  $375,809   $13,452   $389,261 
                         
2018 Year To Date     22,887  17,821  $1,257,173   $25,189   $1,282,362 

24

 

ITEM 2. PROPERTIES - continued

 

Drilling Activity and Productive Wells

 

Combined Well Status

 

The following table summarizes development activity and Well Status as of December 31, 2019:

 

   Cumulative Well Status   Developed   Cumulative Well Status 
   at 12/31/2019   2019   at 12/31/2018 
Drilling Activity/Well Status  Gross   Net   Gross   Net   Gross   Net 
                         
Development Wells:                              
Productive -Texas (Hazel)   1.00    0.80    -    -    1.00    0.80 
Productive -Texas (Warwink)   1.00    0.13    -    -    1.00    0.13 
Productive - Okla   2.00    0.40    -    -    2.00    0.40 
Test Wells - Orogrande   9.00    5.69    3.00    2.03    6.00    3.66 
Test Wells - Hazel   6.00    4.80    2.00    1.60    4.00    3.20 
                               
Exploration Wells:                              
Productive   -    -    -    -    -    - 
Dry   -    -    -    -    -    - 
                               
Total Drilled Wells:                              
Productive -Texas   2.00    0.93    -    -    2.00    0.93 
Productive - Okla   2.00    0.40    -    -    2.00    0.40 
Test Wells   15.00    10.49    5.00    3.63    10.00    6.86 
                               
Acquired Wells:                              
Productive -Texas   -    -    -    -    -    - 
Productive - Okla   -    -    -    -    -    - 
                               
Total Wells:                              
Productive -Texas   2.00    0.93    -    -    2.00    0.93 
Productive - Okla   2.00    0.40    -    -    2.00    0.40 
Test Wells   15.00    10.49    5.00    3.63    10.00    6.86 
                               
Total   19.00    11.82    5.00    3.63    14.00    8.19 
                               
Well Type:                              
Oil   -    -    -    -    -    - 
Gas   -    -    -    -    -    - 
Combination -Oil and Gas   4.00    1.33    -    -    4.00    1.33 
Test Wells   15.00    10.49    5.00    3.63    10.00    6.86 
                               
Total   19.00    11.82    5.00    3.63    14.00    8.19 

25

 

ITEM 2. PROPERTIES - continued

 

Our acreage positions at December 31, 2019 are summarized as follows:

 

           TRCH Interest   TRCH Interest 
   Total Acres   Developed Acres   Undeveloped Acres 
Leasehold Interests - 12/31/2019  Gross   Net   Gross   Net   Gross   Net 
                         
Texas -                              
Orogrande   133,000    96,425    -    -    133,000    96,425 
Hazel Project   12,000    9,600    320    256    11,680    9,344 
Warwink Properties   1,400    175    1,400    175    -    - 
                               
Oklahoma -                              
Viking   640    192    640    192    -    - 
                               
Total   147,040    106,392    2,360    623    144,680    105,769 

 

Current Projects

 

As of December 31, 2019, we had interests in four oil and gas projects: the Orogrande Project in Hudspeth County, Texas, the Hazel Project in Sterling, Tom Green, and Irion Counties, Texas, the Winkler Project in Winkler County, Texas, and the Hunton wells in partnership with Husky Ventures in central Oklahoma.

 

See the description under “Current Projects” below under Note 4, “Oil & Gas Properties,” of the financial statements included with this report for information and disclosure regarding these projects, which description is incorporated herein by reference.

 

ITEM 3. LEGAL PROCEEDINGS

 

On January 31, 2020, Torchlight Energy Resources, Inc. and its wholly owned subsidiaries Torchlight Energy, Inc. and Torchlight Energy Operating, LLC were served with a lawsuit brought by Goldstone Holding Company, LLC (Goldstone Holding Company, LLC v. Torchlight Energy, Inc., et al., in the 160th Judicial District Court of Dallas County, Texas). On February 24, 2020, Torchlight Energy Resources, Inc., Torchlight Energy, Inc., and Torchlight Energy Operating, LLC timely filed their answer, affirmative defenses, and requests for disclosure. The suit, which seeks monetary relief over $1 million, makes unspecified allegations of misrepresentations involving a November 2015 participation agreement and a 2016 amendment to the participation agreement. We have denied the allegations and have asserted several affirmative defenses including but not limited to, that the suit is barred by the applicable statute of limitations, that the claims have been released, and that the claims are barred because of contractual disclaimers between sophisticated parties.

 

ITEM 4. MINE SAFETY DISCLOSURES

 

Not Applicable.

26

 

PART II

 

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

 

Our common stock is quoted on The NASDAQ Stock Market LLC under the symbol, “TRCH.” Trading in our common stock has historically been limited and occasionally sporadic and the quotations set forth below are not necessarily indicative of actual market conditions.

 

Record Holders

 

As of March 8, 2020, there were approximately 225 stockholders of record of our common stock, and we estimate that there were approximately 4,100 additional beneficial stockholders who hold their shares in “street name” through a brokerage firm or other institution. As of March 15, 2020, we have a total of 71,695,865 shares of common stock issued and outstanding.

 

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

 

Equity Compensation Plan Information

 

The following table sets forth all equity compensation plans as of December 31, 2019:

 

           Number of 
           securities 
           remaining 
           available 
           for future 
   Number of       issuance 
   securities to   Weighted-   under 
   be issued   average   equity 
   upon   exercise   compensation 
   exercise of   price of   plans 
   outstanding   outstanding   (excluding 
   options,   options,   securities 
   warrants   warrants   reflected in 
Plan Category  and rights   and rights   column (a)) 
Equity compensation plans approved by security holders   6,917,768   $1.39    3,082,232 

 

ITEM 6. SELECTED FINANCIAL DATA

 

Not Applicable.

27

 

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

 

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

 

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

 

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.

 

During the year ended December 31, 2016 the Board of Directors initiated a review of Company operations in view of the divestiture of its Oklahoma properties, which included the previous sale of the Chisholm Trail and Cimarron properties. During 2016 development had continued on the Orogrande Project in West Texas and in April, 2016, the Company acquired the Hazel Project in the Midland Basin also in West Texas. These West Texas properties demonstrate significant potential and future production capabilities based upon the analysis of scientific data being gathered in the day by day development activity. Therefore, the Board has determined to focus its efforts and capital on these projects to maximize shareholder value for the long run.

 

During 2017 the Company increased its commitment to the Orogrande and Hazel Projects. Additional working interests were acquired and test wells were drilled on the properties which is detailed in the Properties section of this filing. Near the end of 2017 the Warwink Project, also in West Texas, was acquired.

 

During 2018 the Company continued development in the Orogrande and Hazel Projects. Additional test wells were drilled to capture additional science data to support lease value. Production from the Hazel Flying B #3 continued through 2018. The carried well provision of the Warwink acquisition in 2017 was fulfilled with the drilling of the Warwink #47-H. That well began production in October, 2018.

 

During 2019 the Company continued development in the Orogrande Project. Additional test wells were drilled to capture additional science data to support lease value.

 

The strategy in divesting of projects other than the Orogrande Project was to refocus on the greatest potential future value for the Company while systematically eliminating debt as noncore assets are sold and operations are streamlined.

 

The following discussion of our financial condition and results of operations should be read in conjunction with our audited financial statements for the years ended December 31, 2019 and 2018 included herewith. This discussion should not be construed to imply that the results discussed herein will necessarily continue into the future, or that any conclusion reached herein will necessarily be indicative of actual operating results in the future. Such discussion represents only the best present assessment by our management.

 

Historical Results for the Years Ended December 31, 2019 and 2018

 

For the year ended December 31, 2019, we had a net loss of $9,839,396 compared to a net loss of $5,806,612 for the year ended December 31, 2018. The difference is primarily due to a decrease in revenues, increased general and administrative and, depreciation, depletion and amortization expenses and impairment loss.

 

Revenues and Cost of Revenues

 

For the year ended December 31, 2019, we had production revenue of $746,263 compared to $1,282,362 of production revenue for the year ended December 31, 2018. Refer to the table of production and revenue for 2019 and 2018 included below. Our cost of revenue, consisting of lease operating expenses and production taxes, was $451,325, and $806,158 for the years ended December 31, 2019 and 2018, respectively.

 

The change in revenue was primarily impacted by the suspension of production from the Flying B #3 well in the Hazel Project in May, 2019.

28

 

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

 

Production and Revenue are detailed as follows:

 

Property  Quarter  Oil Production {BBLS}  Gas Production {MCF}  Oil Revenue   Gas Revenue   Total Revenue 
                      
Oklahoma  Q1 - 2019  56  1,072  $2,567   $2,333   $4,900 
Hazel (TX)  Q1 - 2019  2,864  0   131,901    -    131,901 
MECO (TX)  Q1 - 2019  3,525  2,565   167,677    6,359    174,036 
Total Q1-2019     6,445  3,637  $302,145   $8,692   $310,837 
                         
Oklahoma  Q2 - 2019  43  1,770  $2,477   $2,450   $4,927 
Hazel (TX)  Q2 - 2019  1,123  0   64,302    -    64,302 
Meco (TX)  Q2 - 2019  2,585  2,623   156,259    11,587    167,846 
Total Q2-2019     3,751  4,393  $223,038   $14,037   $237,075 
                         
Oklahoma  Q3 - 2019  0  0  $-   $-   $- 
Hazel (TX)  Q3 - 2019  0  0  $-   $-   $- 
Meco (TX)  Q3 - 2019  1,320  4,522  $71,064   $78   $71,142 
Total Q3-2019     1,320  4,522  $71,064   $78   $71,142 
                         
Oklahoma  Q4 - 2019  166  3,766  $8,873   $1,895   $10,768 
Hazel (TX)  Q4 - 2019  0  0  $-   $-   $- 
Meco (TX)  Q4 - 2019  2,102  5,890  $110,894   $5,547   $116,441 
Total Q4-2019     2,268  9,656   119,767    7,442    127,209 
                         
2019 Year To Date     13,784  22,208  $716,014   $30,249   $746,263 
                         
Oklahoma  Q1 - 2018  72  2,008  $4,463   $5,202   $9,665 
Hazel (TX)  Q1 - 2018  7,786  0   471,498    -    471,498 
Total Q1-2018     7,858  2,008  $475,961   $5,202   $481,163 
                         
Oklahoma  Q2 - 2018  446  1,857  $10,912   $2,690   $13,602 
Hazel (TX)  Q2 - 2018  4,368  0   266,506    -    266,506 
Meco (TX)  Q2 - 2018  51  0   3,155    -    3,155 
Total Q2-2018     4,865  1,857  $280,573   $2,690   $283,263 
                         
Oklahoma  Q3 - 2018  41  2,324  $1,264   $3,845   $5,109 
Hazel (TX)  Q3 - 2018  2,283  0   123,566    -    123,566 
Meco (TX)  Q3 - 2018  0  0   -    -    - 
Total Q3-2018     2,324  2,324  $124,830   $3,845   $128,675 
                         
Oklahoma  Q4 - 2018  94  986  $4,878   $1,104   $5,982 
Hazel (TX)  Q4 - 2018  3,779  0   178,015    -    178,015 
Meco (TX)  Q4 - 2018  3,967  10,646   192,916    12,348    205,264 
Total Q4-2018     7,840  11,632  $375,809   $13,452   $389,261 
                         
2018 Year To Date     22,887  17,821  $1,257,173   $25,189   $1,282,362 

29

 

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

 

We recorded depreciation, depletion and amortization expense of $4,393,160 for the year ended December 31, 2019 compared to $1,173,752 for 2018. Impairment expense recognized was $1,494,769 in 2019 compared to $139,891 for 2018. Although we had no recognized impairment expense in 2017, the Company has adjusted the separation of evaluated versus unevaluated costs within its full cost pool to recognize the value impairment related to the expiration of unevaluated leases in 2017 in the amount of $2,300,626. The impact of this change was to increase the basis for calculation of future period’s depletion, depreciation and amortization to include $2,300,626 of cost which will effectively recognize the impairment on the Statement of Operations over future periods. The $2,300,626 became an evaluated cost for purposes of future period’s Ceiling Tests and which may further recognize the impairment expense recognized in future periods. An additional impairment of unevaluated costs of $756,964 was recorded at December 31, 2019 which has also become an addition to the basis for future depreciation, depletion, and amortization expense.

