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EX-32.1 - FOOTHILLS EXPLORATION, INC.ex32-1.htm
EX-31.2 - FOOTHILLS EXPLORATION, INC.ex31-2.htm
EX-31.1 - FOOTHILLS EXPLORATION, INC.ex31-1.htm
EX-21.1 - FOOTHILLS EXPLORATION, INC.ex21-1.htm

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

 

FORM 10-K/A

(Amendment No. 1)

 

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2017

 

OR

 

[  ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from __________ to __________

 

Commission file number 333-190836

 

 

FOOTHILLS EXPLORATION, INC.

(Exact name of registrant as specified in its charter)

 

Delaware   27-3439423
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)
     
633 17th Street, Suite 1700
Denver, Colorado
  80202
(Address of principal executive offices)   (Zip Code)

 

(720) 449-7478

(Registrant’s telephone number, including area code)

 

Securities registered pursuant to Section 12(b) of the Act: None

 

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

 

Title of Each Class   Name of Each Exchange on Which Registered
Common Stock, par value $0.0001 per share   Otcmarkets.com

 

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

 

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

 

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

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X] No [  ]

 

Indicate by checkmark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of 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. [X]

 

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

 

Large accelerated filer [  ] Accelerated filer [  ]
Non-accelerated filer [  ] (Do not check if a smaller reporting company) Smaller reporting company [X]
Emerging Growth Company [X]    

 

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. [X]

 

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

 

On June 30, 2017, 3,903,759 shares of common stock were held by non-affiliates and had an aggregate value of $5,972,741 based on the average closing bid and ask of $1.53 per share as reported by the OTCQB market.

 

As of July 20, 2018, there were 15,050,627 shares of common stock outstanding.

 

 

 

 
 

 

Explanatory Note

 

Foothills Exploration, Inc. (“Foothills”, the “Company”, “its”, “we”, “our”, “us”) is filing this Amendment No. 1 on Form 10-K/A (the “Amendment”) for the fiscal year ended December 31, 2017, originally filed with the U.S. Securities and Exchange Commission (“SEC”) on April 17, 2018 (the “Original Filing”) to include audited financial statements as of December 31, 2017 along with the opinion of our auditors as to the condition of those financial statements.

 

The principal purposes of this Amendment are as follows:

 

● Replacement of unaudited financial statements with audited financial statements;

● Inclusion of Report of Independent Registered Public Accounting Firm;

● Inclusion of additional oil and gas disclosures as required by the SEC; and

● Inclusion, as Exhibits, new certifications by our principal executive officer and principal financial officer, as required by Rule 12b-15 of the Securities Exchange Act of 1934, as amended.

 

Except as described in this Explanatory Note, the information contained in the Original Filing has not been updated to reflect any subsequent events except for the issuance of common stock found in the footnotes to the financial statements, Note 13, Subsequent Events.

 

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TABLE OF CONTENTS

 

    Page
Number
PART I    
Items 1 and 2. Business and Properties 4
Item 1A. Risk Factors 16
Item 1B. Unresolved Staff Comments 25
Item 3. Legal Proceedings 25
Item 4. Mine Safety Disclosures 28
     
PART II    
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 28
Item 6. Selected Financial Data 29
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 29
Item 7A. Quantitative and Qualitative Disclosures about Market Risk 35
Item 8. Financial Statements and Supplementary Data 36
  Report of Independent Registered Public Accounting Firm F-1
  Consolidated Balance Sheets F-2
  Consolidated Statements of Operations F-3
  Consolidated Statements of Stockholders’ Equity F-4
  Consolidated Statements of Cash Flows F-5
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure 37
Item 9A. Controls and Procedures 37
Item 9B. Other Information 39
     
PART III    
Item 10. Directors, Executive Officers and Corporate Governance 39
Item 11. Executive Compensation 42
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 45
Item 13. Certain Relationships and Related Transactions, and Director Independence 46
Item 14. Principal Accountant Fees and Services 47
     
Part IV    
     
Item 15. Exhibits, Financial Statement Schedules and Signatures 48
SIGNATURES 50
INDEX TO EXHIBITS  

 

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PART I

 

ITEMS 1 and 2. Business and Properties.

 

Cautionary Statement Regarding Forward Looking Statements

 

This Annual Report on Form 10-K (including the section regarding Management’s Discussion and Analysis of Financial Condition and Results of Operations) contains forward-looking statements, within the meaning of Sections 27A and 21E of the Securities Exchange Act of 1934, as amended, (the “Act”), regarding our business, financial condition, results of operations and prospects. Words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “seeks,” “estimates” and similar expressions or variations of such words are intended to identify forward-looking statements, but are not deemed to represent an all-inclusive means of identifying forward-looking statements as denoted in this Annual Report on Form 10-K. Additionally, statements concerning future matters are forward-looking statements.

 

Although forward-looking statements in this Annual Report on Form 10-K/A reflect the good faith judgment of our Management, such statements can only be based on facts and factors currently known by us. Consequently, forward-looking statements are inherently subject to risks and uncertainties and actual results and outcomes may differ materially from the results and outcomes discussed in or anticipated by the forward-looking statements. Factors that could cause or contribute to such differences in results and outcomes include, without limitation, those specifically addressed under the heading “Risks Factors” in Item 1.A. below:

 

  our ability to acquire adequate funds to meet operating capital and satisfy debt obligations;
     
  our ability to obtain or access additional capital in connection with acreage acquisitions;
     
  our ability to successfully develop our acquisition of undeveloped and developed acreage and other assets acquired in December 2016 from Total Belief Ltd., a subsidiary of New Times Energy Corp., an entity whose securities trade on the Main Board of the Stock Exchange of Hong Kong Ltd., and to integrate the operations relating thereto with our existing operations and realize the benefits of such acquisition;
     
  our current financial position;
     
  risks associated with current and/or future potential litigation against the Company and/or its subsidiaries, including risks of asset seizures;
     
  our business strategy, including the use of independent contractors;
     
  meeting our forecasts and budgets;
     
  expectations regarding natural gas and oil markets in the United States;
     
  further or sustained declines in natural gas and oil prices;
     
  operational constraints, start-up delays and production shut-ins at both operated and non-operated properties;
     
  risks associated with bringing shut in wells into commercial levels of production;
     
  risks associated with exploration, including cost overruns and drilling of non-economic wells or dry holes, especially in prospects in which we have made a relatively large capital commitment relative to the size of our capitalization structure;
     
  timing and successful drilling and completion of natural gas and oil wells;

 

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  availability of capital and the ability to repay indebtedness when due;
     
  availability and cost of rigs and other materials and operating equipment;
     
  timely and full receipt of sale proceeds from the sale of our production;
     
  the ability to find, acquire, market, develop and produce new natural gas and oil properties;
     
  interest rate volatility, which might affect the Company’s borrowing costs;

 

  uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures;
     
  the need to take impairments on our properties due to lower commodity prices;
     
  operating hazards attendant to the natural gas and oil business including weather, environmental risks, accidental spills, blowouts and pipeline ruptures, and other risks;
     
  downhole drilling and completion risks that are generally not recoverable from third parties or insurance;
     
  potential mechanical failure or under-performance of significant wells, production facilities, processing plants or pipeline mishaps;
     
  actions or inactions of third-party contractors;
     
  actions or inactions of third-party operators of pipelines or processing facilities;
     
  the ability to find and retain skilled personnel;
     
  strength and financial resources of competitors;
     
  Federal, tribal and state legislative and regulatory developments and approvals;
     
  worldwide economic conditions, which may impact the market price of oil and/or natural gas and thereby affect the Company’s net revenues from oil and/or natural gas production;
     
  the ability to construct and operate infrastructure, including pipeline and production facilities, in the event this is required for the Company to produce oil and/or natural gas from its properties;
     
  operating costs, production rates and ultimate reserve recoveries of our natural gas and oil discoveries;
     
  expanded rigorous monitoring and testing requirements; and
     
  our ability to obtain insurance coverage on commercially reasonable terms.

 

Any of these factors and other factors contained, as well as those discussed elsewhere in this Annual Report on Form 10-K/A. Readers are urged not to place undue reliance on these forward-looking statements, which speak only as of the date of this Annual Report on Form 10-K/A. We file reports with the Securities and Exchange Commission (“SEC”). We make available on our website under “Investor Relations/SEC Filings,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file such materials with or furnish them to the SEC. Our website address is www.foothillspetro.com. You can also read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You can obtain additional information about the operation of the Public Reference Room by calling the SEC at 1-800-877-8339. In addition, the SEC maintains an Internet site (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us. We will provide a copy of our annual report to security holders, including audited financial statements, at no charge upon receipt of a written request to us at Foothills Exploration, Inc., 633 17th Street, Suite 1700, Denver, Colorado, 80202.

 

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We undertake no obligation to revise or update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this Annual Report on Form 10-K. Readers are urged to carefully review and consider the various disclosures made throughout the entirety of this annual Report, which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operations and prospects.

 

For definitions of certain oil and gas industry terms used in this Annual Report on Form 10-K, please see the Glossary beginning on page 12.

 

Background

 

Foothills Exploration, Inc. (the “Company”) was incorporated in the state of Delaware on May 13, 2010, under the name “Key Link Assets Corp.” for the purpose of acquiring a portfolio of heavily discounted real estate properties in the Chicago metropolitan area. The Company changed its focus and planned to acquire small and medium sized grocery stores in non-urban locales that are not directly served by large national supermarket chains.

 

On May 2, 2016, Foothills Petroleum Inc., a Nevada corporation (“FPI”) acquired approximately 14.1 million pre-split (56.4 million post-split) shares of the Company’s common stock constituting approximately 96% of our then issued and outstanding shares (“FPI Acquired Shares”). As of May 16, 2016, we effected a 4:1 forward split of our shares of common stock.

 

On May 27, 2016, the Company entered into a Share Exchange Agreement with shareholders of FPI whereby we acquired all of the outstanding shares of FPI in exchange for 4,500,000 shares of our common stock and also issued 1,503,759 shares of our common stock on automatic conversion of debt (please see discussion below under Overview) for an aggregate of 6,003,759 shares of our common stock (the “Share Exchange”). As a result of the Share Exchange, FPI became our wholly owned subsidiary and the FPI Acquired Shares were returned to treasury and deemed cancelled. For accounting purposes, this transaction is being accounted for as a reverse acquisition and has been treated as a recapitalization of the Company with FPI considered the accounting acquirer, and the financial statements of the accounting acquirer became the financial statements of the registrant. The completion of the Share Exchange resulted in a change of control. The FPI Shareholders obtained approximately 96% of voting control on the date of Share Exchange. FPI was the acquirer for financial reporting purposes and the Company was the acquired company. The consolidated financial statements after the acquisition include the balance sheets of both companies at historical cost, the historical results of FPI and the results of the Company from the acquisition date. All share and per share information in the accompanying consolidated financial statements and footnotes have been retroactively restated to reflect the recapitalization.