 

General and Administrative Expenses

 

Our general and administrative expenses for the years ended December 31, 2019 and 2018 were $3,273,697 and $4,053,062, respectively, a decrease of $779,365. Our general and administrative expenses consisted of consulting and compensation expense, substantially all of which were non-cash or deferred, accounting and administrative costs, professional consulting fees, and other general corporate expenses. The decrease in general and administrative expenses for the year ended December 31, 2019 compared to 2018 is detailed as follows:

 

Increase (decrease) in non cash stock and warrant compensation  $(397,853)
Increase (decrease) in consulting expense   27,857 
Increase (decrease) in investor relations   (88,847)
Increase (decrease) in travel expense   26,886 
Increase (decrease) in salaries and compensation   (192,702)
Increase (decrease) in legal fees   17,070 
Increase (decrease) in filing and compliance fees   (94,593)
Increase (decrease) in insurance   (24,990)
Increase (decrease) in rent   (30,233)
Increase (decrease) in audit fees   (72,936)
Increase (decrease) in general corporate expenses   50,976 
      
Total Decrease in General and Administrative Expenses  $(779,365)

 

The decrease in noncash stock and warrant compensation arises from the combination of a decrease in vested employee stock options expense, an decrease in expense related to warrants issued by the company, and an increase in the value of common stock issued for services. Consulting expense and investor relations expense changes are due to fees related to capital raise activity in 2019. Legal fees increased from prior years due to an increase in transaction activity.

 

Liquidity and Capital Resources

 

For the year ended December 31, 2019, we had a net loss of $9,839,396 compared to a net loss of $5,806,612 for the year ended December 31, 2018.

 

At December 31, 2019, we had current assets of $735,744 and total assets of $40,924,135. As of December 31, 2019, we had current liabilities of $13,962,486. Stockholders’ equity was $15,066,396 at December 31, 2019.

 

Cash from operating activities for the year ended December 31, 2019, was $(141,933) compared to $(1,168,524) for the year ended December 31, 2018, an increase of $1,026,591. Cash from operating activities during 2019 can be attributed principally to net loss from operations of $9,839,396 adjusted for noncash stock based compensation of $942,470, for $4,393,160 in depreciation, depletion and amortization expense, and 1,494,769 in impairment expense.

 

Cash used in operating activities during 2018 can be attributed principally to net losses from operations of $5,806,612 adjusted for noncash stock based compensation of $1,340,324, depreciation, depletion and amortization expense of $1,173,752, and an increase in prepayments for development costs of $1,189,230.

 

Cash used in investing activities for year ended December 31, 2019 was $8,790,222 compared to $12,149,916 for the year ended December 31, 2018. Cash used in investing activities consisted primarily of investments in oil and gas properties during the year ended December 31, 2019 and 2018.

30

 

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

 

Cash from financing activities for the year ended December 31, 2019 was $8,181,722 as compared to $13,106,883 for the year ended December 31, 2018. Cash from financing activities in 2019 and 2018 consisted primarily of proceeds from common stock issuances and debt financing. We expect to continue to have cash provided by financing activities as we seek new rounds of financing and continue to develop our oil and gas investments. Reference Note 11 to the Financial Statements regarding additional funding closed subsequent to December 31, 2019.

 

Our current assets are insufficient to satisfy our cash needs over the next twelve months and as such we will require additional debt or equity financing to meet our plans and needs. We face obstacles in continuing to attract new financing due to our history and current record of net losses and past working capital deficits. Despite our efforts, we can provide no assurance that we will be able to obtain the financing required to meet our stated objectives or even to continue as a going concern.

 

We do not expect to pay cash dividends on our common stock in the foreseeable future.

 

Critical Accounting Policies and Estimates

 

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. Unevaluated properties are reviewed for impairment at least annually and are determined through an evaluation considering, among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plan, and political, economic, and market conditions.

 

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

 

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 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.

 

Asset retirement obligations – The fair value of a liability for an asset’s retirement obligation (“ARO”) is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, with the corresponding charge 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 costs incurred are recorded as a reduction of the ARO liability.

31

 

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

 

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.

 

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.

 

The Company accounts for stock option awards using the calculated value method. The expected term was derived using the simplified method provided in Securities and Exchange Commission release Staff Accounting Bulletin No. 110, which averages an awards weighted average vesting period and contractual term for “plain vanilla” share options.

 

The Company accounts for any forfeitures of options when they occur. Previously recognized compensation cost for an award is reversed in the period that the award is forfeited.

 

The Company also issues equity awards to non-employees. The fair value of these option awards is estimated when the award recipient completes the contracted professional services. The Company recognizes expense for the estimated total value of the awards during the period from their issuance until performance completion.

 

In June 2018, the FASB issued ASU 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting, which simplifies the accounting for share-based payments granted to nonemployees for goods and services. Under this ASU, the guidance on such payments to nonemployees is aligned with the requirements for share-based payments granted to employees. ASU 2018-07 is effective for fiscal years beginning after December 15, 2018, however the Company has opted for early adoption effective July 1, 2018. The amendments in this ASU are to be applied through a cumulative-effect adjustment to retained earnings as of the first reporting period in which the ASU is effective. In evaluating early adoption the Company has determined that the change did not have a material impact on its consolidated financial statements.

 

The Company values warrant and option awards using the Black-Scholes option pricing model.

 

Commitments and Contingencies

 

Leases

 

The Company had a noncancelable lease for its office premises that expired on November 30, 2019. Effective June 1, 2019 the Company entered into an agreement with a company that had been subleasing a portion of its office space to become the primary obligor on the lease and to assume full responsibility for lease payments after lease expiration on November 30, 2019. The Company continued after November 30, 2019 as a subtenant on a month-to-month basis.

 

As of December 31, 2019, the Company had interests in four oil and gas projects: the Orogrande Project in Hudspeth County, Texas, the Hazel Project in Sterling, Tom Green, and Irion Counties, Texas, the Warwink Project in Winkler County, Texas, and Hunton wells in Central Oklahoma.

 

See the description under “Current Projects” below under Note 4, “Oil & Gas Properties,” of the financial statements included with this report for information and disclosure regarding these projects, which description is incorporated herein by reference.

 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Not Applicable.

32

 

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and

 

Stockholders of Torchlight Energy Resources, Inc.

 

Plano, Texas

 

Opinions on the Financial Statements and Internal Control over Financial Reporting

 

We have audited the accompanying consolidated balance sheets of Torchlight Energy Resources, Inc. (the Company) as of December 31, 2019 and 2018, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2019, and the related notes (collectively referred to as the financial statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control—Integrated Framework (2013) issued by COSO.

 

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has incurred recurring losses from its operations, has negative working capital, a significant accumulated deficit, and a number of notes payable maturing over the next 12 months, which raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

Basis for Opinion

 

The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Item 9A, “Management’s Annual Report on Internal Control Over Financial Reporting.” Our responsibility is to express an opinion on the Company’s financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

 

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

 

Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

 

Definition and Limitations of Internal Control over Financial Reporting

 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

 

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

 

/s/ Briggs & Veselka Co.

 

We have served as the Company’s auditor since 2016.

 

Houston, Texas

 

March 16, 2020

33

 

TORCHLIGHT ENERGY RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS

 

   December 31,   December 31, 
   2019   2018 
ASSETS          
Current assets:          
Cash  $89,730   $840,163 
Accounts receivable   199,462    179,702 
Production revenue receivable   100,546    294,715 
Subscription receivable   250,000    - 
Prepayments - development costs   -    146,422 
Prepaid expenses   96,006    60,980 
Total current assets   735,744    1,521,982 
           
Oil and gas properties, net   40,182,043    36,565,461 
Office equipment, net   6,348    4,076 
Other assets   -    6,362 
           
TOTAL ASSETS  $40,924,135   $38,097,881 
           
LIABILITIES AND STOCKHOLDERS’ EQUITY          
Current liabilities:          
Accounts payable  $1,444,002   $729,806 
12% 2020 Unsecured promissory notes, net of $127,170 of discount and financing costs   8,437,127    - 
10% 2021 Convertible promissory notes payable   540,000    - 
Notes payable   2,000,000    - 
Accrued payroll   996,176    816,176 
Related party payables   45,000    45,000 
Due to working interest owners   54,320    54,320 
Accrued interest payable   445,861    553,370 
Total current liabilities   13,962,486    2,198,672 
           
12% 2021 Unsecured promissory notes, net of $59,297 of discount and financing costs   3,940,703    11,862,080 
8% 2021 Convertible promissory notes payable, net of $1,186,029 of discount and BCF   773,971    - 
Notes payable and accrued interest   7,157,260    6,000,000 
Asset retirement obligations   23,319    14,353 
           
Total liabilities   25,857,739    20,075,105 
           
Commitments and contingencies          
           
Stockholders’ equity:          
Preferred stock, par value $0.001, 10,000,000 shares authorized; -0- issued and outstanding at December 31, 2019 and December 31, 2018   -    - 
Common stock, par value $0.001 per share; 150,000,000 shares authorized; 76,222,042 issued and outstanding at December 31, 2019; 70,112,376 issued and outstanding at December 31, 2018   76,225    70,116 
Additional paid-in capital   114,143,872    107,266,965 
Accumulated deficit   (99,153,701)   (89,314,305)
Total stockholders’ equity   15,066,396    18,022,776 
           
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY  $40,924,135   $38,097,881 

 

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

34

 

TORCHLIGHT ENERGY RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS

 

   Year   Year 
   Ended   Ended 
   December 31,   December 31, 
   2019   2018 
Oil and gas sales  $746,263   $1,282,362 
Cost of revenues   (451,325)   (806,158)
Gross profit   294,938    476,204 
           
Operating expenses:          
General and administrative   3,273,697    4,053,062 
Depreciation, depletion and amortization   4,393,160    1,173,752 
Loss on settlement   -    369,439 
Impairment loss   1,494,769    139,891 
Total operating expenses   9,161,626    5,736,144 
           
Other income (expense)          
Interest expense and accretion of note discounts   (968,292)   (547,710)
Franchise tax   (4,441)   - 
Interest income   25    1,038 
Total (expense), net   (972,708)   (546,672)
           