 

Prior to the Share Exchange, we had minimal assets and recognized no revenues from operations and were accordingly classified as a shell company. On June 24, 2016, we filed an Amendment No. 1 to our Current Report on Form 8-K originally filed on June 10, 2016, indicating that we were no longer a shell company as defined by Rule12b-2 of the Exchange Act. In light of the closing of the Share Exchange, the Company became actively engaged in oil and gas operations.

 

On August 4, 2016, the Financial Industry Regulatory Association (“FINRA”) approved our name change from Key Link Assets Corp. to Foothills Exploration, Inc., and a change of trading symbol from KYLK to FTXP.

 

On October 5, 2016, the Company launched its Exploration Division and opened a new office in Houston to support the division’s staff. That division consisted of geologists and petroleum engineers engaged in the exploration and development of hydrocarbons who were tasked with building a portfolio of high impact exploration projects in the Gulf Coast region. On March 27, 2018, we closed that office.

 

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On December 12, 2016, the Company entered into a participation agreement with Magna Operating, LLC, a privately held Houston-based independent exploration and production company (“Magna Operating”), in relation to the Labokay prospect, covering approximately 240 acres in Calcasieu Parish, Louisiana. As consideration for an assignment of interest in and to the leases and the prospect, Foothills Petroleum Operating, Inc., a Nevada corporation and indirect wholly-owned subsidiary of the Company (“FPOI”), tendered to Magna Operating the purchase price in the amount of $144,000. This amount covered FPOI’s share of the land, lease, and administrative costs that Magna Operating incurred in generating and assembling the Labokay prospect as of November 15, 2016. As further consideration for an assignment of working interest in and to the leases, FPOI agreed to participate in the cost, risk, and expense of drilling the Labokay test well. The well was plugged and abandoned in February 2017. The Company has no immediate plans to engage in further exploration and development activities in the U.S. Gulf Coast region.

 

On December 30, 2016, the Company acquired various oil and gas assets (the “Uinta Agreement”). These assets included certain oil and gas wells throughout the Uinta Basin in Utah on acreage with over 30 proved undeveloped drilling locations, additional non-operated interest in other leases, and access to approximately 5,600 acres in the Uinta Basin with proved and probable reserves and existing infrastructure in place. Through the acquisition, Foothills also obtained six shut-in wells in the Natural Buttes Field, Utah. The transaction provided Foothills with the rights to an agreement to acquire up to 5,600+ acres and up to 16 shut-in oil and gas wells with proved and proved undeveloped reserves on Tribal lands in the Uinta Basin. This acquisition delivered to the Company an additional 40% working interest in the Ladysmith Prospect covering 3,060 acres in the Greater Green River Basin, Wyoming, bringing the Company’s total working interest in the prospect from 35% (pre-acquisition) up to 75%.

 

Pursuant to the Uinta Agreement the Company acquired 13,166,667 shares, constituting 55.6% of the outstanding shares of Grey Hawk Exploration, Inc. (“Grey Hawk”), a British Columbia, Canada company. Grey Hawk owns a non-operated working interest in two non-producing wells in the southern portion of the Natural Buttes Field.

 

On December 30, 2016, the Company acquired the remaining 25% membership interest in TEPI from Green Stone Capital Partners Limited, a Cayman Islands limited liability company, in exchange for assumption of Greenstone’s proportionate share of TEPI obligations and liabilities.

 

Effective August 28, 2017 , the Company acquired a 21.6% working interest, with a 17.1% net revenue interest, in two (2) exploratory, horizontal wells in Uintah County, Utah, from an undisclosed party. These wells were drilled through an existing wellbore into an unproved reservoir. Both wells are operated by EOG Resources, Inc. (NYSE: EOG) (“EOG”). We expect total costs for our working interest in both wells will be approximately $3.2 million based on Authorizations for Expenditures to which we agreed. Of those total costs, we incurred $1.5 million during 2017. These wells align with the Company’s overall growth strategy for the basin and provide us with the ability to gain insight from a world-class operator. The Stagecoach 111-20H and Stagecoach 117-20H horizontal wells both commenced producing natural gas liquids, and residue gas in commercial quantities in December 2017, despite the wells having not yet been completed. These two successful horizontal wells are expected to generate production and net cash flow for the Company subject to the Company’s payment to EOG of the Company’s share of costs incurred in the drilling and completion of the wells.

 

Our principal office is located at 633 17th Street, Suite 1700, Denver, Colorado 80202. Our telephone number is (720) 449-7478. Our website address is www.foothillspetro.com.

 

Overview

 

The Company is an exploration stage company engaged in the acquisition and development of oil and natural gas properties. The Company is focused on acquiring producing and developmental properties in the U.S. Rocky Mountain region. The Company seeks to acquire non-core, dislocated, underdeveloped, and underexplored oil and gas assets and maximize those assets to create shareholder value.

 

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Industry and Market Data

 

The market data and certain other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources. In addition, some data are based on our good faith estimates.

 

Market Environment

 

The U.S. energy markets finished strong in 2017 as improving fundamentals for both oil and natural gas buoyed energy prices going into the close of the year. Looking ahead in 2018, we believe the U.S. energy markets’ improving fundamentals will continue to strengthen and will position the U.S. as a global leader for producing fossil fuels and lead to further growth of U.S. exports. We also expect an uptick in price volatility heading into 2018. Our bias is moderately bullish at current levels for both WTI oil prices and natural gas prices as strong global demand for products is partially offset by rising oil and natural gas production out of U.S. shale formations.

 

Oil – The prevailing theme in 2017 was OPEC and Non-OPEC producing nations’ production cuts and extensions of these cuts throughout the year. In the fourth quarter of 2017, OPEC had announced extending the cuts once again in 2018. The production cuts have gained traction as the global oil markets’ supply/demand rebalanced and global stock piles haven decreased materially. For 2018, we see a second prevailing theme emerging, which is global demand. The International Energy Agency (IEA) in its monthly oil market report for February 2018 forecast global demand to increase by 1.4 million barrels per day in 2018 with peak demand of 100.0 million barrels per day in the fourth quarter of 2018. The Energy Information Administration (“EIA”), in its “Short-Term Energy Outlook” dated March 6, 2018 is forecasting that U.S. crude oil production will average 10.7 million barrels per day in 2018, which would mark the highest annual average U.S. crude oil production level, surpassing the previous record of 9.6 million b/d set in 1970. In the same report, the EIA is forecasting WTI oil prices to average $58 a barrel for both 2018 and 2019. No assurance can be given that this outlook will prove to be accurate.

 

Natural Gas – The EIA in its “Short-Term Energy Outlook” dated March 6, 2018 estimates that U.S. dry natural gas production averaged 73.6 billion cubic feet per day (Bcf/d) in 2017. The EIA forecasts that natural gas production will average 81.7 Bcf/d in 2018, establishing a new record. That level would be 8.1 Bcf/d higher than the 2017 level and the highest annual average growth on record. The EIA forecasts dry gas consumption will average 78.19 billion cubic feet per day (Bcf/d) while net exports will average 2.09 billion cubic feet per day (Bcf/d) in 2018. The EIA expects Henry Hub spot prices to average $2.99/MMBtu for all of 2018. In 2019, EIA forecasts prices will average $3.07/MMBtu. No assurance can be given that this outlook will prove to be accurate.

 

Commodity Price Environment

 

Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. Commodity prices are beyond our control and are difficult to predict. Many factors enter into the price of oil, both domestic and foreign.

 

Governmental Regulation and Environmental Consideration

 

The oil and gas business in the United States is subject to regulation by both federal and state authorities, particularly with respect to pricing, allowable rates of production, marketing and environmental matters. The production of crude oil and gas has, in recent years, been the subject of increasing state and federal controls. No assurance can be given that newly imposed or changed federal laws will not adversely affect the economic viability of any oil and gas properties we currently own and/or may acquire in the future. Federal income and “windfall profit” taxes have in the past affected the economic viability of such properties. The following discussion provides a brief overview of potential state and federal regulations. Because Foothills to date has acquired specific properties, and because of the wider range of activities in which the Company expects to participate, management believes that it is not practical currently to set forth in detail the potential impact federal and state regulations may have on our operations.

 

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The Department of Energy

 

The Department of Energy Organization Act (Pub. L. No. 95-91) became effective October 1, 1977. Under this Act various agencies, including the Federal Energy Administration (FEA) and the Federal Power Commission (FPC), have been consolidated to constitute the cabinet-level Department of Energy (DOE). The Economic Regulatory Administration (ERA), a semi-independent administration within the DOE, now administers most of the regulatory programs formerly managed by the FEA, including oil pricing and allocation. The Federal Energy Regulatory Commission (FERC), an independent agency within the DOE, has assumed the FPC’s responsibility for natural gas regulation.

 

Crude Oil and Natural Gas Liquids Price and Allocation Regulation

 

Pursuant to Executive Order Number 12287, issued January 28, 1981, President Reagan lifted all existing federal price and allocation controls over the sale and distribution of crude oil and natural gas liquids. Executive Order Number 12287 was made effective as of January 28, 1981, and consequently, sales of crude oil and natural gas liquids after January 27, 1981 are free from federal regulation. The price for such sales and the supplier-purchaser relationship will be determined by private contract and prevailing market conditions. Because of this action, oil that may be sold by us will be sold at deregulated or free market prices. At various times, certain groups have advocated the reestablishment of regulations and control on the sale of domestic oil and gas.

 

State Regulations

 

Foothills’ production of oil and gas, if any, will be subject to regulation by state regulatory authorities in the states in which we may produce oil and gas. In general, these regulatory authorities are empowered to make and enforce regulations to prevent waste of oil and gas and to protect correlative rights and opportunities to produce oil and gas as between owners of a common reservoir. Some regulatory authorities may also regulate the amount of oil and gas produced by assigning allowable rates of production.

 

Environmental Laws

 

Oil and gas exploration and development are specifically subject to existing federal and state laws and regulations governing environmental quality and pollution control. Such laws and regulations may substantially increase the costs of exploring for, developing, or producing oil and gas and may prevent or delay the commencement or continuation of a given operation.

 

All of our operations involving the exploration for or the production of any minerals are subject to existing laws and regulations relating to exploration procedures, safety precautions, employee health and safety, air quality standards, pollution of streams and fresh water sources, odor, noise, dust, and other environmental protection controls adopted by federal, state and local governmental authorities as well as the right of adjoining property owners. We may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of minerals may have upon the environment. All requirements imposed by any such authorities may be costly, time consuming, and may delay commencement or continuation of exploration or production operations.

 

It may be anticipated that future legislation will significantly emphasize the protection of the environment, and that, as a consequence, our activities may be more closely regulated to further the cause of environmental protection. Such legislation, as well as future interpretation of existing laws, may require substantial increases in equipment and operating costs to us and delays, interruptions, or a termination of operations, the extent to which cannot now be predicted.