Loss before income taxes   (9,839,396)   (5,806,612)
           
Provision for income taxes   -    - 
           
Net loss  $(9,839,396)  $(5,806,612)
           
Loss per common share:          
Basic and Diluted  $(0.14)  $(0.09)
Weighted average number of common shares outstanding:          
Basic and Diluted   72,857,079    68,134,745 

 

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

35

 

TORCHLIGHT ENERGY RESOURCES, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
YEARS ENDED DECEMBER 31, 2019 AND 2018

 

   Common
stock
shares
   Common
stock
shares
   Additional
paid-in
capital
   Accumulated
deficit
   Total 
Balance, December 31, 2017   63,340,034   $63,344   $99,403,654   $(83,507,693)  $15,959,305 
                          
Issuance of common stock for services   450,000    450    544,550    -    545,000 
Issuance of common stock for cash less Underwriting/Offering Costs   5,750,000    5,750    6,043,984    -    6,049,734 
Issuance of common stock for note payment in kind   172,342    172    220,852    -    221,024 
Warrant exercise into common stock   400,000    400    199,600    -    200,000 
Warrants issued for services   -    -    510,575    -    510,575 
Stock options issued for services   -    -    343,750    -    343,750 
Net loss   -    -    -    (5,806,612)   (5,806,612)
                          
Balance, December 31, 2018   70,112,376   $70,116   $107,266,965   $(89,314,305)  $18,022,776 
                          
Issuance of common stock for services   312,593    312    365,088    -    365,400 
Issuance of common stock for cash less Underwriting/Offering Costs   4,696,100    4,696    3,508,221    -    3,512,917 
Issuance of common stock for subscription   416,667    417    183,546    -    183,963 
Issuance of common stock for interest   167,845    169    183,545    -    183,714 
Issuance of common stock for payment in kind on note payable   202,316    202    313,906    -    314,108 
Issuance of common stock for oil and gas lease extension   100,000    100    124,900    -    125,000 
Beneficial conversion feature on convertible notes   -    -    1,145,546    -    1,145,546 
Debt discount from fair value of warrants issued with convertible notes   -    -    240,455    -    240,455 
Issuance of common stock for convertible note conversion   45,455    45    49,955    -    50,000 
Warrant/Option exercise into common stock   168,690    168    184,675    -    184,843 
Warrants issued for services   -    -    340,570    -    340,570 
Stock options issued for services   -    -    236,500    -    236,500 
Net loss                  (9,839,396)   (9,839,396)
                          
Balance, December 31, 2019   76,222,042   $76,225   $114,143,872   $(99,153,701)  $15,066,396 

 

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

36

 

TORCHLIGHT ENERGY RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

 

   Year   Year 
   Ended   Ended 
   December 31, 2019   December 31, 2018 
Cash Flows From Operating Activities          
Net loss  $(9,839,396)  $(5,806,612)
Adjustments to reconcile net loss to net cash from operations:          
Stock based compensation   942,470    1,340,324 
Stock issued for interest payments on notes payable   183,714    228,057 
Amortization of debt issuance costs   286,584    268,917 
Bad debt expense   34,500    - 
Accretion of debt discounts   429,138    216,732 
Accrued interest payable in stock   228,057    - 
Depreciation, depletion and amortization   4,393,160    1,173,752 
Net settlement offset   -    (100,561)
Impairment loss   1,494,769    139,891 
Change in:          
Accounts receivable   (54,260)   (3,400)
Production revenue receivable   194,169    (151,783)
Prepayments - development costs   146,422    1,189,230 
Prepaid expenses   (35,026)   (21,474)
Other assets   6,362    - 
Accounts payable and accrued expenses   311,603    14,116 
Accrued interest payable   1,135,801    344,287 
Net cash from operating activities   (141,933)   (1,168,524)
           
Cash Flows From Investing Activities          
Investment in oil and gas properties   (8,783,658)   (12,149,916)
Purchases of property, plant, and equipment   (6,564)   - 
Net cash from investing activities   (8,790,222)   (12,149,916)
           
Cash Flows From Financing Activities          
Issuance of common stock   3,446,880    6,049,734 
Proceeds from convertible promissory notes   539,999    4,107,149 
Repayment of promissory notes   -    (3,250,000)
Proceeds from notes payable   4,010,000    6,000,000 
Proceeds from exercise of warrants into common stock   184,843    200,000 
Net cash from financing activities   8,181,722    13,106,883 
           
Net (decrease) in cash   (750,433)   (211,557)
           
Cash - beginning of year   840,163    1,051,720 
           
Cash - end of year  $89,730   $840,163 
           
Supplemental disclosure of cash flow information: (Non Cash Items)          
           
Common stock issued for oil and gas lease extension  $125,000   $- 
Common stock issued for partial payment of unpaid compensation  $-   $59,000 
Common stock issued for payment in kind on notes payable  $314,108   $221,024 
Common stock issued in conversion of convertible note principal  $50,000   $- 
Subscription receivable for sale of common stock  $250,000   $- 
(Increase) in accounts payable for property development costs  $(520,094)  $(133,189)
Beneficial conversion feature on convertible notes  $1,145,546   $- 
Debt discount from fair value of warrants issued with convertible notes  $240,455   $- 
Cash paid for interest  $1,554,510   $1,519,573 
Cash paid for state franchise tax  $4,441   $- 

 

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

37

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1. NATURE OF BUSINESS

 

Torchlight Energy Resources, Inc. (“Company”) 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. We operate our business through our subsidiaries Torchlight Energy Inc., Torchlight Energy Operating, LLC, Hudspeth Oil Corporation, Torchlight Hazel LLC, and Warwink Properties LLC.

 

2. GOING CONCERN

 

At December 31, 2019, the Company had not yet achieved profitable operations. We had a net loss of $9,839,396 for the year ended December 31, 2019 and had accumulated losses of $99,153,701 since our inception. We expect to incur further losses in the development of our business. The Company had a working capital deficit as of December 31, 2019 of $13,226,742. These conditions raise substantial doubt about the Company’s ability to continue as a going concern.

 

The Company’s ability to continue as a going concern is dependent on its ability to generate future profitable operations and/or to obtain the necessary financing to meet its obligations and repay its liabilities arising from normal business operations when they come due. Management’s plan to address the Company’s ability to continue as a going concern includes: (1) obtaining debt or equity funding from private placement or institutional sources; (2) obtain loans from financial institutions, where possible, or (3) participating in joint venture transactions with third parties. Although management believes that it will be able to obtain the necessary funding to allow the Company to remain a going concern through the methods discussed above, there can be no assurances that such methods will prove successful.

 

These consolidated financial statements have been prepared assuming that the Company will continue as a going concern and therefore, the financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amount and classifications of liabilities that may result from the outcome of this uncertainty.

 

3. SIGNIFICANT ACCOUNTING POLICIES

 

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

 

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

 

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, Hudspeth Oil Corporation, Torchlight Hazel LLC, and Warwink Properties LLC. All significant intercompany balances and transactions have been eliminated.

38

 

TORCHLIGHT ENERGY RESOURCES, INC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

3. SIGNIFICANT ACCOUNTING POLICIES - continued

 

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

 

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

 

Fair value of financial instruments – Financial instruments consist of cash, receivables, payables and promissory notes, if any. The estimated fair values of cash, receivables, and payables approximate the carrying amount due to the relatively short maturity of these instruments. The carrying amounts of any 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.

 

Cash and cash equivalents – Cash and cash equivalents include certain investments in highly liquid instruments with original maturities of three months or less.

 

Accounts receivable – Accounts receivable consist of uncollateralized oil and natural gas revenues due under normal trade terms, as well as amounts due from working interest owners of oil and gas properties for their share of expenses paid on their behalf by the Company. Management reviews receivables periodically and reduces the carrying amount by a valuation allowance that reflects management’s best estimate of the amount that may not be collectible. As of December 31, 2019 and 2018, no valuation allowance was considered necessary.

 

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. Unevaluated properties are reviewed for impairment at least annually and are determined through an evaluation considering, among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plan, and political, economic, and market conditions.

 

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

39

 

TORCHLIGHT ENERGY RESOURCES, INC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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 years ended December 31, 2019 and 2018, the Company capitalized $2,858,753 and $2,020,019, 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 realizable 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 Company recorded an impairment expense of $1,494,769 and $139,891 for the years ended December 31, 2019 and 2018, respectively, to recognize the adjustment required by the ceiling test. At December 31, 2019 an additional impairment of unevaluated costs of $756,964 was added to the basis for future period’s depletion.

 

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 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 of 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.

 

Asset retirement obligations – The fair value of a liability for an asset’s retirement obligation (“ARO”) is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, with the corresponding charge 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 costs incurred are recorded as a reduction of 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.

 

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.

 

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. Company tax returns remain subject to Federal and State tax examinations. Generally, the applicable statutes of limitation are three to four years from their respective filings.

40

 

TORCHLIGHT ENERGY RESOURCES, INC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

3. SIGNIFICANT ACCOUNTING POLICIES - continued

 

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 operations. The Company has not recorded any interest or penalties associated with unrecognized tax benefits for any periods covered by these financial statements.

 

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.

 

The Company accounts for stock option awards using the calculated value method. The expected term was derived using the simplified method provided in Securities and Exchange Commission release Staff Accounting Bulletin No. 110, which averages an awards weighted average vesting period and contractual term for “plain vanilla” share options.

 

The Company accounts for any forfeitures of options when they occur. Previously recognized compensation cost for an award is reversed in the period that the award is forfeited.

 

The Company also issues equity awards to non-employees. The fair value of these option awards is estimated when the award recipient completes the contracted professional services. The Company recognizes expense for the estimated total value of the awards during the period from their issuance until performance completion.

 

In June 2018, the FASB issued ASU 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting, which simplifies the accounting for share-based payments granted to nonemployees for goods and services. Under this ASU, the guidance on such payments to nonemployees is aligned with the requirements for share-based payments granted to employees. ASU 2018-07 was effective for fiscal years beginning after December 15, 2018, however the Company opted for early adoption effective July 1, 2018. In evaluating early adoption the Company determined that the change did not have a material impact on its consolidated financial statements.

 

The Company values warrant and option awards using the Black-Scholes option pricing model.

 

Revenue recognition – On January 1, 2018, the Company adopted ASC 606, Revenue from Contracts with Customers, and the related guidance in ASC 340-40 (the new revenue standard), and related guidance on gains and losses on derecognition of nonfinancial assets ASC 610-20, using the modified retrospective method applied to those contracts which were not completed as of January 1, 2018. Under the modified retrospective method, the Company recognizes the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of retained earnings; however, no significant adjustment was required as a result of adopting the new revenue standard. Results for reporting periods beginning after January 1, 2018 are presented under the new revenue standard. The impact of the adoption of the new revenue standard was immaterial to the Company’s net loss.

 

The Company’s revenue is typically generated from contracts to sell natural gas, crude oil or NGLs produced from interests in oil and gas properties owned by the Company. Contracts for the sale of natural gas and crude oil are evidenced by (1) base contracts for the sale and purchase of natural gas or crude oil, which document the general terms and conditions for the sale, and (2) transaction confirmations, which document the terms of each specific sale. The transaction confirmations specify a delivery point which represents the point at which control of the product is transferred to the customer. These contracts frequently meet the definition of a derivative under ASC 815, and are accounted for as derivatives unless the Company elects to treat them as normal sales as permitted under that guidance. The Company elects to treat contracts to sell oil and gas production as normal sales, which are then accounted for as contracts with customers. The Company has determined that these contracts represent multiple performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point.