 

Title to Properties

 

Foothills owns the interest in its properties and also at times relies on contracts with the owner or operator of the property, pursuant to which, among other things, the Company has the right to have its interest placed of record. As is customary in the oil and gas industry, we anticipate that a preliminary title examination will be conducted at the time unproved properties or interests are acquired by us. Prior to commencement of drilling operations on such acreage and prior to the acquisition of proved properties, Foothills will conduct a title examination and attempt to cure materially significant defects before proceeding with operations or the acquisition of proved properties, as it may deem appropriate. Foothills properties are subject to royalty, overriding royalty and other interests customary in the industry, liens incident to agreements, current taxes and other burdens, minor encumbrances, easements and restrictions. Foothills’ Utah properties acquired from Total Belief Limited on December 30, 2016, are subject to a certain Bureau of Indian Affairs (“BIA”) Administrative Appeal and a Ute Indian Tribe Global Settlement Agreement, each of which does or may affect title to some, all or none of the properties acquired. Foothills is currently attempting to cure title on these properties, subject to the outcome of the BIA Administrative Appeal, which is still ongoing as of July 26, 2018. To the extent that such defects or disputes exist and cannot be cured, Foothills would suffer title failures, which could result in property valuation impairments and other material adverse consequences to the operations of the Company.

 

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Employees

 

As of December 31, 2017 and 2016, we had 5 and 6 employees, respectively, including our executive officers.

 

Our Strategy

 

Our strategic objective is to build a portfolio of producing properties that have low operating costs, long lived reserves, and upside development potential. Our goal is to build a land bank of over 200,000 net acres of proved, probable, and prospective reserves during this period of relatively low commodity pricing. We intend to accomplish this by acquiring oil and gas properties with attractive valuation metrics and attractive geological risk/reward profiles that are better positioned to benefit from an improvement in commodity prices. Our primary focus is the U.S. Rocky Mountain region, where our consultants and technical staff have conducted successful oil and gas operations. Our geographical focus, regional experience, and strategic industry relationships advantageously position the Company to acquire high quality oil and gas assets at attractive valuations in the current environment.

 

Our acquisitions and roll up strategy is based on identifying high-quality, non-core, stranded, and distressed assets in the U.S. Rocky Mountain region, which are selling at a discount to intrinsic value. We are primarily focused on acquiring oil and gas assets that come with current production, existing infrastructure in place, and future developmental potential. Acquired assets are subsequently optimized to maximize production and create shareholder value. Our strategy includes targeting adjacent oil and gas properties with similar characteristics for bolt on acquisitions to increase total acreage in a concentrated geographical area, enabling us to optimize the profitable operation of those assets. Our business involves:

 

  Identifying, evaluating, and making strategic acquisitions of producing oil and gas properties;
     
  Integrating, optimizing, and operating the assets acquired;
     
  Developing the properties to grow proved reserves; and
     
  Consolidating additional acreage nearby existing controlled acreage.

 

We seek to acquire high quality oil and gas assets that have been underexplored and underdeveloped. The industry’s recent flight to the Permian and Delaware Basins has encouraged major exploration and production companies to divest of quality non-core assets in other (secondary) basins in other regions, such as the Rocky Mountains, in order to generate cash for reinvestment into their core (primary) target investment basins like the Permian or Delaware Basins. We aim to achieve a lower cost of entry and generate an overall better return on invested capital by acquiring assets at a discount to inherent value, optimizing and developing those assets, and then operating those assets profitably, even at current energy prices. Management believes that accomplishing these objectives will create and maximize shareholder value in the long term.

 

Our Properties  

 

Program  Unproved Acreage   Proved Acreage   Total Acreage 
   Gross   Net   Gross   Net   Gross   Net 
Wyoming   5,621    5,621            5,621    5,621 
Utah           7,842    7,842    7,842    7,842 
Total   5,621    5,621    7,842    7,842    13,463    13,463 

 

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Wyoming Properties

 

The principal Wyoming assets that we own currently consist of non-producing, prospective mineral leases in the Ladysmith and Paw Paw projects. Our Wyoming properties are located in Fremont and Big Horn Counties, Wyoming.

 

Ladysmith Project

 

We own a 75% working interest in the Ladysmith Anticline prospect that is located in Fremont County, Wyoming. Total acreage position is 3,061 gross acres located between the Great Divide/Greater Green River Basin and the Wind River Basin. The primary target zones are the variable Phosphoria and Tensleep sandstone with secondary considerations in the Madison limestone and Flathead sandstone. The prospect generation was based on licensed 2-D seismic comprising two seismic lines covering the Chevron/Echo – Greater Green River Basin.

 

Paw Paw Project

 

The Paw Paw project is a 3-D seismic defined prospect, which covers 4,467 net acres and is a direct analog to the highly productive Tensleep Formation “Enigma” Field (EUR 3.7 million barrels of oil) located only two miles to the south. We own 100% working interest in 2,560 net acres of this project before Payout and this working interest is reduced to 75% after Payout. The Tensleep Formation has a history of prolific area production with two nearby analogous reservoirs. The Paw Paw project has potential from primary and secondary recovery of up to 2 million barrels of oil. On December 11, 2016, the Company completed drilling operations on the Paw Paw Federal #1 test well. The Big Horn County Wyoming test well reached total depth in the Madison Formation and the Company successfully logged and acquired valid data to further evaluate the project’s potential.

 

The Paw Paw Federal #1 test well reached total depth of 4,500 feet in the Madison Formation after drilling an anticipated stratigraphic section and thrust fault. Oil shows were found in the Muddy, Phosphoria, and Madison formations. The Phosphoria is a regionally productive formation and could end up being the secondary zone in sidetrack operations should that type of operation be deemed commercially economic.

 

As used herein, the term “Payout” shall be deemed to occur at 7:00 a.m. on the first day in which Foothills recovers out of its share of production from the Paw Paw Federal #1 (“Test Well”), after deduction of all royalties, existing overriding royalties, production or severance taxes, and any other burdens or taxes measured by or payable out of production, a sum equal to the aggregate of the following:

 

the aggregate costs and expenses of drilling, testing and completing the Test Well into the tanks or the pipeline to which the Test Well is connected, including the costs of all surface equipment attached or connected to the wellhead; and

 

the costs and expenses of operating during the Payout period (items i. and ii. shall be calculated and governed by the terms and provisions of the accounting procedure attached to the Paw Paw Unit Operating Agreement).

 

Utah Properties

 

The Utah properties are located in Uintah and Duchesne Counties, comprising operated and non-operated working interests as well as rights and interests in a project for future development.

 

The Company operates through TEO six oil and gas wells situated on 280 gross acres (224 net) in the Duck Creek area of the Altamont Bluebell field located in Uintah County, Utah, in which the Company has a 100% working interest with an 80% net revenue interest.

 

The Company owns all rights and interests pertaining to the Global Settlement Agreement (“GSA”) for the Uintah and Ouray Reservation among Mountain Oil & Gas, Inc (‘MOG”) and entities associated with MOG and the Ute Indian Tribe of the Uintah and Ouray Reservation, dated December 22, 2014. The Company also owns all rights and interests acquired in the Purchase and Sale Agreements between TEPI and Mountain Oil & Gas, Inc. dated April 16, 2012, and December 18, 2012. The Company expects to move forward with this transaction in 2018 via a revised Global Settlement Agreement with the parties to said agreement.

 

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The Company owns a very small (under 1%) non-operated working interest in certain leases located in Duchesne County, Utah. The Company recognized approximately $4,532 in net revenues during 2017 from this non-operated working interest.

 

On August 28, 2017, the Company acquired a 21.6% non-operated working interest with a 17.1% net revenue interest in two horizontal wells in the Uintah Basin (“Basin”). First sales from the two wells were made in December 2017, and the well was successfully completed and tested in February 2018.

 

Plan of Operations

 

Over the near-term the Company believes that it is well positioned to capitalize on the current relatively low-price environment. Foothills intends to acquire dislocated oil and gas assets as well as non-core assets from larger exploration and production companies seeking to divest assets in secondary basins as the industry continues its migration to the Permian and Delaware Basins. In addition to a favorable macroeconomic environment for acquiring attractive oil and gas assets, management intends to leverage our geographical focus in the Rocky Mountain region. We are focused on acquiring and rolling up smaller operators in a considerably fragmented oil and gas market; and, through consolidation, management believes the Company can effectively scale its production and acreage position and collectively unlock value in the acquired oil and gas assets to create shareholder value.

 

Acquiring Additional Assets

 

The Company is currently targeting several prospective acquisitions in a tightly defined geographical area of interest that meet certain metrics and future development potential. Management’s current focus has shifted to oil-weighted projects, given crude’s moderate recovery in recent months and the desire to diversify the Company’s current natural gas-weighted projects. The Company anticipates that future acquisitions will be funded through the sale of common stock, debt and cash generated from the Company’s financing activities, including public, private and institutional offerings in capital market transactions and future reserve-based lending activities. Subject to the securing of additional capital, the Company anticipates the expenditure of up to $45 million to fund additional bolt-on acquisitions of producing properties, which can potentially be leveraged and optimized by applying its technical capabilities and improving operational efficiencies. Although the Company is currently evaluating several prospective acquisitions, which meet its criteria and anticipates making an announcement regarding its next acquisition in the near term, no assurance can be given that it will be successful in any of these endeavors.

 

Retain Operational Control and Significant Working Interest

 

In its principal acquisition and development targets, the Company aims to preserve operational control of its development and drilling activities. As the operator for its projects, the Company retains more control over the timing, selection and process of drilling prospects and completion design, which enhances its ability to maximize the return on invested capital and gives greater control over the timing, allocation and amounts of capital expenditures. However, the Company will always evaluate and consider making strategic acquisitions of non-operated working interest in certain projects with world-class operators that are located within our geographical areas of interest.

 

GLOSSARY OF OIL AND GAS TERMS

 

The following are the meanings of some of the oil and gas industry terms that may be used in this annual report.

 

2-D seismic: Geophysical data that depicts the subsurface strata in two dimensions. A vertical section of seismic data consisting of numerous adjacent traces acquired sequentially.

 

3-D seismic: A set of numerous closely-spaced seismic lines that provide a high spatially sampled measure of subsurface reflectivity. Events are placed in their proper vertical and horizontal positions, providing more accurate subsurface maps than can be constructed on the basis of more widely spaced 2D seismic lines. In particular, 3D seismic data provide detailed information about fault distribution and subsurface structures.

 

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Analogous reservoir: Reservoirs with similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure), and drive mechanisms but are typically at a more advanced stage of development than the reservoir of interest and, thus, may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (a) same geological formation (but not necessarily in pressure communication with the reservoir of interest), (b) same environment of deposition, (c) similar geological structure, (d) same drive mechanism. Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

 

Barrel: Standard volume of measure for crude oil and liquid petroleum products.

 

Basin: A depression of the earth’s surface into which sediments are deposited, usually characterized by sediment accumulation over a long interval; a broad area of the earth beneath which layers of rock are inclined, usually from the sides toward the center.

 

BCF: Billion cubic feet.

 

BOE: Barrel of oil equivalent. One barrel equals 42 US gallons. One/sixth of a barrel is equivalent to one MCF (thousand cubic feet) of natural gas.

 

BOE/D: Barrel of oil equivalent per day.

 

Completion: The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

 

Crude oil: A general term for unrefined petroleum or liquid petroleum.

 

Developmental drilling: Drilling that occurs after the initial discovery of hydrocarbons in a reservoir.

 

Developed nonproducing reserves: Those reserves that either have not been on production or have previously been on production but are shut-in, and the date of resumption of production is unknown. These are commonly referred to as PDNP reserves.

 

Developed producing reserves: Those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. These are commonly referred to as PDP reserves.

 

Developed reserves: Those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on production. The Developed category may be subdivided into producing and nonproducing.

 

Development well: A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

Dry hole: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

 

E&P: Exploration and production.

 

Exploration: The initial phase in petroleum operations that includes generation of a prospect or play or both, and drilling of an exploration well. Appraisal, development and production phases follow successful exploration.

 

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Exploratory well: A well drilled to find and produce oil or gas in an unproved area, find a new reservoir in a field previously found to be productive in another reservoir, or extend a known reservoir.

 

Farmout: An agreement whereby the owner of a lease (farmor) agrees to assign part or all of a leasehold interest to a third party (farmee) in return for drilling of a well or wells and/or the performance of other required activities. The farmee is said to “farm-in.”

 

Field: An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

 

Formations: Beds or deposits composed substantially of the same minerals throughout.

 

Fracturing or “Fracking”: Hydraulic fracturing is a method used to create fractures that extend from a borehole into rock formations, which are typically maintained by a proppant, a material such as grains of sand, ceramic beads or other material which prevent the fractures from closing. The method is informally called fracking or hydro-fracking. The technique of hydraulic fracturing is used to increase or restore the rate at which fluids, such as oil, gas or water, can be produced from the desired formation. By creating fractures, the reservoir surface area exposed to the borehole is increased.

 

Full cost: Method of accounting which can be elected by an E&P company. As described in Reg. S-X, Rule 4-10(c), a full cost company capitalizes all costs incurred in property acquisition, exploration, and development.

 

Gas show: While drilling a well through different rock formations, gas may appear in the drilling mud which is circulating through the drill pipe, which indicates the presence of gas in the formation being drilled; drillers call this a “gas show”.

 

Horizontal well: a well in which the borehole is deviated from vertical at least 80 degrees so that the borehole penetrates a productive formation in a manner parallel to the formation. A single horizontal lateral can effectively drain a reservoir and eliminate the need for several vertical boreholes.

 

Hydrocarbon: A naturally occurring organic compound comprising hydrogen and carbon. Hydrocarbons can be as simple as methane (CH 4), but many are highly complex molecules, and can occur as gases, liquids or solids. The molecules can have the shape of chains, branching chains, rings or other structures. Petroleum is a complex mixture of hydrocarbons. The most common hydrocarbons are natural gas, oil and coal.

 

Lease and well equipment: Wells and related equipment and facilities are often referred to in the oil and gas industry as lease and well equipment even though, technically, the property may have been acquired other than by a lease. The costs include those incurred to (a) drill and equip exploratory wells and exploratory-type stratigraphic test wells that have found proved reserves and (b) obtain access to proved reserves and provide facilities for extracting, treating, gathering, and storing the oil and gas, including the drilling and equipping of development wells and development-type stratigraphic test wells (whether those wells are successful or unsuccessful) and service wells.

 

MCF: Standard measure of volume for natural gas which is one thousand cubic feet.

 

MCFE: MCF equivalent. Six thousand cubic feet of natural gas is equivalent to one barrel of oil.

 

MCFE/D: MCF equivalent per day.

 

MSTB: Thousand stock tank barrels. Volume of oil after production at surface pressure and temperature (as opposed to reservoir conditions).

 

Net revenue interest (NRI): The portion of oil and gas production revenue remaining after the deduction of royalty and overriding royalty interests.

 

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NYMEX: The New York Mercantile Exchange, the world’s largest physical commodity futures exchange, located in New York City.

 

Operator: The individual or company responsible for the exploration and/or exploitation and/or production of an oil or gas well or lease.

 

Overriding royalty interest (ORRI): an interest carved out of a working interest that entitles its owner to a fraction of production free of any capital costs and production or operating expense but not free of production or severance tax levied on the production. An overriding interest’s duration derives from the lease in which it was created.

 

Participation interest: The proportion of exploration and production costs each party will bear and the proportion of production each party will receive, as set out in an operating agreement.

 

Production: The phase that occurs after successful exploration and development and during which hydrocarbons are extracted from an oil or gas field.

 

Proved properties: Properties with proved reserves.

 

Recompletion: After the initial completion of a well, the action and technique of re-entering the well and repairing the original completion or completing the well in a different formation to restore the well’s productivity.

 

Reservoir: A subsurface, porous, permeable rock formation in which oil and gas are found. Formations are confined by impermeable rock or water barriers and are individual and separate from other reservoirs.

 

Royalty interest: An ownership interest in the portion of oil, gas, and/or minerals produced from a well that is retained by the lessor upon execution of a lease or to one who has acquired possession of the royalty rights, based on a percentage of the gross production from the property free and clear of all costs except taxes.

 

Seismic: Exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape, and depth of subsurface rock formations. 2-D seismic provides two-dimensional information, and 3-D seismic provides three dimensional pictures. 4-D seismic produces 3-D pictures over time and is used to indicate fluid movement in producing reservoirs.

 

Shale: A type of sedimentary rock from which oil and gas can be produced by utilizing different extraction techniques.

 

Shut in: Not currently producing.

 

SMOG: Acronym for the disclosure, required by the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932 – Extractive Activities – Oil and Gas, of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves.

 

Service well: Well drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane, or flue gas), water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

 

Support facilities and equipment: Support equipment and facilities used in oil and gas producing activities, such as seismic equipment, drilling equipment, construction and grading equipment, vehicles, repair shops, warehouses, supply points, camps, and division, district, or field offices.

 

Uncompleted wells, equipment, and facilities: Uncompleted wells, equipment and facilities, the costs of which include those incurred to (a) drill and equip wells that are not yet completed and (b) acquire or construct equipment and facilities that are not yet completed and installed.

 

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Undeveloped reserves: those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. These are commonly referred to as PUD. We do not at this time include probable and possible proved reserves in our calculation of future cash flows and standardized measure of future cash flows in our Supplemental Oil and Gas Disclosures contained in the footnotes to our consolidated financial statements.

 

Unproved properties: Properties with no proved reserves.

 

Wildcat: Exploratory well that is particularly risky (i.e., information from seismic data or nearby producing fields is not available to support the prospect).

 

Working interest: The interest in oil or gas that includes the responsibility for all drilling, developing, and operating costs.

 

Workover: The performance of one or more of a variety of remedial operations on a producing well to try to increase or restore production.

 

ITEM 1A. Risk Factors.

 

The statements that are not historical facts contained in this Form 10-K are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements reflect the current belief, expectations or intent of our management and are subject to and involve certain risks and uncertainties. Many of these risks and uncertainties are outside of our control and are difficult for us to forecast or mitigate. An investment in our common stock is speculative and involves a high degree of risk. In addition to the risks described elsewhere in this Form 10-K and in certain of our other filings with the US Securities and Exchange Commission, the following important factors, among others, could cause our actual results to differ materially from those expressed or implied by us in any forward-looking statements contained herein or made elsewhere by or on behalf of us. The risks described below are not the only risks we face. If any of the events described in the following risk factors actually occurs, or if additional risks and uncertainties later materialize that are not presently known to us or that we currently deem immaterial, then our business, prospects, results of operations and financial condition could be materially adversely affected. In that event, the trading price of our common stock or our warrants could decline, and you may lose all or part of your investment in our common stock.

 

RISK FACTORS RELATED TO OUR COMPANY

 

Our business has a very limited operating history and is unproven, and therefore very risky.

 

In May 2016, the Company changed its focus to operate as an independent oil and gas exploration and production company. It was not until January 2017 that the Company commenced operations under the business plan discussed herein. Potential investors should be aware of the risks and difficulties encountered by a new enterprise in the oil and gas industry, especially in view of the material amounts of capital required, the drilling and other operational and commodity fluctuation risks, as well as intense competition from existing companies in the same industry segments as we operate.

 

We have no significant revenue history and have a short history of operations.

 

We have only recently begun operations in the oil and gas industry. From its inception in December 2015 through December 31, 2017, Foothills produced limited revenues from its principal business operations and is currently still an exploration stage company. Prior to January 2016, Foothills had minimal operations that were focused mainly on administrative activities connected to the identification and evaluation of potential oil and gas prospects and other potential leasehold acquisitions in our geographical areas of interest.

 

We are not profitable and the business effort is considered to be in an early stage of operations. We must be regarded as a new or development venture with all of the unforeseen costs, expenses, problems, material risks and difficulties to which such ventures are subject.

 

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We can give no assurance of success or profitability to our investors.

 

There is no assurance that we will ever operate profitably, or that we will generate adequate revenues to offset our operating costs or that the market price of our common stock will be increased thereby.

 

We may have a shortage of working capital in the future which could jeopardize our ability to carry out our business plan.

 

Our operating capital needs consist primarily of expenses related to geological evaluation, general and administrative and potential exploration participation. We are currently seeking to raise more than $5 million and are currently engaged in discussions with financing sources. The Company is currently evaluating several potential acquisitions and will likely need additional capital in the form of equity or debt, including possible bank debt. Such funds are not currently committed and no assurance can be given that we will be able to secure such financing on favorable terms or on any terms at all. The failure to obtain such funds will have a negative impact on our ability to fund daily activities and materially and adversely affect the execution of our business plan.

 

If we find oil and gas reserves to exist on a prospect, we will need substantial additional financing to fund the necessary exploration and development work. Furthermore, if the results of that exploration and development work are successful, we will need to obtain substantial additional funds for continued development. We will need to obtain the necessary funds either through debt or equity financing, some form of cost-sharing arrangement with others, or the sale of all or part of the property. There is no assurance that we will be successful in obtaining any financing. These various financing alternatives may dilute the interest of our shareholders and/or reduce our interest in the properties.

 

We will need additional financing for which we have no commitments, and this may jeopardize execution of our business plan.

 

The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, drilling, production, and acquisition of properties, crude oil, natural gas, and natural gas liquids reserves. We intend to finance our future capital expenditures primarily with sales of our equity, cash flow from operations, as well as privately secured and institutionally obtained borrowings. Our cash flow from operations and access to equity and debt capital is subject to a number of variables, including:

 

  Our anticipated, probable and proved reserves.
     
  The level of crude oil, natural gas and natural gas liquids we are or might be able to produce from existing wells.
     
  The prices at which crude oil, natural gas and natural gas liquids are sold.
     