41

 

TORCHLIGHT ENERGY RESOURCES, INC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

3. SIGNIFICANT ACCOUNTING POLICIES - continued

 

Revenues from oil and gas sales are detailed as follows:

 

   Year   Year 
   Ended   Ended 
   December 31,   December 31, 
   2019   2018 
Revenues          
           
Oil sales  $716,014   $1,257,173 
           
Gas sales   30,249    25,189 
           
Total  $746,263   $1,282,362 

 

Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. The Company recognizes revenue in the amount that reflects the consideration it expects to be entitled to in exchange for transferring control of those goods to the customer. Amounts allocated in the Company’s price contracts are based on the standalone selling price of those products in the context of long-term contracts. Payment is generally received one or two months after the sale has occurred. 

 

Gain or loss on derivative instruments is outside the scope of ASC 606 and is not considered revenue from contracts with customers subject to ASC 606. The Company may in the future use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales, or in limited cases may use them for contracts the Company intends to physically settle but do not meet all of the criteria to be treated as normal sales.

 

Producer Gas Imbalances. The Company applies the sales method of accounting for natural gas revenues. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers.

 

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 calculation of diluted earnings per share excludes 12,621,528 and 14,814,586 shares, respectively for the years ended December 31, 2019 and 2018, issuable upon the exercise of outstanding warrants and options because their effect 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. The Company accrued no liability as of December 31, 2019 and 2018.

 

Recent adopted accounting pronouncements – In February 2016 the FASB, issued ASU, 2016-02, Leases. The ASU requires companies to recognize on the balance sheet the assets and liabilities for the rights and obligations created by leased assets. ASU 2016-02 was effective for the Company in the first quarter of 2019. The Company adopted the change which did not have a material impact on its consolidated financial statements.

 

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

 

Subsequent events – The Company evaluated subsequent events through March 16, 2020 the date of issuance of these financial statements. Subsequent events, if any, are disclosed in Note 11.

42

 

TORCHLIGHT ENERGY RESOURCES, INC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

4. OIL & GAS PROPERTIES

 

The following table presents the capitalized costs for oil & gas properties of the Company as of December 31, 2019 and 2018:

 

   2019   2018 
Evaluated costs subject to amortization  $13,243,541   $11,664,586 
Unevaluated costs   39,667,740    31,746,477 
Total capitalized costs   52,911,281    43,411,063 
Less accumulated depreciation, depletion and amortization   (12,729,238)   (6,845,602)
Total oil and gas properties  $40,182,043   $36,565,461 

 

Unevaluated costs as of December 31, 2019 include cumulative costs on developing projects including the Orogrande, Hazel, and Winkler projects in West Texas.

 

The Company identified impairment of $2,300,626 in 2017 related to its unevaluated properties. The Company adjusted the separation of evaluated versus unevaluated costs within its full cost pool to recognize the value impairment related to the expiration of unevaluated leases in 2017 in the amount of $2,300,626. The impact of this change was to increase the basis for calculation of future period’s depletion, depreciation and amortization to include $2,300,626 of cost which will effectively recognize the impairment on the consolidated statement of operations over future periods. The $2,300,626 has also become an evaluated cost for purposes of ceiling tests and which may further recognize the impairment expense recognized in future periods. The impact of this cost reclassification at March 31, 2018 was a recognized impairment expense of $139,891. Impairment expense was recognized for the year ended December 31, 2019 of $1,494,769. At December 31, 2019 an additional impairment of unevaluated costs of $756,964 was added to the basis for future period’s depletion.

 

Due to the volatility of commodity prices, should oil and natural gas prices decline in the future, it is possible that a further 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.

 

Current Projects

 

As of December 31, 2019, we had interests in four oil and gas projects: the Orogrande Project in Hudspeth County, Texas, the Hazel Project in Sterling, Tom Green, and Irion Counties, Texas, the Winkler Project in Winkler County, Texas and the Hunton wells in partnership with Husky Ventures in central Oklahoma.

 

Orogrande Project, West Texas

 

On August 7, 2014, we entered into a Purchase Agreement with Hudspeth Oil Corporation (“Hudspeth”), McCabe Petroleum Corporation (“MPC”), and Gregory McCabe, our Chairman. 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 approximately 172,000 mostly contiguous acres in the Orogrande Basin in West Texas. As of December 31, 2017, leases covering approximately 134,000 acres remain in effect. As consideration, at closing we issued 868,750 restricted 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 has, at his option, a 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 among Hudspeth, MPC and Mr. McCabe. Mr. McCabe also holds a 4.5% overriding royalty interest in the Orogrande acreage, which he obtained prior to, and was not a part of, the August 2014 transaction. We believe all drilling obligations through December 31, 2019 have been met.

 

On September 23, 2015, Hudspeth entered into a Farmout Agreement with Pandora Energy, LP (“Pandora”), Founders Oil & Gas, LLC (“Founders”), and for the limited purposes set forth therein, MPC and Mr. McCabe, for the entire Orogrande Project in Hudspeth County, Texas. The Farmout Agreement provided that Hudspeth and Pandora (collectively referred to as “Farmor”) would assign to Founders an undivided 50% of the leasehold interest and a 37.5% net revenue interest in the oil and gas leases and mineral interests in the Orogrande Project, which interests, except for any interests retained by Founders, would be reassigned to Farmor by Founders if Founders did not spend a minimum of $45.0 million on actual drilling operations on the Orogrande Project by September 23, 2017. Under a joint operating agreement also entered into on September 23, 2015, Founders was designated as operator of the leases.

43

 

TORCHLIGHT ENERGY RESOURCES, INC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

4. OIL & GAS PROPERTIES - continued

 

On March 27, 2017, Founders, Founders Oil & Gas Operating, LLC, Founders’ operating partner, Hudspeth and Pandora signed a Drilling and Development Unit Agreement (the “DDU Agreement”), with the Commissioner of the General Land Office, on behalf of the State of Texas, and as approved by the Board for Lease of University Lands, or University Lands, on the Orogrande Project. The DDU Agreement has an effective date of January 1, 2017 and required a payment from Founders, Hudspeth and Pandora, collectively, of $335,323 as the initial consideration fee. The initial consideration fee was paid by Founders in April 2017 and was to be deducted from the required spud fee payable to us at commencement of the next well drilled.

 

The DDU Agreement allows for all 192 existing leases covering approximately 133,000 net acres leased from University Lands to be combined into one drilling and development unit for development purposes. The term of the DDU Agreement expires on December 31, 2023, and the time to drill on the drilling and development unit continues through December 2023. The DDU Agreement also grants the right to extend the DDU Agreement through December 2028 if compliance with the DDU Agreement is met and the extension fee associated with the additional time is paid. Our drilling obligations began with one well to be spudded and drilled on or before September 1, 2017, and increased to two wells in year 2018, three wells in year 2019, four wells in year 2020 and five wells per year in years 2021, 2022 and 2023. The drilling obligations are minimum yearly requirements and may be exceeded if acceleration is desired. The DDU Agreement replaces all prior agreements, and will govern future drilling obligations on the drilling and development unit if the DDU Agreement is extended. The Company drilled three wells during fourth quarter of 2019.

 

There are two vertical tests wells in the Orogrande Project, the Orogrande Rich A-11 test well and the University Founders B-19 #1 test well. The Orogrande Rich A-11 test well was spudded on March 31, 2015, drilled in the second quarter of 2015 and was evaluated and numerous scientific tests were performed to provide key data for the field development thesis. We believe that future utility of this well may be conversion to a salt water disposal well in the course of further development of the Orogrande acreage. The University Founders B-19 #1 was spudded on April 24, 2016 and drilled in the second quarter of 2016. The well successfully pumped down completion fluid in the third quarter of 2016 and indications of hydrocarbons were seen at the surface on this second Orogrande Project test well. We believe that future utility of this well may be conversion to a salt water disposal well in the course of further development of the Orogrande acreage. 

 

During the fourth quarter of 2017, the Company took back operational control from Founders on the Orogrande Project. We were joined by Wolfbone Investments, LLC, (“Wolfbone”), a company owned by Mr. McCabe. We, along with Hudspeth, Wolfbone and, for the limited purposes set forth therein, Pandora, entered into an Assignment of Farmout Agreement with Founders, (the “Assignment of Farmout Agreement”), pursuant to which we and Wolfbone will share the remaining commitments under the Farmout Agreement. All original provisions of our carried interest were to remain in place including reimbursement to us on each wellbore. Founders was to remain a 9.5% working interest owner in the Orogrande Project for the $9.5 million it had spent as of the date of the Assignment of Farmout Agreement, and such interests were to be carried until $40.5 million is spent by Wolfbone and us, with each contributing 50% of such capital spend, under the existing agreement. The Company estimates that there is still approximately $27.1 million remaining to be spent on the project until such time as the capital expenditures revert back to the percentages of the working interest owners.

 

Our working interest in the Orogrande Project thereby increased by 20.25% to a total of 67.75% and Wolfbone then owned 20.25%.

 

Founders was to operate a newly drilled horizontal well called the University Founders #A25 (at 5,540’ depth in a 1,000’ lateral) with supervision from us and our partners. The University Founders #A25 was spudded on November 28, 2017. During the month of April, 2018, we, MPC and Mr. McCabe were to assume full operational control including managing drilling plans and timing for all future wells drilled in the project.

 

On July 25, 2018, the Company and Hudspeth entered into a Settlement & Purchase Agreement (the “Settlement Agreement”) with Founders (and Founders Oil & Gas Operating, LLC), Wolfbone and MPC, which agreement provides for Hudspeth and Wolfbone to each immediately pay $625,000 and for Hudspeth or the Company and Wolfbone or MPC to each pay another $625,000 on July 20, 2019, as consideration for Founders assigning all of its working interest in the oil and gas leases of the Orogrande Project to Hudspeth and Wolfbone equally. The final payments were made on July 18, 2019. The assignments to Hudspeth and Wolfbone were made in July when the first payments were made. Future well capital spending obligations will require the same 50% contribution from Hudspeth and 50% from Wolfbone until such time as the $40.5 million to be spent on the project (as per our Assignment of Farmout Agreement with Founders) is completed. The Company estimates that there is still approximately $27.1 million remaining to be spent on the project until such time as the capital expenditures revert back to the percentages of the working interest owners.

 

After the assignment by Founders (for which Hudspeth’s total consideration was $1,250,000), Hudspeth’s working interest increased to 72.5%.