  Our ability to acquire, locate and produce new reserves and valuable acreage prospects.

 

We have limited funds, and such funds currently are not adequate to execute our business plan in the oil and gas industry. We may not be able to obtain debt or equity financing on terms favorable to us, or at all. In particular, the cost of raising money in the debt and equity capital markets has increased substantially, while the availability of funds from those markets generally has diminished significantly, particularly for small, early stage companies such as ours. Also, as a result of concerns about the stability of financial markets generally and the recent and future Federal Reserve interest rate hikes, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, may refuse to extend or refinance existing debt at maturity on terms that are similar to existing debt, and reduced, or in some cases ceased, to provide funding to borrowers. The failure to obtain additional financing could result in a material curtailment of our operations relating to acquisitions, exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our crude oil, natural gas and natural gas liquids reserves.

 

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We may in the future issue more shares which could cause a loss of control by our present management and current stockholders.

 

We may issue further shares as consideration for the cash or assets or services out of our authorized but unissued common stock that would, upon issuance, represent a majority of the voting power and equity of our Company. The result of such an issuance would be that those new stockholders and management would control our Company, and thereafter persons unknown could replace our management. Such an occurrence would result in a greatly reduced percentage of ownership of our Company by our current shareholders, which could present significant risks to investors.

 

We have warrants issued and outstanding which are convertible into our common stock. A conversion of such equity instruments could have a dilutive effect to existing shareholders.

 

As of December 31, 2017, we have warrants issued and outstanding exercisable into 2,683,515 shares of our common stock, that are exercisable in whole or in part, at exercise prices which range from $0.665 per share to $4.00 per share. The weighted average exercise price is $1.56 per share. The exercise of the warrants into shares of our common stock may have a dilutive effect to the holdings of our existing shareholders.

 

We depend upon management, but we may at times have limited participation of management.

 

Currently our directors are also acting as our officers. We are heavily dependent upon their skills, talents, and abilities, as well as several consultants to us, to implement our business plan, and may, from time to time, find that the inability of our directors and consultants to devote their full-time attention to our business results in a delay in progress toward implementing our business plan. Consultants may be employed on a part-time basis under contracts to be determined.

 

Some of our directors are, or may become, in their individual capacities, officers, directors, controlling shareholders and/or partners of other entities engaged in a variety of businesses. Thus, some of our directors may have potential conflicts including their time and efforts involved in participation with other business entities. Because investors will not be able to manage our business, they should critically assess all of the information concerning our officers and directors.

 

We have agreed to indemnification of officers and directors.

 

Delaware and Nevada statutes provide for the indemnification of our directors, officers, employees, and agents, under certain circumstances, against attorney’s fees and other expenses incurred by them in any litigation to which they become a party arising from their association with or activities on our behalf. We will also bear the expenses of such litigation for any of our directors, officers, employees, or agents, upon such person’s promise to repay us therefore if it is ultimately determined that any such person shall not have been entitled to indemnification. This indemnification policy could result in substantial expenditures by us that we will be unable to recoup.

 

RISK FACTORS RELATING TO OUR BUSINESS

 

Our oil and gas operations have numerous risks which could render us unsuccessful.

 

The search for new oil and gas reserves and the operation of oil and gas properties frequently results in unprofitable efforts. We have for example experienced two commercially unproductive wells drilled. Existing wells acquired may become costly to refurbish and maintain, resulting in losses. There is no assurance that we will find or produce oil or gas from any of the wells we have acquired or which may be acquired by us, nor are there any assurances that if we ever obtain any production it will be profitable.

 

We have substantial competitors who have an advantage over us in resources and management.

 

Most of our competitors have materially greater financial resources, technical expertise and managerial capabilities than us and, consequently, we are at a competitive disadvantage in identifying, developing or exploring suitable prospects. Our competitors’ resources could overwhelm our restricted efforts to acquire and explore oil and gas prospects and cause failure of our business plan.

 

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We will be subject to all of the market forces in the energy business, many of which could pose a significant risk to our operations.

 

The marketing of natural gas and oil, which may be produced by our prospects, will be affected by a number of factors beyond our control. These factors include the extent of the supply of oil or gas in the market, the availability of competitive fuels, crude oil imports, the world-wide political situation, price regulation, and other factors. Current economic and market conditions have created dramatic fluctuations in oil prices. Any significant decrease in the market prices of oil and gas could materially affect our profitability of oil and gas activities.

 

There generally are only a limited number of gas transmission companies with existing pipelines in the vicinity of a gas well or wells. In the event that producing gas properties are not subject to purchase contracts or that any such contracts terminate and other parties do not purchase our gas production, there is no assurance that we will be able to enter into purchase contracts with any transmission companies or other purchasers of natural gas and there can be no assurance regarding the price, which such purchasers would be willing to pay for such gas. There may, on occasion, be an oversupply of oil or gas in the marketplace or in pipelines, the extent and duration of which may affect prices adversely. Such oversupply may result in reductions of purchases and prices paid to producers by principal oil or gas pipeline purchasers.

 

We believe investors should consider certain negative aspects of our operations that could result in material losses.

 

Dry Holes: We may expend substantial funds acquiring and potentially participating in exploring properties, which we later determine not to be productive. All funds so expended may result in a total loss to us.

 

Technical Assistance: We will find it necessary to employ technical assistance in the operation of our business. When we deem it appropriate to seek such assistance, we believe it is likely to be available at compensation levels that we would be unable to pay.

 

Uncertainty of Title: We will attempt to acquire leases or interests in leases by option, lease, farmout, participation agreement or by purchase. The validity of title to oil and gas property depends upon numerous circumstances and factual matters (many of which are not discoverable of record or by other readily available means) and is subject to many uncertainties of existing law and our application.

 

Government Regulations: The area of exploration of natural resources has become significantly regulated by state and federal governmental agencies, and such regulation could have an adverse effect on our operations. Compliance with statutes and regulations governing the oil and gas industry could significantly increase the capital expenditures necessary to develop our prospects.

 

Nature of our Business: Our business is highly speculative, involves the commitment of high-risk capital, and exposes us to potentially substantial losses. In addition, we will be in direct competition with other organizations, which are significantly better financed and staffed than we are.

 

General Economic and Other Conditions: Our business may be adversely affected from time to time by such matters as changes in general economic, industrial and international conditions; changes in taxes; oil and gas prices and costs; excess oil and gas supplies and other factors of a general nature.

 

Our business is subject to significant weather interruptions.

 

Our activities may be subject to periodic interruptions due to weather conditions. Weather-imposed restrictions during certain times of the year on roads accessing properties could adversely affect our ability to benefit from production on such properties or could increase the costs of drilling new wells or costs of operating existing wells because of delays.

 

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Our use of 2D and 3D seismic data is subject to interpretation and may not accurately identify the presence of crude oil, natural gas and natural gas liquids. In addition, the use of such technology requires greater predrilling expenditures, which could adversely affect the results of our drilling operations.

 

In making the decision to drill our initial two wells in the Paw Paw and Labokay prospects, we made material use of 2D and 3D seismic data and those two wells drilled did not yield commercial shows of oil or gas. Our decisions to purchase, explore, develop and exploit prospects or properties will continue to depend in part on data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are uncertain. However, even when used and properly interpreted, 2D and 3D seismic data and visualization techniques only assist geoscientists and geologists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know if hydrocarbons are present or producible economically. Other geologists and petroleum professionals, when studying the same seismic data, may have significantly different interpretations than our professionals.

 

In addition, the use of 3D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses due to such expenditures or otherwise in the acquisition of that data. As a result, our drilling activities may not be geologically successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area may not improve.

 

The potential lack of availability of, or cost of, drilling rigs, equipment, supplies, personnel and crude oil field services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.

 

When the prices of crude oil, natural gas and natural gas liquids increase, or the demand for equipment and services is greater than the supply in certain areas, such as those in which we operate, we expect to encounter an increase in the cost of securing drilling rigs, equipment, oil field services and supplies. In addition, larger producers may be more likely to secure access to such equipment by offering more lucrative terms. If we are unable to acquire access to such resources, or can obtain access only at higher prices, our ability to locate and generate production or to convert our reserves into cash flow could be delayed and the cost of seeking or producing those reserves could increase significantly, which would adversely affect our results of operations and financial condition.

 

Natural gas and oil prices fluctuate widely, and a continued substantial or extended decline in natural gas and oil prices would adversely affect our revenues, profitability and growth, and could have a material adverse effect on the business, the results of operations and financial condition of the Company.

 

Our revenues, profitability, and future growth depend significantly on natural gas and crude oil prices. Natural gas and crude oil prices recovered moderately in 2017. The markets for these commodities are volatile, and prices received affect the amount of future cash flow available for capital expenditures and repayment of indebtedness and our ability to raise additional capital through the sale of our securities or other capital raising techniques. Lower prices also affect the amount of natural gas and oil that we might economically produce. Factors that can cause price fluctuations include but are not limited to:

 

  Overall economic conditions, domestic and global;
     
  The domestic and foreign supply of natural gas and oil;
     
  The level of consumer demand for refined products;
     
  Adverse weather conditions and natural disasters;
     
  The price and availability of competitive fuels such as LNG, heating oil and coal;
     
  Political conditions in the Middle East and other natural gas and oil producing regions;
     
  The ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and other oil exporting nations to agree to and maintain oil price and production controls;

 

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  Domestic and foreign governmental regulations;
     
  Special taxes on production;
     
  Access to pipelines and gas processing plants; and
     
  The loss of tax credits and deductions.

 

A substantial or extended decline in natural gas and oil prices could have a material adverse effect on our access to capital and the quantities of natural gas and oil that may be economically produced by us.

 

Reserves estimates depend on many assumptions that may turn out to be inaccurate. Inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and net present value of our reserves. The Company’s current estimates of reserves could change, potentially in material amounts, in the future, in particular due to fluctuations in commodity prices.

 

The process of estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of available technical data and many assumptions, including assumptions relating to current and future economic conditions, production rates, drilling and operating expenses, and commodity prices. Any significant inaccuracy in these interpretations or assumptions could materially affect our estimated quantities and net present value of our reserves.

 

In order to prepare reserves estimates, we must project production rates and the amount and timing of future development expenditures. Our booked proved undeveloped reserves must be developed within five years from the date of initial booking under SEC reserve rules. Changes in the timing of development plans that impact our ability to develop such reserves within the required time frame could result in fluctuations in reserves value between periods as reserves booked in one period may need to be removed or reevaluated in a subsequent period.

 

We must also analyze available geological, geophysical, production and engineering data in preparing reserve estimates. The extent, quality and reliability of this data can vary with the uncertainty of decline curves and the ability to model heterogeneity of the porosity, permeability and pressure relationships in unconventional resources. The process also requires economic assumptions, based on historical data but projected into the future, about matters such as crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

 

The prices used in calculating our estimated proved reserves are, in accordance with SEC requirements, calculated by determining the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding 12 months. Commodity prices recovered moderately in 2017 and 2018 to date, and if such prices should fluctuate significantly, our future calculations of estimated proved reserves may also fluctuate accordingly.

 

Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves will vary and could vary significantly from our estimates. Any significant variance could materially affect the estimated quantities and net present value of our reserves, which in turn could have an adverse effect on the value of our assets. In addition, we may adjust estimates of proved reserves, potentially in material amounts, to reflect production history, results of exploration and development, prevailing crude oil and natural gas prices and other factors, many of which are beyond our control.

 

The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated crude oil and natural gas reserves and, in particular, may be reduced should significant declines in commodity prices occur.

 

You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated crude oil and natural gas reserves. In accordance with SEC rules, we will base the estimated discounted future net revenues from proven reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months. Actual future prices may be materially higher or lower than the SEC pricing used in these calculations. Actual future net revenues from crude oil and natural gas properties will be affected by factors such as:

 

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  the actual prices we receive for sales of crude oil and natural gas;
     
  the actual cost and timing of development and production expenditures;
     
  the timing and amount of actual production; and
     
  changes in governmental regulations or taxation.

 

The timing of both our production and our incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual net present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the crude oil and natural gas industry in general.

 

We may be required to write down the carrying values of our crude oil and natural gas properties if crude oil prices remain at their current levels or decline further.

 

Accounting rules require that we periodically, but no less frequently than annually, review the carrying values of our crude oil and natural gas properties for possible impairment. Based on specific market factors, prices, and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying values of our crude oil and natural gas properties. A write-down results in a non-cash charge to earnings. We may incur additional impairment charges in the future, particularly if crude oil and natural gas prices remain at their currently low levels or decline further, which could have a material adverse effect on our results of operations for the periods in which such charges are taken

 

We are subject to significant operating hazards and uninsured risk in the energy industry.

 

Our proposed operations will be subject to all of the operating hazards and risks normally incident to exploring, drilling for and producing oil and gas, such as encountering unusual or unexpected formations and pressures, blowouts, environmental pollution and personal injury. We currently maintain general liability insurance but we do not expect to obtain insurance against such things as blowouts and pollution risks because of the prohibitive expense. Should we sustain an uninsured loss or liability, or a loss in excess of policy limits, our ability to operate may be materially adversely affected.

 

We are subject to substantial government regulation in the energy industry which could adversely impact us.

 

The production and sale of oil and gas are subject to regulation by state and federal authorities, the spacing of wells and the prevention of waste. There are both federal and state laws regarding environmental controls, which may necessitate significant capital outlays resulting in extended delays, materially affect our earnings potential and/or cause material changes in our business. We cannot predict what legislation, if any, may be passed by Congress or state legislatures in the future, or the effect of such legislation, if any, on us. Such regulations may have a significant effect on our operating results.

 

The Standardized Measure of our estimated reserves and PV-10 included in this report should not be considered as the current market value of the estimated oil and gas reserves attributable to our properties.

 

The Standardized Measure is a reporting convention that provides a common basis for comparing oil and gas companies subject to the rules and regulations of the SEC. Standardized Measure requires the use of specific pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. The non-GAAP financial measure, PV-10, is based on the average of the closing price on the first day of the month for the 12-month period prior to fiscal year end, while actual future prices and costs may be materially higher or lower.

 

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Consequently, these measures may not reflect the prices ordinarily received or that will be received for oil and gas production because of varying market conditions, nor may they reflect the actual costs that will be required to produce or develop the oil and gas properties. Accordingly, estimates included herein of future net cash flow may be materially different from the future net cash flows that are ultimately received. Therefore, the Standardized Measure of our estimated reserves and PV-10 included in this report should not be construed as accurate estimates of the current fair value of our proved reserves. In addition, the 10% discount factor we use when calculating PV-10 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. Actual future net revenues also will be affected by factors such as the amount and timing of actual production, prevailing operating and development costs, supply and demand for oil and gas, increases or decreases in consumption and changes in governmental regulations or taxation.

 

RISK FACTORS RELATED TO OUR STOCK

 

The regulation of penny stocks by SEC and FINRA may discourage the tradability of our securities.

 

We are a “penny stock” company. Our securities are subject to an SEC rule that imposes special sales practice requirements upon broker-dealers who sell such securities to persons other than established customers or accredited investors. For purposes of the rule, the phrase “accredited investors” means, in general terms, institutions with assets in excess of $5,000,000, or individuals having a net worth in excess of $1,000,000, excluding the primary residence, or having an annual income that exceeds $200,000 (or that, when combined with a spouse’s income, exceeds $300,000). For transactions covered by the rule, the broker-dealer must make a special suitability determination for the purchaser and receive the purchaser’s written agreement to the transaction prior to the sale. Effectively, this discourages broker-dealers from executing trades in penny stocks. Consequently, this rule will affect the ability of purchasers of our common stock to sell their securities in any market that might develop therefore because it imposes additional regulatory burdens on penny stock transactions.

 

In addition, the SEC has adopted a number of rules to regulate “penny stocks”. Such rules include Rules 3a51-1, 15g-1, 15g-2, 15g-3, 15g-4, 15g-5, 15g-6, 15g-7, and 15g-9 under the Securities and Exchange Act of 1934, as amended. Because our securities constitute “penny stocks” within the meaning of the rules, the rules would apply to us and to our securities. The rules will further affect the ability of owners of shares to sell our securities in any market that might develop for them because it imposes additional regulatory burdens on penny stock transactions.

 

Shareholders should be aware that, according to the SEC, the market for penny stocks has suffered in recent years from patterns of fraud and abuse. Such patterns include (i) control of the market for the security by one or a few broker-dealers that are often related to the promoter or issuer; (ii) manipulation of prices through prearranged matching of purchases and sales and false and misleading press releases; (iii) “boiler room” practices involving high-pressure sales tactics and unrealistic price projections by inexperienced sales persons; (iv) excessive and undisclosed bid-ask differentials and markups by selling broker-dealers; and (v) the wholesale dumping of the same securities by promoters and broker-dealers after prices have been manipulated.

 

We will pay no foreseeable dividends in the future.

 

We have not paid dividends on our common stock and do not anticipate paying such dividends in the foreseeable future.

 

Our investors may suffer future dilution due to issuances of shares for various considerations in the future.

 

There may be substantial dilution to our shareholders as a result of future decisions of the Board to issue shares, without shareholder approval, for cash, services, or acquisitions.

 

At December 31, 2017, we have warrants issued and outstanding exercisable into 2,683,515 shares of our common stock at exercise prices which range from $0.665 per share to $4.00 per share. The weighted average exercise price is $1.56 per share. They are exercisable in whole or in part. The exercise of the warrants into shares of our common stock likely would have a dilutive effect to the holdings of our existing shareholders.

 

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Rule 144 sales in the future may have a depressive effect on our stock price.

 

Outstanding shares of common stock held by our present officers, directors, and affiliate stockholders are “restricted securities” within the meaning of Rule 144 under the Securities Act of 1933, as amended. As restricted shares, these shares may be resold only pursuant to an effective registration statement or under the requirements of Rule 144 or other applicable exemptions from registration under the Act and as required under applicable state securities laws. Rule 144 provides in essence that a person who has held restricted securities for six months, under certain conditions, may sell every three months, in brokerage transactions, a number of shares that does not exceed the greater of at least 1.0% of a company’s outstanding common stock or the average weekly trading volume during the four calendar weeks prior to the sale. There is no limit on the amount of restricted securities that may be sold by a nonaffiliate after the owner has held the restricted securities for a period of six months. A sale under Rule 144 or under any other exemption from the Act, if available, or pursuant to subsequent registration of shares of common stock of present stockholders, may have a depressive effect upon the price of the common stock in any market that may develop.

 

Our common stock may be volatile, which substantially increases the risk that you may not be able to sell your shares at or above the price that you may pay for the shares.

 

Because of the limited trading market for our common stock and because of the possible price volatility, you may not be able to sell your shares of common stock when you desire to do so. The inability to sell your shares in a rapidly declining market may substantially increase your risk of loss because of such illiquidity and because the price for our securities may suffer greater declines because of our price volatility.

 

Certain factors, some of which are beyond our control, that may cause our share price to fluctuate significantly include, but are not limited to the following:

 

  Variations in our quarterly operating results;
     
  Loss of a key relationship or failure to complete significant transactions;
     
  Additions or departures of key personnel; and
     
  Fluctuations in stock market price and volume.

 

Additionally, in recent years the stock market in general, and the over-the-counter markets in particular, have experienced extreme price and volume fluctuations. In some cases, these fluctuations are unrelated or disproportionate to the operating performance of the underlying company. These market and industry factors may materially and adversely affect our stock price, regardless of our operating performance. In the past, class action litigation often has been brought against companies following periods of volatility in the market price of those companies’ common stock. If we become involved in this type of litigation in the future, it could result in substantial costs and diversion of management attention and resources, which could have a further negative effect on your investment in our stock.

 

Our business is highly speculative and the investment is, therefore, risky.

 

Due to the speculative nature of our business, it is possible that investment in our common stock will result in a total loss to the investor. Investors should be able to financially bear the loss of their entire investment. Investment should, therefore, be limited to that portion of discretionary funds not needed for normal living purposes or for reserves for disability and retirement.

 

Additional risks and uncertainties may materially adversely affect our business, financial condition and/or operating results.

 

Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, and/or operating results. Our financial statements reflect that our current liabilities exceed our current assets and it is possible that the historical value of the assets that we record on our books may not be attained on a sale or other disposition for cash. We require substantial additional operating capital to maintain current operations and to implement even a portion of our identified acquisitions and workovers. Additional capital, if available at all, will likely be on onerous terms that are also dilutive to our shareholders. No assurance can be given that we will obtain any additional capital. As a consequence, an investment in our shares or other securities is extremely speculative and may result in a complete loss of your investment.

 

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ITEM 1B. Unresolved Staff Comments.

 

As a “smaller reporting company” as defined by Item 10 of Regulation S-K, the Company is not required to provide the information required by this Item.

 

ITEM 3. Legal Proceedings.

 

From time to time, we may be involved in routine legal proceedings, as well as demands, claims and threatened litigation that arise in the normal course of our business. The ultimate amount of liability, if any, for any claims of any type (either alone or in the aggregate) may materially and adversely affect our financial condition, results of operations and liquidity. In addition, the ultimate outcome of any litigation is uncertain. Any outcome, whether favorable or unfavorable, could materially and adversely affect us due to legal costs and expenses, diversion of management attention and other factors. We expense legal costs in the period incurred. We cannot assure you that additional contingencies of a legal nature or contingencies having legal aspects will not be asserted against us in the future, and these matters could relate to prior, current or future transactions or events.