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TORCHLIGHT ENERGY RESOURCES, INC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

4. OIL & GAS PROPERTIES - continued

 

The Orogrande Project ownership as of December 31, 2019 is detailed as follows:

 

   Revenue   Working 
   Interest   Interest 
         
University Lands - Mineral Owner   20.000%   n/a 
           
ORRI - Magdalena Royalties, LLC, an entity controlled by Gregory McCabe, Chairman   4.500%   n/a 
           
ORRI - Unrelated Party   0.500%   n/a 
           
Hudspeth Oil Corporation, a subsidiary of Torchlight Energy Resources Inc.   54.375%   72.500%
           
Wolfbone Investments LLC, an entity controlled by Gregory McCabe, Chairman   18.750%   25.000%
           
Unrelated Party   1.875%   2.500%
    100.000%   100.000%

 

Reference Note 11 – Subsequent Events for the reduction of 6% in the Company’s working interest as a result of the conversion of notes payable and accrued interest into working interest in the Orogrande.

 

Rich Masterson, our consulting geologist, is credited with originating the Orogrande Project in Hudspeth County in the Orogrande Basin. With Mr. Masterson’s assistance and based on all the science we have gathered to date, we have identified multiple unconventional and conventional target pay zones with depths between 3,000’ and 8,000’ with primary pay, described as the Penn formation, located at depths of 5,300 to 5,900’. Based on our geologic analysis to date, this basin has stacked pay with zones including the Wolfcamp, Penn, Barnett, Woodford, Atoka and more. These potential zones are prospective for oil and gas with a GOR of 1100 expected based on our gathered scientific information and analysis from independent third parties.

 

During the fourth quarter, 2018, the Company drilled three additional test wells in the Orogrande in order to stay in compliance with University Lands D&D Unit Agreement, as well as, to test for potential shallow pay zones and deeper pay zones that may be present on structural plays. Development of these wells continued into the nine months ended September 30, 2019 to further capture and document the scientific base in support of demonstrating the production potential of the property. The Company is currently marketing the project for an outright sale or farm in partner. This marketing process has been long and arduous as the overall market is quite soft. In addition, due to the size and scope of the project, we are dealing with very large companies that have multitudes of people reviewing our material, which in itself is extensive. During the marketing process, the Company and Wolfbone will endeavor to complete the University Maverick A24 #1 as a potential producer in the Atoka formation. In addition, should a farm out partner or sale not occur, the Company and Wolfbone will proceed to drill two additional wells in the play prior to year-end, in order to fulfill the obligations under the DDU Agreement. We drilled to test the two obligation wells described above. The first well, the A35 1H, has been drilled and cased in the Penn Section and tested with positive results of oil and gas production to the surface. This first well is a short horizontal in the proven Penn Section where we will be looking to break through the dual porosity system in place with a larger frac designed to open up the oil bearing pores. We are also drilled and cased the A25 #2 which targeted an identified structure. This well is designed to test both conventional zones and potentially the unconventional Barnett and Woodford Zones ultimately drilling down to the cellar around 7600 feet. Testing is ongoing.

 

Hazel Project in the Midland Basin in West Texas

 

Effective April 4, 2016, TEI acquired from MPC a 66.66% working interest in approximately 12,000 acres in the Midland Basin in exchange for 1,500,000 warrants to purchase shares of our common stock with an exercise price of $1.00 for five years and a back-in after payout of a 25% working interest to MPC.

 

Initial development of the first well on the property, the Flying B Ranch #1, began July 9, 2016 and development continued through September 30, 2016. This well is classified as a test well in the development pursuit of the Hazel Project. We believe that this wellbore will be utilized as a salt water disposal well in support of future development.

 

In October 2016, the holders of all of our then-outstanding shares of Series C Preferred Stock (which were issued in July 2016) elected to convert into a total 33.33% working interest in our Hazel Project, reducing our ownership from 66.66% to a 33.33% working interest. As of December 31, 2019, no shares of our Series C Preferred Stock were outstanding.

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TORCHLIGHT ENERGY RESOURCES, INC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

4. OIL & GAS PROPERTIES - continued

 

On December 27, 2016, drilling activities commenced on the second Hazel Project well, the Flying B Ranch #2. The well is a vertical test similar to our first Hazel Project well, the Flying B Ranch #1. Recompletion in an alternative geological formation for this well was performed during the three months ended September 30, 2017; however, we believe that the results were uneconomic for continuing production. We believe that this wellbore will be utilized as a salt water disposal well in support of future development.

 

We commenced planning to drill the Flying B Ranch #3 horizontal well in the Hazel Project in June 2017 in compliance with the continuous drilling obligation. The well was spudded on June 10, 2017. The well was completed and began production in late September 2017. As of December 31, 2019 the well is shut in due to high lease operating expenses as a result of lack of three phase electricity to the property which forced the use of diesel generation equipment to power the production facilities.

 

Acquisition of Additional Interests in Hazel Project

 

On January 30, 2017, we and our then wholly-owned subsidiary, Torchlight Acquisition Corporation, a Texas corporation (“TAC”), entered into and closed an Agreement and Plan of Reorganization and a Plan of Merger with Line Drive Energy, LLC, a Texas limited liability company (“Line Drive”), and Mr. McCabe, under which agreements TAC merged with and into Line Drive and the separate existence of TAC ceased, with Line Drive being the surviving entity and becoming our wholly-owned subsidiary. Line Drive, which was wholly-owned by Mr. McCabe, owned certain assets and securities, including approximately 40.66% of 12,000 gross acres, 9,600 net acres, in the Hazel Project and 521,739 warrants to purchase shares of our common stock (which warrants had been assigned by Mr. McCabe to Line Drive). Upon the closing of the merger, all of the issued and outstanding shares of common stock of TAC automatically converted into a membership interest in Line Drive, constituting all of the issued and outstanding membership interests in Line Drive immediately following the closing of the merger, the membership interest in Line Drive held by Mr. McCabe and outstanding immediately prior to the closing of the merger ceased to exist, and we issued Mr. McCabe 3,301,739 restricted shares of our common stock as consideration therefor. Immediately after closing, the 521,739 warrants held by Line Drive were cancelled, which warrants had an exercise price of $1.40 per share and an expiration date of June 9, 2020. A Certificate of Merger for the merger transaction was filed with the Secretary of State of Texas on January 31, 2017. Subsequent to the closing the name of Line Drive Energy, LLC was changed to Torchlight Hazel, LLC. We are required to drill one well every six months to hold the entire 12,000 acre block for eighteen months, and thereafter two wells every six months starting June 2018. During the year ended December 31, 2019 modifications were made to mineral owner leases as described below.

 

Also on January 30, 2017, TEI entered into and closed a Purchase and Sale Agreement with Wolfbone. Under the agreement, TEI acquired certain of Wolfbone’s Hazel Project assets, including its interest in the Flying B Ranch #1 well and the 40 acre unit surrounding the well, for consideration of $415,000, and additionally, Wolfbone caused to be cancelled a total of 2,780,000 warrants to purchase shares of our common stock, including 1,500,000 warrants held by MPC, and 1,280,000 warrants held by Green Hill Minerals, an entity owned by Mr. McCabe’s son, which warrant cancellations were effected through certain Warrant Cancellation Agreements. The 1,500,000 warrants held by MPC that were cancelled had an exercise price of $1.00 per share and an expiration date of April 4, 2021. The warrants held by Green Hill Minerals that were cancelled included 100,000 warrants with an exercise price of $1.73 and an expiration date of September 30, 2018 and 1,180,000 warrants with an exercise price of $0.70 and an expiration date of February 15, 2020.

 

Since Mr. McCabe held the controlling interest in both Line Drive and Wolfbone, the transactions were combined for accounting purposes. The working interest in the Hazel Project was the only asset held by Line Drive. The warrant cancellation was treated in the aggregate as an exercise of the warrants with the transfer of the working interests as the consideration. We recorded the transactions as an increase in its investment in the Hazel Project working interests of $3,644,431, which is equal to the exercise price of the warrants plus the cash paid to Wolfbone.

 

Upon the closing of the transactions, our working interest in the Hazel Project increased by 40.66% to a total ownership of 74%.

 

Effective June 1, 2017, we acquired an additional 6% working interest from unrelated working interest owners in exchange for 268,656 shares of common stock valued at $373,430, increasing our working interest in the Hazel project to 80%, and an overall net revenue interest of 74-75%.

 

Mr. Masterson is credited with originating the Hazel Project in the Midland Basin. With Mr. Masterson’s assistance, we are targeting prospects in the Midland Basin that have 150 to 130 feet of thickness, are likely to require six to eight laterals per bench, have the potential for 12 to 16 horizontal wells per section, and 200 long lateral locations, assuming only two benches.

46

 

TORCHLIGHT ENERGY RESOURCES, INC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

4. OIL & GAS PROPERTIES - continued

 

In April 2018, we announced that we have commenced a process that could result in the monetization of the Hazel Project. We believe the development activity at the Hazel Project, coupled with nearby activities of other oil and gas operators, suggests that this project has achieved a level of value worth monetizing. We anticipate that the liquidity that would be provided from selling the Hazel Project could be redeployed into the Orogrande Project. While this process is underway, we will take all necessary steps to maintain the leasehold as required. As of this filing, we continue to maintain the leases in good standing and continue to market the acreage in an effort to focus on the Orogrande Project.

 

During the year ended December 31, 2019 the Company deepened the Flying B #4 and took whole cores through all of the Wolfcamp A and the upper portion of the Wolfcamp B. In addition, in May, 2019 we entered into agreements with two of the three mineral owners on the northern section of the leases to keep the entire acreage block as one lease with a one year extension. We issued each of them 50,000 shares of our common stock as consideration for this extension. At December 31, 2019 we were structuring the extension agreement with the third mineral owner for cash consideration. Due to this extension, our obligation in November reduces to one obligation well. We have finished that obligation well and are awaiting results. This well is targeting a shallow zone that is showing oil potential.

 

The marketing process is ongoing for the Hazel project. We continue to encounter, as does the entire industry, a soft market for acquisitions and divestitures transactions. We will continue to look to sell the property or joint venture the property via farm in or a drillco transaction.

 

Winkler Project, Winkler County, Texas

 

On December 1, 2017, the Agreement and Plan of Reorganization that we and our then wholly-owned subsidiary, Torchlight Wolfbone Properties, Inc., a Texas corporation (“TWP”), entered into with MPC and Warwink Properties, LLC (“Warwink Properties”) on November 14, 2017 closed. Under the agreement, TWP merged with and into Warwink Properties and the separate existence of TWP ceased, with Warwink Properties being the surviving entity and becoming our wholly-owned subsidiary. Warwink Properties was wholly owned by MPC. Warwink Properties owns certain assets, including a 10.71875% working interest in approximately 640 acres in Winkler County, Texas. Upon the closing of the merger, all of the issued and outstanding shares of common stock of TWP converted into a membership interest in Warwink Properties, constituting all of the issued and outstanding membership interests in Warwink Properties immediately following the closing of the merger, the membership interest in Warwink Properties held by MPC and outstanding immediately prior to the closing of the merger ceased to exist, and we issued MPC 2,500,000 restricted shares of our common stock as consideration. Also on December 1, 2017, MPC closed its transaction with MECO IV, LLC (” MECO”), for the purchase and sale of certain assets as contemplated by the Purchase and Sale Agreement dated November 9, 2017 among MPC, MECO and additional parties thereto (the “MECO PSA”), to which we are not a party. Under the MECO PSA, Warwink Properties received a carry from MECO (through the tanks) of up to $1,179,076 in the next well drilled on the Winkler County leases. A Certificate of Merger for the merger transaction was filed with the Secretary of State of Texas on December 5, 2017.