 

At December 31, 2017, our indirect subsidiaries were parties to the following contested matters:

 

Utah Wells

 

SCI Welding & Oilfield Service vs. Tiger Energy Operating LLC (Case No. 169000023, 8th District Court, Duchesne County, State of Utah)

 

This case concerns the collection of unpaid debt owed by TEO, relating to the work over of wells in Duchesne County, Utah, in the amount of $53,407. On September 29, 2017, TEO and SCI Welding reached an agreement to settle the matter for $35,000, and the Company paid SCI Welding these settlement funds. A Stipulated Motion to Dismiss (signed by all parties) and an Order by the Court Dismissing Case was filed on October 11, 2017. This is a final settlement of this matter with no further judicial action required.

 

Graco Fishing & Rental Tools, Inc. vs. Tiger Energy Operating LLC (Case No. 160800005 8th Judicial District Court, Duchesne County, State of Utah)

 

Plaintiff in this case sought collection of unpaid debt incurred by TEO for services rendered. Pursuant to this action a default judgment in the amount of $159,965 was obtained by Plaintiff on June 1, 2016, against TEO, for unpaid accounts in connection with its workover of wells in Duchesne County, Utah. Graco filed a writ of execution against the A Rust 2, Dye-Hall 2-21 A1, Wilkins 1-24 A5 and Rust 3-22A-4 wells located in Duchesne County executing on properties not owned by our subsidiary company. A Motion to Set Aside the sheriff’s sale concerning these properties was filed with the court based on the fact that TEO is not the owner of these properties. A hearing for this matter was held on May 1, 2017, in Duchesne County, Utah, at which time a Company representative was present to comply with the court’s order to produce documents. Prior to the hearing, TEO made an initial settlement offer, which was rejected by Graco. A writ of execution was again issued to seize the property of this subsidiary on March 8, 2018.

 

Plaintiff had scheduled certain foreclosure sales of TEO’s interests in various oil and gas wells to take place on May 3, 2018 (the “Sales”). On April 27, 2018, the parties reached a settlement and release agreement whereby TEO agreed to make five (5) payments totaling $163,965 to Graco. The first payment due on May 9, 2018, has already been paid by TEO. The second payment of $32,793 is due on July 9, 2018; third payment of $32,793 is due on September 9, 2018; fourth payment of $32,793 is due on November 9, 2018; and fifth and final payment of $32,793 is due on January 9, 2019. Upon receipt of an executed agreement, Graco agreed to postpone the Sales until May 10, 2018; and upon receipt of the first payment on May 9, 2018, Graco agreed to cancel the Sales altogether. If any of the above payments are not made when due, Graco will have the right to immediately execute the Sales. Graco will maintain and apply liens and notices of its judgment until the total payment has been paid in full by TEO. TEO shall be provided with a 10-day period within which to cure any subsequently occurring default under the settlement agreement. TEO made its second payment of $32,793 on July 19, 2018, within the 10-day cure period provided in the settlement agreement.

 

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Conquest Well Servicing, LLC vs. Foothills Exploration Operating, Inc. (Case No. 179800421 8th Judicial District Court in and for Uintah County, State of Utah)

 

Plaintiff filed this action on September 11, 2017 for collection of unpaid services and materials incurred by FEOI, a wholly-owned indirect subsidiary of the Company, in the amount of $49,689 in connection with a workover of wells in Uintah County, Utah. A Settlement Agreement and Stipulation to Entry of Judgment was agreed to by the parties and filed with the court on October 10, 2017. Judgment in the amount of $54,937 was filed on December 18, 2017. An order requesting company asset inquiry was issued on February 20, 2018. As of July 26, 2018, no further action has been taken.

 

Peak Well Service, LLC v. Tiger Energy Operating, LLC (Case No. 2:16-CV-00957-EJF United States District Court for the District of Utah Court)

 

Peak Well Service, LLC (“Peak”), filed mechanics and materialman’s liens against the Wilkins, Rust 2 Well, Dye Hall 2, Rust 3, and Josie 1 wells operated by TEO for unpaid accounts in connection with work on these wells. A settlement was reached between TEO and Peak pursuant to a confidential settlement agreement. Pursuant to the settlement agreement, lien releases on each of these well liens were filed on February 8, 2017. This settlement is a final resolution of this creditor claim.

 

Bureau of Indian Affairs (BIA) Administrative Appeal – Tiger Energy Partners International, LLC

 

  Notice of Appeal,   Dated May 8, 2013
  Appellant:   Tiger Energy Partners International, LLC
  Appellee:   Superintendent Uintah and Ouray Agency
  Decision   April 12, 2013
  Concerning:   Notice of Expiration of Oil and Gas Leases

 

This Administrative appeal concerns the ownership and validity of Northern Ute Tribal leases acquired by TEPI in a transaction with Mountain Oil and Gas and its affiliated companies. Pursuant to the Global Settlement Agreement negotiated between the Northern Ute Tribe (the “Tribe”) and TEPI, the Company proposed to resolve any issues regarding the ownership of the subject leases and other lands thus acquired. The status of the appeal by TEPI remains unchanged, awaiting decision by the Regional Director of the BIA on the merits of the appeal. The decision of the Regional Director is stayed by the parties having entered into the Global Settlement Agreement. The Tribe and Tiger remain in discussion regarding urging final approval of the Global Settlement Agreement by the Regional Director of the BIA.

 

Labokay Well – Parish of Calcasieu, State of Louisiana

 

In February 2017, FPOI drilled a test well on the Labokay prospect to the total measured depth of 8,795 feet, where hydrocarbons shows were present but not in commercial quantities to warrant completion. Consequently, the Labokay test well was plugged and abandoned in February 2017. Since the well was not commercially viable, FPOI’s working interest in the underlying mineral lease terminated; and we no longer have a right to acquire title to said property. The Labokay-related civil suits described below were filed against FPOI, a wholly-owned indirect subsidiary of the Company arising from unpaid accounts in connection with drilling of the Labokay test well.

 

R.W. Delaney Construction Company vs. Foothills Petroleum Operating, Inc. (Cause No. 2017-CV-0330 – County Court of Adams County, Mississippi)

 

This case was filed on September 18, 2017 and concerns the collection of amounts incurred by FPOI for services performed by plaintiff (R. W. Delaney) in the amount of $72,495 in connection with drilling of the Labokay test well in Calcasieu Parish, Louisiana. A judgment was entered on January 22, 2018, in the County Court of Adams County, Mississippi in the principal amount of $72,495, plus pre-judgement interest in the amount of $12,763, plus attorney’s fees in the amount of $18,124, plus costs in the amount of $196, for a total amount of $103,578, plus post-judgment interest at the rate of 8% per annum. On May 9, 2018, District Court for the City and County of Denver, Colorado, granted plaintiff with an order granting its petition to domesticate this foreign judgment with the Denver District Court, which now has the same effect and is subject to the same procedures, defenses, and proceedings for reopening, vacating, or staying as a judgment from the Denver District Court, and may be enforced or satisfied in like manner.

 

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Performance Drilling Company, LLC vs. Foothills Petroleum Operating, Inc. (Case No. 2017-3916 DIV G 14th Judicial District Court in Parish of Calcasieu, State of Louisiana)

 

This case was filed on September 25, 2017 and concerns the collection of amounts incurred by FPOI for services performed by plaintiff in the amount of $205,251 for unpaid accounts in connection with its drilling of the Labokay test well. On January 16, 2018, a default judgment was entered against FPOI, in the amount of $205,251, together with accrued interest of $29,861 from March 18, 2017, through December 31, 2017, plus additional interest from January 1, 2018, at the rate of one and one-half percent (1.5%) per month until paid (a per diem rate of $104), plus an additional sum for reasonable attorney’s fees in the amount of $2,500, and all costs of the court.

 

Monster Rentals, LLC dba Deepwell Equipment Rentals vs. Foothills Petroleum Operating, Inc. (Case No. 2017-11013 DIV E – 15th Judicial District Court in Parish of Acadia, State of Louisiana)

 

This case was filed on October 24, 2017 and concerns the collection of amounts incurred by FPOI for services performed by plaintiff in the amount of $53,944 in connection with the Labokay test well in Calcasieu Parish, Louisiana.

 

Canal Petroleum Products, Inc. vs. Foothills Petroleum Operating, Inc. (Case No. 2017-6574; DIV. C – 15TH Judicial District Court, Lafayette Parish, Louisiana)

 

This case was filed on November 14, 2017 and concerns the collection of amounts incurred by FPOI for services performed by plaintiff in the amount of $35,981 for unpaid accounts in connection with its drilling of the Labokay test well. On January 25, 2018, a default judgment was entered against FPOI in the amount of $35,981.08, inclusive of interest through September 6, 2017, plus, interest continuing to accrue after September 6, 2017, of one and one-half percent (1.5%) per month (18% per annum) until paid on the unpaid principal amount of $32,956, plus, legal fees of $8,239 together with related court costs.

 

Smith International, Inc. vs. Foothills Petroleum Operating, Inc. (Case No. 2017-004617; DIV. E – 14th Judicial District Court, Calcasieu Parish, Louisiana)

 

This case was filed on November 7, 2017 and concerns the collection of amounts incurred by FPOI for services performed by plaintiff in the amount of $30,244 in connection with its drilling of the Labokay test well. On March 23, 2018, the court issued a preliminary judgement in favor of plaintiff in the amount of $30,244, plus interest in the contractual amount of 18% per annum from the date the payment was originally due until the judgement date, plus legal interest from the judgment date until amounts are paid, plus reasonable attorneys’ fees.

 

M-I, L.L.C. d/b/a MI-SWACO vs. Foothills Petroleum Operating, Inc. (Case No. 2017-004616; DIV. G – 14th Judicial District Court, Calcasieu Parish, Louisiana)

 

This case was filed on November 7, 2017 and concerns the collection of amounts incurred by FPOI for services performed by plaintiff in the amount of $51,275 in connection with the Labokay test well. On March 23, 2018, the court issued a preliminary judgement in favor of plaintiff in the amount of $51,275, plus interest in the contractual amount of 1.5% per month from the date the payment was originally due until the judgement date, plus legal interest from the judgment date until amounts are paid, plus reasonable attorney’s fees expended in the prosecution and collection of debt.

 

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Schlumberger Technology Corporation vs. Foothills Petroleum Operating, Inc. (Case No. 2017-004618; DIV. E – 14th Judicial District Court, Calcasieu Parish, Louisiana)

 

This case was filed on November 7, 2017 and concerns the collection of amounts incurred by FPOI for services performed by plaintiff in the amount of $28,904 for unpaid accounts in connection with its drilling of the Labokay test well in Calcasieu Parish, Louisiana. On March 23, 2018, the court issued a preliminary judgement in favor of plaintiff in the amount of $28,904, plus interest in the contractual amount of 1.5% per month from the date the payment was originally due until the judgement date, plus legal interest from the judgment date until amounts are paid, plus attorneys’ fees.

 

We currently are not a party to any other material legal proceedings. However, legal claims are inherently uncertain, and we cannot assure you that we will not be adversely affected in the future by legal proceedings.

 

ITEM 4. Mine Safety Disclosures.