 

Also on December 1, 2017, the transactions contemplated by the Purchase Agreement that TEI entered into with MPC closed. Under the Purchase Agreement, which was entered into on November 14, 2017, TEI acquired beneficial ownership of certain of MPC’s assets, including acreage and wellbores located in Ward County, Texas (the “Ward County Assets”). As consideration under the Purchase Agreement, at closing TEI issued to MPC an unsecured promissory note in the principal amount of $3,250,000, payable in monthly installments of interest only beginning on January 1, 2018, at the rate of 5% per annum, with the entire principal amount together with all accrued interest due and payable on January 1, 2021. In connection with TEI’s acquisition of beneficial ownership in the Ward County Assets, MPC sold those same assets, on behalf of TEI, to MECO at closing of the MECO PSA, and accordingly, TEI received $3,250,000 in cash for its beneficial interest in the Ward County Assets. Additionally, at closing of the MECO PSA, MPC paid TEI a performance fee of $2,781,500 in cash as compensation for TEI’s marketing and selling the Winkler County assets of MPC and the Ward County Assets as a package to MECO. 

 

Addition to the Winkler Project

 

As of May 7, 2018 our Winkler project in the Delaware Basin had begun the drilling phase of the first Winkler Project well, the UL 21 War-Wink 47 #2H. Our operating partner, MECO had begun the pilot hole on the project. The plan is to evaluate the various potential zones for a lateral leg to be drilled once logging is completed. We expect the most likely target to be the Wolfcamp A interval. The well is on 320 newly acquired acres offsetting the original leasehold we entered into in December, 2017. The additional acreage was leased by our operating partner under the Area of Mutual Interest Agreement (AMI) and we exercised its right to participate for its 12.5% in the additional 1,080 gross acres at a cash cost of $447,847 in July, 2018. Our carried interest in the first well, as outlined in the agreement, was originally planned to be on the first acreage acquired. That carried interest is being applied to this new well and will allow MECO to drill and produce potential revenues sooner than originally planned. The primary leasehold is a 320-acre block directly west of the current position and will allow for 5,000-foot lateral wells to be drilled. The well was completed and began production in October, 2018 and is producing currently. Recently the operator has informed us that there will be no planned additional wells in the acreage this year. All acreage is presently held by production.

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TORCHLIGHT ENERGY RESOURCES, INC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

4. OIL & GAS PROPERTIES - continued

 

In December 2018, the Company began to take measures on its own to market the Winkler Project in an effort to focus on the Orogrande. This process is ongoing.

 

Hunton Play, Central Oklahoma

 

Presently, we are producing from one well in the Viking Area of Mutual Interest and one well in Prairie Grove.

 

Assets Held for Sale

 

With respect to marketing oil and natural gas properties, the Company has evaluated the properties being marketed to determine whether any should be reclassified as held-for-sale at December 31, 2019. The held-for-sale criteria include: management commits to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property would be reclassified as held-for-sale on the Company’s consolidated balance sheets and measured at the lower of their carrying amount or estimated fair value less costs to sell. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, valuations performed by third parties, earnings multiples, or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. If each of these criteria is met, DD&A expense would not be recorded on assets to be divested once they are classified as held for sale. Based on management’s assessment, these criteria have not been met and no assets are classified as held for sale as of December 31, 2019.

 

5. RELATED PARTY PAYABLES

 

As of December 31, 2019 and 2018, related party payables of $45,000, and accrued payroll was $996,176 and $816,176, respectively, consisting of accrued and unpaid compensation due to our executive officers.

 

6. COMMITMENTS AND CONTINGENCIES

 

Leases

 

The Company had a noncancelable lease for its office premises that expired on November 30, 2019 and which required the payment of base lease amounts and executory costs such as taxes, maintenance and insurance. Effective June 1, 2019 the Company entered into an agreement with a company that had been subleasing a portion of its office space to become the primary obligor on the lease and to assume full responsibility for lease payments after lease expiration on November 30, 2019. The Company continued after November 30, 2019 as a subtenant on a month to month basis.

 

Legal Matters

 

On January 31, 2020, Torchlight Energy Resources, Inc. and its wholly owned subsidiaries Torchlight Energy, Inc. and Torchlight Energy Operating, LLC were served with a lawsuit brought by Goldstone Holding Company, LLC (Goldstone Holding Company, LLC v. Torchlight Energy, Inc., et al., in the 160th Judicial District Court of Dallas County, Texas). On February 24, 2020, Torchlight Energy Resources, Inc., Torchlight Energy, Inc., and Torchlight Energy Operating, LLC timely filed their answer, affirmative defenses, and requests for disclosure. The suit, which seeks monetary relief over $1 million, makes unspecified allegations of misrepresentations involving a November 2015 participation agreement and a 2016 amendment to the participation agreement. We have denied the allegations and have asserted several affirmative defenses including but not limited to, that the suit is barred by the applicable statute of limitations, that the claims have been released, and that the claims are barred because of contractual disclaimers between sophisticated parties.

 

Environmental matters

 

The Company is subject to contingencies as a result of environmental laws and regulations. Present and future environmental laws and regulations applicable to the Company’s operations could require substantial capital expenditures or could adversely affect its operations in other ways that cannot be predicted at this time. As of December 31, 2019 and 2018, 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.

 

7. STOCKHOLDERS’ EQUITY

 

Common Stock

 

During the years ended December 31, 2019 and 2018, the Company issued 4,686,100 and 5,750,000 shares of common stock, respectively, for cash of $3,512,917 and $6,049,734.

 

During the years ended December 31, 2019 and 2018, the Company issued 416,667 and -0- shares of common stock, respectively, for a subscription of $183,963 and $-0-.

 

During the years ended December 31, 2019 and 2018, the Company issued 312,593 and 450,000 shares of common stock, respectively, with total fair values of $365,400 and $545,000 as compensation for services.

 

During the years ended December 31, 2019 and 2018, the Company issued 167,845 and -0- shares of common stock respectively, for lease interests with total fair values of $183,714 and $-0-.

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TORCHLIGHT ENERGY RESOURCES, INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

7. STOCKHOLDERS’ EQUITY - continued

 

During the years ended December 31, 2019 and 2018, the Company issued 100,000 and -0- shares of common stock respectively, for lease extensions with total fair values of $125,000 and $-0-.

 

During the years ended December 31, 2019 and 2018, the Company issued 45,455 and -0- shares of common stock respectively, in conversions of notes payable valued at $50,000 and $-0-.

 

During the years ended December 31, 2019 and 2018, the Company issued 202,316 and 172,342 shares of common stock respectively, in payment in kind on notes payable valued at $314,108 and $221,024.

 

During the years ended December 31, 2019 and 2018, the Company issued 168,690 and 400,000 shares of common stock, respectively, resulting from warrant and option exercises for consideration totaling $184,843 and $200,000.

 

Warrants and Options

 

During the years ended December 31, 2019 and 2018, the Company issued and vested 100,000 and 1,220,000 warrants, respectively, with total fair values of $99,000 and $510,575, respectively, as compensation for services and 2,032,122 warrants in connection with financings in 2019.

 

During the years ended December 31, 2019 and 2018, the Company issued 700,000 and 600,000 stock options, respectively. The Company vested 700,000 and 700.000 stock options, respectively, with total fair values of $236,500 and $343,750 respectively, as compensation for services.

 

A summary of warrants outstanding as of December 31, 2019 and 2018 by exercise price and year of expiration is presented below:

 

Exercise   Expiration Date In     
Price   2020   2021   2022   2023   2024   2025   12/31/2019 
                              
$0.70    420,000    -    -    -    -    -    420,000 
$0.80    -    -    -    -    -    1,666,667    1,666,667 
$1.03    -    120,000    -    -    -    -    120,000 
$1.14    -    -    -    600,000    -    -    600,000 
$1.21    -    -    -    120,000    -    -    120,000 
$1.35    -    -    365,455    -    -    -    365,455 
$1.40    321,737    -    -    -    -    -    321,737 
$1.63    -    -    -    -    100,000    -    100,000 
$1.64    -    200,000    -    -    -    -    200,000 
$1.80    1,250,000    -    -    -    -    -    1,250,000 
$2.00    -    200,000    -    -    -    -    200,000 
$2.23    339,901    -    -    -    -    -    339,901 
      2,331,638    520,000    365,455    720,000    100,000    1,666,667    5,703,760 

49

 

TORCHLIGHT ENERGY RESOURCES, INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

7. STOCKHOLDERS’ EQUITY - continued

 

Exercise   Expiration Date In     
Price   2019   2020   2021   2022   2023   12/31/2018 
                          
$0.70    -    420,000    -    -    -    420,000 
$0.77    100,000    -    -    -    -    100,000 
$1.00    25,116    -    -    -    -    25,116 
$1.03    -    -    120,000    -    -    120,000 
$1.08    37,500    -    -    -    -    37,500 
$1.14    -    -    -    -    600,000    600,000 
$1.21    -    -    -    -    120,000    120,000 
$1.40    -    1,121,736         -    -    1,121,736 
$1.50    -         100,000    -    -    100,000 
$1.64    -    -    200,000    -    -    200,000 
$1.80    -    1,250,000    -    -    -    1,250,000 
$2.00    -    -    400,000    -    -    400,000 
$2.23    -    832,512         -    -    832,512 
$2.50    35,211    -    -    -    -    35,211 
$3.50    15,000    -    -    -    -    15,000 
$4.50    700,000    -    -    -    -    700,000 
$6.00    22,580    -    -    -    -    22,580 
$7.00    700,000    -    -    -    -    700,000 
      1,635,407    3,624,248    820,000    -    720,000    6,799,655 

 

A summary of stock options outstanding as of December 31, 2019 and 2018 by exercise price and year of expiration is presented below:

 

Exercise   Expiration Date In     
Price   2020   2021   2022   2023   2024   12/31/2019 
                          
$0.85    -    -    -    -    600,000    600,000 
$0.97    -    259,742    -    -    -    259,742 
$1.10    -    -    800,000    -    -    800,000 
$1.19    -    -    -    700,000    -    700,000 
$1.57    4,500,000    -    -    -    -    4,500,000 
$1.63    -    -    58,026    -    -    58,026 
      4,500,000    259,742    858,026    700,000    600,000    6,917,768 

 

Exercise   Expiration Date In     
Price   2019   2020   2021   2022   2023   12/31/2018 
                          
$0.97    -    -    259,742    -    -    259,742 
$1.10    -    -    -    800,000    -    800,000 
$1.19    -    -    -    -    600,000    600,000 
$1.57    1,497,163    4,500,000    -    -    -    5,997,163 
$1.63    -    -    -    58,026    -    58,026 
$1.79    -    300,000    -    -    -    300,000 
      1,497,163    4,800,000    259,742    858,026    600,000    8,014,931 

50

 

TORCHLIGHT ENERGY RESOURCES, INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

7. STOCKHOLDERS’ EQUITY - continued

 

At December 31, 2019 and 2018, the Company had reserved 12,621,528 and 14,814,586 common shares for future exercise of warrants and options.

 

Warrants and options granted were valued using the Black-Scholes Option Pricing Model. The assumptions used in calculating the fair value of the warrants and options issued were as follows:

 

2019  
   
Risk-free interest rate 1.65% - 2.46%
Expected volatility of common stock 77% - 107%
Dividend yield 0.00%
Discount due to lack of marketability 20%
Expected life of option/warrant Three to Five Years
   
2018  
   
Risk-free interest rate 2.15% - 2.83%
Expected volatility of common stock 114% - 119%
Dividend yield 0.00%
Discount due to lack of marketability 20%
Expected life of option/warrant 2.75 to Five Years

 

8. INCOME TAXES

 

The Company recorded no income tax provision for 2019 and 2018 because of losses incurred. The Company has placed a full valuation allowance against net deferred tax assets because future realization of these assets is not assured.

 

There are no uncertain tax positions accounted for in this tax provision.

 

The following is a reconciliation between the federal income tax benefit computed at statutory federal income tax rates and actual income tax provision for the years ended December 31, 2019 and 2018:

 

   Year ended   Year ended 
   December 31, 2019   December 31, 2018 
Federal income tax benefit at statutory rate  $(2,066,273)  $(1,221,483)
Permanent Differences   1,336    505 
Annual reconciling adjustment   10,949    1,449,429 
Change in valuation allowance   2,053,988    (228,451)
Provision for income taxes  $-   $- 

51

 

TORCHLIGHT ENERGY RESOURCES, INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

8. INCOME TAXES - continued

 

The tax effects of temporary differences that gave rise to significant portions of deferred tax assets and liabilities at December 31, 2019 and 2018 are as follows:

 

   December 31, 2019   December 31, 2018 
Deferred tax assets:          
Net operating loss carryforward  $14,066,645   $11,968,500 
Stock based compensation   4,688,694    4,490,775 
Disallowed interest expense   285,205    69,505 
Other   288,030    302,131 
Deferred tax liabilities:          
Investment in oil and gas properties   (3,322,760)   (2,879,086)
Net deferred tax assets and liabilities   16,005,814    13,951,825 
Less valuation allowance   (16,005,814)   (13,951,825)
Total deferred tax assets and liabilities  $-   $- 

 

The Company had a net deferred tax asset related to federal net operating loss carryforwards of $66,984,025 and $63,070,504 at December 31, 2019 and 2018, respectively. The federal net operating loss carryforward will begin to expire in 2034. Realization of the deferred tax asset is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards. The Company has placed a 100% valuation allowance against the net deferred tax asset because future realization of these assets is not assured.

 

9. PROMISSORY NOTES

 

On April 10, 2017, the Company sold to investors in a private transaction two 12% unsecured promissory notes with a total amount of $8,000,000 in principal amount. Interest only is due and payable on these notes each month at the rate of 12% per annum, with a balloon payment of the outstanding principal due and payable at maturity on April 10, 2020. The holders of these notes will also receive annual payments of common stock at the rate of 2.5% of principal amount outstanding, based on a volume-weighted average price. Both notes were sold at an original issue discount of 5.75% and accordingly, we received total proceeds of $7,540,000 from the investors. We used the proceeds for working capital and general corporate purposes, which includes, without limitation, drilling capital, lease acquisition capital and repayment of prior debt.

 

These 12% promissory notes allow for early redemption. The notes also contain certain covenants under which we have agreed that, except for financing arrangements with established commercial banking or financial institutions and other debts and liabilities incurred in the normal course of business, we will not issue any other notes or debt offerings which have a maturity date prior to the payment in full of the 12% notes, unless consented to by the holders.

 

The effective interest rate is 16.15%.

 

On April 24, 2017, we used $2,509,500 of the proceeds from this financing to redeem and repay a portion of the outstanding 12% Series B Convertible Unsecured Promissory Notes. Separately, $1,000,000 of the principal amount of the Series B Notes plus accrued interest was converted into 1,007,890 shares of common stock and $64,297 was rolled into the new debt financing.

 

On February 6, 2018, we sold to an investor in a private transaction a 12% unsecured promissory note with a principal amount of $4,500,000. Interest only is due and payable on the note each month at the rate of 12% per annum, with a balloon payment of the outstanding principal due and payable at maturity on April 10, 2020. The holder of the note will also receive annual payments of common stock at the rate of 2.5% of principal amount outstanding, based on a volume-weighted average price. We sold the note at an original issue discount of 3.73% and accordingly, we received total proceeds of $4,332,150 from the investor. We used the proceeds for working capital and general corporate purposes, which includes, without limitation, drilling capital, lease acquisition capital and repayment of prior debt.

52

 

TORCHLIGHT ENERGY RESOURCES, INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

9. PROMISSORY NOTES - continued

 

This 12% promissory note allows for early redemption, provided that if we redeem before February 6, 2019, we must pay the holder all unpaid interest and common stock payments on the portion of the note redeemed that would have been earned through February 6, 2019. The note also contains certain covenants under which we have agreed that, except for financing arrangements with established commercial banking or financial institutions and other debts and liabilities incurred in the normal course of business, we will not issue any other notes or debt offerings which have a maturity date prior to the payment in full of the 12% note, unless consented to by the holder.

 

The effective interest rate is 15.88%.

 

In April 2019 and 2018, respectively, the holders of the notes described above received 202,316 and 172,342 shares of common stock as a payment in kind representing the annual payments of common stock due at the rate of 2.5% of principal amount outstanding as of April 10 based on a volume-weighted average price calculation.

 

Unsecured promissory note transactions through December 31, 2019 are summarized as follows:

 

Unsecured promissory note balance - December 31, 2018  $11,862,080 
      
Accretion of discount and amortization of debt issuance costs   515,750 
      
Unsecured promissory note balance - December 31, 2019  $12,377,830 

 

$8,564,297 of the 2017 and 2018 Note have balloon payments of outstanding principal due and payable at maturity on April 10, 2020.

 

The maturity date of the remaining $4 million in 2017 Notes was extended to April 10, 2021  and is classified as a long term liability in our consolidated balance sheet.

 

On October 17, 2018, we sold to certain investors in a private transaction 16% Series C Unsecured Convertible Promissory Notes with a total principal amount of $6,000,000. Interest and principal were due and payable on the notes in one balloon payment at maturity on April 17, 2020. The notes were convertible, at the election of the holders, into an aggregate 6% working interest in certain oil and gas leases in Hudspeth County, Texas, known as our “Orogrande Project.” After an analysis of the transaction and a review of applicable accounting pronouncements, management concluded that the notes issued on October 17, 2018 which contain a conversion right for holders to convert into a working interest in the Orogrande Project of the Company, meet a specific scope exception to the provisions requiring derivative accounting.

 

The notes allowed us to redeem them early only upon the event of a fundamental transaction, such as a merger or sale of substantially all our assets. The notes provided that the noteholders may accelerate and declare any and all of the obligations under the notes to be immediately due and payable in the event of default, such as nonpayment, failure to perform required conversions, failure to perform any covenant or agreement under the notes, an insolvency event, or certain defaults or judgments. As part of the sale of the of the notes, the noteholders required that McCabe Petroleum Corporation, a Texas corporation owned by our Chairman Gregory McCabe (“MPC”), provide them a put option whereby they had the right to have MPC purchase from them any unpaid principal amount due on the notes. Additionally, the notes provided that if there was a fundamental transaction, Mr. McCabe would be required to pay a fee to each noteholder that elects not to convert or require MPC to purchase the principal amount under the note, which fee would be equal to such noteholder’s pro-rata share of a total fee amount of $1,500,000.

 

We received total proceeds of $6,000,000 from the sale of the notes, of which $3,000,000 was used to pay back the promissory note issued to MPC on December 1, 2017, which note was due on December 31, 2020. We used the remaining proceeds for working capital and general corporate purposes, which includes, without limitation, drilling and lease acquisition capital.

 

Prior to entering into the above transactions, our Board of Directors formed a special committee composed of independent directors to analyze and authorize the transactions on behalf of Torchlight Energy Resources, Inc. and determine whether the transactions are fair to the company. In this role, the special committee engaged an independent financial consulting firm which rendered a fairness opinion deeming that the transactions were fair to the company, from a financial point of view, and contained terms no less favorable to the company than those that could be obtained in arm’s length transactions.

 

See “Note 11 – Subsequent Events” below for disclosure of the conversion of the notes which occurred on March 9, 2020.

 

In February and March, 2019 the Company raised a total of $2,000,000 from investors through the sale of 14% Series D Unsecured Convertible Promissory Notes. Principal is payable in a lump sum at maturity on May 11, 2020 with payments of interest payable monthly at the rate of 14% per annum. Holders of the notes have the right to convert principal and interest at any time into common stock at a conversion price of $1.08 per share. The Company has the right to redeem the notes at any time, provided that the redemption amount must include all interest that would have been earned through maturity. The Company evaluated the notes for beneficial conversion features and derivative accounting criteria and concluded that derivative accounting treatment is not applicable.

53

 

TORCHLIGHT ENERGY RESOURCES, INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

9. PROMISSORY NOTES - continued

 

In July 2019, the Company issued 8% Unsecured Convertible Promissory notes in the amount of $2,010,000 together with warrants to purchase our common stock. The principal and accrued interest on the notes are convertible into shares of common stock at $1.10 per common share at any time after the original issue date. Along with the notes, the three year warrants equal to 20% of the number of shares of common stock issuable upon the conversion of the notes were issued to note holders. The warrants are exercisable at $1.35 per share.

 

Warrants issued along with the notes meet the requirements of the scope exemptions in ASC 815-10-15-74 and are thus classified as equity upon issuance. The Company determined the fair value of the warrants using the Black Scholes pricing formula and is recognized as a discount on the carrying amount of the notes and is credited to additional paid in capital. The fair value of the warrants at the issuance date was determined to be $240,455.

 

A beneficial conversion feature (“BCF”) of a convertible note is normally characterized as the convertible portion feature that provides a rate of conversion that is below market value or “in the money” when issued. The BCF related to the issuance of the notes was recorded at the issuance date. The BCF was measured using the intrinsic value method and is shown as a discount to the carrying amount of the convertible note and is credited to additional paid in capital. The intrinsic value of the BCF at the issuance date of the notes was determined to be $1,145,546.

 

The allocated fair values of the BCF and the warrants was recorded as a debt discount from the face amount of the notes and such discount is being accreted over the expected term of the notes and is charged to interest expense. The Company recognized interest expense for 2019 of $199,972 from the amortization of debt discount from these notes.

 

Effective October 31, 2019, the Company issued 10% Unsecured Convertible Promissory notes in the amount of $540.000. Principal and interest are due at maturity on December 3, 2020. The principal and accrued interest on the notes are convertible into shares of common stock at $.75 per common share at any time after the original issue date

 

The Company evaluated the July, 2019 and the October, 2019 notes for beneficial conversion features and derivative accounting criteria and concluded that derivative accounting treatment was not applicable.

 

10. ASSET RETIREMENT OBLIGATIONS

 

The following is a reconciliation of the asset retirement obligations liability through December 31, 2019:

 

Asset retirement obligations – December 31, 2018  $14,353 
      
Accretion expense   569 
Estimated liabilities recorded   8,397 
      
Asset retirement obligations – December 31, 2019  $23,319 

 

11. SUBSEQUENT EVENTS

 

On October 17, 2018, we sold to certain investors in a private transaction 16% Series C Unsecured Convertible Promissory Notes with a total principal amount of $6,000,000, with interest and principal due and payable on the notes in one balloon payment at maturity on April 17, 2020 (at maturity a total of $1,500,000 in interest would be due and payable on the notes). On March 9, 2020, each of the noteholders entered into a Conversion Agreement with us and our subsidiary Hudspeth Oil Corporation (“Hudspeth”), under which the noteholders elected to convert the notes, in accordance with their terms, into an aggregate 6% working interest (of all such holders) in certain oil and gas leases in Hudspeth County, Texas, known as our “Orogrande Project.” Principal of $6,000,000 and approximately $1,339,000 of accrued interest were converted at March 9, 2020.

 

The principal amount converted on March 9, 2020 of $6,000,000 plus interest accrued to December 31, 2019 of $1,157,260 is classified as a long term liability in the accompanying consolidated balance sheet .

 

The Conversion Agreements also provided additional consideration to the noteholders including a limited carry, a top-off obligation of us and Hudspeth, and warrants to purchase a total of 750,000 restricted shares of our common stock, which warrants will have a term of five years and an exercise price of $0.70 per share. The limited carry provides that for the remainder of the 2020 calendar year, Hudspeth will pay all costs and expenses attributable to the assigned working interests, except where prohibited by law or regulation. The top-off obligation provides that, subject to the terms and conditions of the Conversion Agreements, if (a) we sell our entire working interest in the Orogrande Project, (b) as part of such sale, the holder’s entire working interests are sold, and (c) the gross proceeds received by all the holders in such transaction are equal to less than $9,000,000; then we must pay the holders an amount equal to $9,000,000, (i) less gross proceeds the holders received in the transaction, (ii) less the amount of the carry the holders received under the Conversion Agreements, and (iii) less any gross proceeds the holders received in any farmouts occurring prior to the transaction.

54

 

TORCHLIGHT ENERGY RESOURCES, INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

11. SUBSEQUENT EVENTS - continued

 

On February 20, 2020, the Company extended the maturity on $4 million of the 12% unsecured promissory notes previously due in April, 2020. The maturity date of the subject promissory note has been extended for one year, from April 10, 2020 to April 10, 2021 and is classified as a long term liability in the accompanying consolidated balance sheet.

 

As part of the terms of the referenced extension agreement, the Company paid the noteholder a fee of $80,000. The promissory note was originally issued in April 2017, and provides for monthly payments of interest only at the rate of 12% per annum, with a balloon payment of the outstanding principal due and payable at maturity. The noteholder also receives annual payments of common stock at the rate of 2.5% of the principal amount outstanding, based on a volume-weighted average price.

 

On January 16, 2020, the Company announced the closing of its underwritten public offering of 3,285,715 shares of its common stock at a public offering price of $0.70 per share, for total gross proceeds of approximately $2.3 million, before deducting underwriting discounts and other offering expenses payable by the Company.

 

A shelf registration statement relating to the shares of common stock issued in the offering was filed with the Securities and Exchange Commission (the “SEC”).

55

 

TORCHLIGHT ENERGY RESOURCES, INC.

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

 

The unaudited supplemental information on oil and gas exploration and production activities has been presented in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas and the SEC’s final rule, Modernization of Oil and Gas Reporting.

 

Investment in oil and gas properties during the years ended December 31, 2019 and 2018 is detailed as follows:

 

   2019   2018 
Property acquisition costs  $-   $1,072,047 
Development costs  $6,641,467   $9,191,041 
Exploratory costs  $-   $- 
           
Totals  $9,415,551   $10,263,088 

 

Property acquisition costs presented above exclude interest capitalized into the full cost pool of $2,858,753 in 2019 and $2,084,026 in 2018.

 

Property acquisition cost relates to the Company’s acquisition of additional working interests in the Orogrande Project in west Texas and the acquisition of the Warwink Project, also in west Texas. The development costs include work in the Orogrande, Hazel, and Warwink projects in west Texas. No development costs were incurred for Oklahoma properties in 2019.

 

Oil and Natural Gas Reserves

 

Reserve Estimates

 

SEC Case. The following tables sets forth, as of December 31, 2019, our estimated net proved oil and natural gas reserves, the estimated present value (discounted at an annual rate of 10%) of estimated future net revenues before future income taxes (PV-10) and after future income taxes (Standardized Measure) of our proved reserves and our estimated net probable oil and natural gas reserves, each prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with assumptions prescribed by the Securities and Exchange Commission (“SEC”). All of our reserves are located in the United States.

 

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

56

 

The estimates of our proved reserves and the PV-10 set forth herein reflect estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions at December 31, 2019. For purposes of determining prices, we used the average of prices received for each month within the 12-month period ended December 31, 2019, adjusted for quality and location differences, which was $62.04 per barrel of oil and $3.10 per MCF of gas. This average historical price is not a prediction of future prices. The amounts shown do not give effect to non-property related expenses, such as corporate general administrative expenses and debt service, future income taxes or to depreciation, depletion and amortization.

 

   December 31, 2019   December 31, 2019 
   Reserves   Future Net Revenue (M$) 
                   Present Value
Discounted
 
Category  Oil (Bbls)   Gas (Mcf)   Total (BOE)   Total   at 10% 
                     
Proved Producing   14,700    21,100    18,217   $634   $514 
Proved Nonproducing   0    0    0   $-   $- 
Total Proved   14,700    21,100    18,217   $634   $514 
                          
Standardized Measure of Future Net Cash Flows Related to Proved Oil and Gas Properties                      $539 
                          
Probable Undeveloped   0    0    0   $-   $- 
         
   December 31, 2018   December 31, 2018 
   Reserves   Future Net Revenue (M$) 
                   Present Value 
                   Discounted 
Category  Oil (Bbls)   Gas (Mcf)   Total (BOE)   Total   at 10% 
                     
Proved Producing   177,300    51,100    185,817   $4,027   $2,029 
Proved Undeveloped   797,500    105,800    815,133   $15,313   $2,895 
Total Proved   974,800    156,900    1,000,950   $19,340   $4,924 
                          
Standardized Measure of Future Net Cash Flows Related to Proved Oil and Gas Properties                      $5,341 
                          
Probable Undeveloped   0    0    0   $-   $- 

 

The upward revisions of previous estimates from 2017 to 2018 of proved reserves of 972,500 BBLS and 113,100 MCF resulted primarily from 2018 reserve report calculations for the Company’s properties which included reserves from producing properties in the Hazel and Warwink Projects for the first time. The decrease in producing reserves from 2018 to 2019 from 185,817 to 18,217 BOE is related to the shut in of the Hazel Flying B #3 well in May, 2019 and the decline in production in the Oklahoma properties. Neither of these properties were economic under the 2019 Reserve Report.

 

Reserve values as of December 31, 2019 are related to a single producing well in the Warwink Project.

 

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

57

 

Standardized Measure of Oil & Gas Quantities - Volume Rollforward
Year Ended December 31, 2019

 

The following table sets forth the Company’s net proved reserves, including the changes therein, and proved developed reserves:

 

   Crude Oil (Bbls)   Natural Gas (Mcf)   BOE 
TOTAL PROVED RESERVES:               
Beginning of period   974,780    156,940    1,000,937 
Revisions of previous estimates   (944,985)   (121,400)   (965,218)
Extensions, discoveries and other additions   -    -    - 
Divestiture of Reserves   -    -    - 
Acquisition of Reserves   -    -    - 
Production   (15,085)   (14,410)   (17,487)
End of period   14,710    21,130    18,233 

 

Standardized Measure of Oil & Gas Quantities - Volume Rollforward
Year Ended December 31, 2018

 

The following table sets forth the Company’s net proved reserves, including the changes therein, and proved developed reserves:

 

   Crude Oil (Bbls)   Natural Gas (Mcf)   BOE 
TOTAL PROVED RESERVES:               
Beginning of period   2,300    43,800    9,600 
Revisions of previous estimates   21,257    (7,709)   19,972 
Extensions, discoveries and other additions   974,110    138,670    997,222 
Divestiture of Reserves   -    -    - 
Acquisition of Reserves   -    -    - 
Production   (22,887)   (17,821)   (25,857)
End of period   974,780    156,940    1,000,937 

58

 

Standardized Measure of Oil & Gas Quantities
Year Ended December 31, 2019 & 2018

 

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows:

 

   2019   2018 
Future cash inflows  $843,040   $46,335,070 
Future production costs   (196,670)   (15,042,900)
Future development costs   -    (11,740,000)
Future income tax expense   -    - 
Future net cash flows   646,370    19,552,170 
10% annual discount for estimated timing of cash flows   (107,070)   (14,210,840)
Standardized measure of discounted future net cash flows related to proved reserves  $539,300   $5,341,330 

 

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves is as follows:

 

   2019   2018 
Balance, beginning of period  $5,341,330   $123,268 
Net change in sales and transfer prices and in production (lifting) costs related to future production   1,176,090    40,762 
Changes in estimated future development costs   1,851,760    (8,718,999)
Net change due to revisions in quantity estimates   (5,896,344)   289,740 
Accretion of discount   (868,787)   1,036 
Other   (1,763,161)   (385,278)
           
Net change due to extensions and discoveries   -    14,467,005 
Net change due to sales of minerals in place   -    - 
Sales and transfers of oil and gas produced during the period   (294,912)   (476,204)
Previously estimated development costs incurred during the period   993,324    - 
Net change in income taxes   -    - 
Balance, end of period  $539,300   $5,341,330 

 

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

 

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

59

 

Reserve Estimation Process, Controls and Technologies

 

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

 

Results of Operations for Oil and Gas Producing Activities            
For the Year Ended December 31, 2019  Total   Texas   Oklahoma 
             
Oil and Gas revenue  $746,263   $725,668   $20,595 
                
Production costs  $451,325   $426,096   $25,229 
Depreciation, depletion, and amortization  $4,388,868   $3,814,938   $573,930 
Exploration expenses  $-   $-   $- 
    4,840,193   $4,241,034   $599,159 
                
Income tax expense  $-   $-   $- 
                
Results of Operations (excluding corporate overhead and interest costs)  $(4,093,930)  $(3,515,366)  $(578,564)

 

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

 

Not Applicable.

 

ITEM 9A. CONTROLS AND PROCEDURES

 

Management’s Evaluation of Disclosure Controls and Procedures

 

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2019. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2019, our disclosure controls and procedures were effective, in that they ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

 

Management’s Annual Report on Internal Control Over Financial Reporting

 

Management acknowledges its responsibility for establishing and maintaining adequate internal control over financial reporting in accordance with Rule 13a-15(f) promulgated under the Exchange Act. The company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

 

Management has also evaluated the effectiveness of its internal control over financial reporting in accordance with generally accepted accounting principles within the guidelines of the Committee of Sponsoring Organizations of the Treadway Commission framework (2013). Based on the results of this evaluation, management has determined that the Company’s internal control over financial reporting was effective as of December 31, 2019. The independent registered public accounting firm of Briggs & Veselka Co, the auditors of the Company’s financial statements included in the Annual Report, has issued an attestation report on the Company’s internal control over financial reporting.

 

Changes in Internal Controls

 

There were no changes in our Company’s internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) during the year ended December 31, 2019, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.