 

Not applicable.

 

PART II

 

ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities.

 

Trading Information

 

Our common stock is quoted on the OTCQB under the symbol “FTXP.” There has been limited reported trading to date in our common stock. The following table sets forth, for the periods indicated, the range of high and low intraday bid price per share of our common stock. Our shares began trading under this symbol on or about August 9, 2016. These quotations reflect inter-dealer prices without retail mark-up, mark-down, or commission and may not necessarily represent actual transactions.

 

Our common stock is thinly traded, and any reported sale prices may not be a true market-based valuation of our common stock.

 

   High   Low 
Fiscal Year 2016          
           
First Quarter   n/a    n/a 
Second Quarter   n/a    n/a 
Third Quarter (from August 9, 2016)  $1.85   $1.54 
Fourth Quarter  $2.04   $1.75 
           
Fiscal Year 2017                
                 
First Quarter   $ 2.21     $ 1.21  
Second Quarter   $ 1.27     $ 0.80  
Third Quarter   $ 0.90     $ 0.46  
Fourth Quarter   $ 0.50     $ 0.30  

 

On July 20, 2018, the closing sales price reported for our common stock was $0.13 per share and as of that date, we had approximately 58 holders of record of our common stock, and 15,050,627 shares outstanding.

 

Dividend Policy

 

We have not declared or paid any dividends on our common stock. We intend to retain earnings for use in our operations and to finance our business. Any change in our dividend policy is within the discretion of our board of directors and will depend, among other things, on our earnings, debt service and capital requirements, restrictions in financing agreements, if any, business conditions, legal restrictions, and other factors that our board of directors deems relevant.

 

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Purchases of Equity Securities by the Issuer and Affiliated Purchasers

 

None.

 

Securities Authorized for Issuance under Equity Compensation Plans

 

The Company has no formally adopted compensation plans or equity incentive plans approved or submitted for approval by the shareholders.

 

ITEM 6. Selected Financial Data.

 

As a “smaller reporting company” as defined by Item 10 of Regulation S-K, the Company is not required to provide the information required by this Item.

 

ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion should be read in conjunction with our financial statements, including the Notes thereto, appearing elsewhere in this Report. The discussions of results, causes, and trends should not be construed to imply any conclusion that these results or trends will necessarily occur. This discussion includes forward-looking statements that involve risks and uncertainties. As a result of many factors, such as those set forth under “Risk Factors” and elsewhere in this Report, our actual results may differ materially from those anticipated in these forward-looking statements.

 

Going Concern

 

The Company’s consolidated financial statements included in Item 8 of this Annual Report have been prepared assuming that it will continue as a going concern, which contemplates continuity of operations, realization of assets, and liquidation of liabilities in the normal course of business. The Company has incurred recurring losses from inception through December 31, 2017, has a working capital deficit at December 31, 2017, of $13,024,813, and has limited sources of revenue. These factors raise substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements included elsewhere herein do not include any adjustments related to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might be necessary should the Company be unable to continue as a going concern. Our financial statements reflect that our current liabilities exceed our current assets and it is possible that the historical value of the assets that we record on our books may not be attained on a sale or other disposition for cash. We require substantial additional operating capital to maintain current operations and to implement even a portion of our identified acquisitions and workovers. Additional capital, if available at all, will likely be on onerous terms that are also dilutive to our shareholders. No assurance can be given that we will obtain any additional capital. As a consequence, an investment in our shares or other securities is extremely speculative and may result in a complete loss of your investment.

 

To address these matters, the Company is actively meeting with investors for possible equity investments, including business combinations; investigating other possible sources to refinance our existing debt; and in continuing discussions with various individuals and groups that could be willing to provide capital to fund operations and growth of the Company.

 

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Results of Operations

 

Year ended December 31, 2017 compared to year ended December 31, 2016

 

Revenue

 

The following table summarizes our revenues from commodity sales during the years ended December 31, 2017 and 2016.

 

   Years Ended         
   December 31,       Percentage 
   2017   2016   Difference   Change 
                 
Revenues                    
Oil  $82,794   $-   $82,794    100%
Natural gas liquids   15,180    -    15,180    100%
Residue gas   57,187    -    57,187    100%
Total  $155,161   $-   $155,161    100%
                     
Sales volumes                    
Oil (Bbls)   1,710    -    1,710    100%
Natural gas liquids (Bbls)   362    -    362    100%
Residue gas (MCF)   19,119    -    19,119    100%
Total BOE   5,259    -    5,259    100%
Total BOE/D   14.4    -    14.4    100%
                     
Average prices                    
Oil (per Bbl)  $48.42   $-   $48.42    100%
Natural gas liquids (per Bbl)   41.91    -    41.91    100%
Residue gas (per MCF)   2.99         2.99    100%
Price per BOE  $29.51   $-   $29.51    100%

 

Operating Expenses

 

Operating expenses for the years ended December 31, 2017 and 2016, are set forth in the table below.

 

   Years Ended         
   December 31,       Percentage 
   2017   2016   Difference   Change 
                 
Costs and Expenses                    
Lease operating expense (1)  $252,682   $   $252,682    100%
Production and ad valorem taxes (2)   71        71    100%
Depletion, depreciation, amortization, accretion, and impairment expense (3)   1,542,000        1,542,000    100%
General and administrative expense   3,808,067    1,913,265    1,894,802    99%
Total operating expenses  $5,602,820   $1,913,265   $3,689,555    193%

 

(1) Incurred primarily on our Duck Creek properties.
(2) Incurred on December 2017 pre-completion sales from two horizontal wells in Uintah County, Utah.
(3) Includes $1,507,768 impairment of the Labokay project.

 

30
 

 

Operating expenses expressed in BOE for the years ended December 31, 2017 and 2016 are set forth in the table below:

 

   Years Ended         
   December 31,       Percentage 
   2017   2016   Difference   Change 
                 
Costs and Expenses                    
Lease operating expense  $48.05   $   $48.05    100%
Production and ad valorem taxes   0.01        0.01    100%
Depletion, depreciation, amortization, accretion, and impairment expense   293.23        293.23    100%
General and administrative expense   724.15        724.15    100%
Total operating expenses  $1,065.44        1,065.44    100%

 

Interest Expense

 

Interest expense for the years ended December 31, 2017 and 2016, were $930,923 and $27,873, respectively. The increase in interest expense is primarily attributed to new notes payable entered into during the year ended December 31, 2017.

 

Loss on Change in Derivative Value

 

Loss on change in derivative value for the years ended December 31, 2017 and 2016, was $169,423 and $0, respectively. The increase in change in derivative value is primarily attributed to new convertible notes entered into for the year ended December 31, 2017.

 

Other Income

 

Other income for the years ended December 31, 2017 and 2016, was $5,727 and $0, respectively. The increase in other income is primarily attributed to a credit provided by the lessor of our Denver office for an unused allowance for tenant improvements which was contractually allowed to offset monthly rental payments for the year ended December 31, 2017.

 

Gain on Extinguishment of Debt

 

Gain on extinguishment of debt for the years ended December 31, 2017 and 2016, was $48,407 and $0, respectively. The increase in gain on extinguishment of debt is attributed to a settlement of legal proceedings and accrued interest forgiven under a note payable which was paid in full during the year ended December 31, 2017.

 

Net Loss

 

As a result of the foregoing, our net loss for the year ended December 31, 2017, was $6,493,871 ($0.45 per basic and diluted common share). Our net loss for the year ended December 31, 2016, was $1,941,138 ($0.23 per basic and diluted common share).

 

Liquidity and Capital Resources

 

Overview

 

As of December 31, 2017, we had a working capital deficit of $13,024,813. As of December 31, 2016, we had a working capital deficit of $1,083,783. The increase of $11,941,030, in the working capital deficit was attributable as follows:

 

Decrease in current assets of which $800,822 was decreased cash  $802,570 
Increase in accounts payable and accrued liabilities   1,407,102 
Increase in accounts payable and accrued liabilities – related party (1)   518,552 
Increase in current portion of notes payable   7,397,369 
Increase in current portion of notes payable – related party (2)   1,250,000 
Increase in deferred rent   14,487 
Increase in derivative liabilities   458,387 
Increase in other liabilities   92,563 
Sum of changes in working capital  $11,941,030 

 

31
 

 

(1) Accrued payable to management for unpaid compensation of $362,714 and 2017 accrued interest to Berwin Trading Limited (“Berwin”) of $166,438 on related party note payable.
(2) Note payable to Berwin.

 

Our December 31, 2017, reserves report based on the SEC pricing case makes various assumptions regarding the pace of development of our proved undeveloped reserves. In order to develop these reserves on the schedule assumed in the reserve report, the capital expenditure requirement for 2017 would have been $4 million. It is our intent to secure additional capital investment to fund our current operations, development plans for current assets, and acquisitions of producing properties presently under consideration. There are no assurances, however, that we will be successful in this financing effort.

 

There are multiple factors that can affect these estimates including changes in commodity prices, adverse weather conditions and unforeseen events, both inside and outside of our business. In the event that a new financing is not put in place or that other unforeseen circumstances create a shortfall in the capital expenditure budget, other potential sources of funds to support the development effort include:

 

  The establishment of joint ventures with other operators or financing sources;
  Additional debt financing; and
  Additional equity offerings.

 

If, however, cash flow plus the additional sources outlined above are not sufficient to support our portion of the capital expenditure budget outlined in the reserve report, our ability to execute our plan of operations could be negatively impacted and drilling activity could be reduced.

 

Cash and Accounts Receivable

 

As of December 31, 2017, we had cash in bank of $555, compared to $801,377 at December 31, 2016. The $800,822 decrease in cash was due primarily to costs associated with the operation of our business in excess of net revenues earned, consisting mainly of wages and related costs, travel and costs associated with being a publicly traded company.

 

As of December 31, 2017, we had accounts receivable of $32,671, compared to $0 at December 31, 2016. This increase in accounts receivable is due primarily to a receivable for December product sales which the operator has informed us will be applied against unpaid costs of drilling and construction of support facilities and equipment, which were, respectively, $1,479,282 and $22,087 as of December 31, 2017.

 

Liabilities

 

As of December 31, 2017, the outstanding balance of principal and accrued interest on debt was $9,218,947 a net increase of $9,218,947 from the outstanding balance of $0 as of December 31, 2016. This net increase was due to repayment of $1,020,000 of principal and accrued interest on a loan used to satisfy certain obligations under the Purchase and Sale Agreement with Total Belief Limited,(“TBL Acquisition”) for general working capital and to support certain target drilling activities; $6,000,0000 of principal and accrued interest on a note issued in conjunction with the TBL Acquisition; $1,106,168 of principal and interest on a bridge note issued to repay the $1,020,000 of principal and accrued interest on the note referred to above; $250,000 of principal and accrued interest on promissory note to an investor; $123,042 of principal and accrued interest on note issued in exchange for services; $53,219 of principal and accrued interest on a convertible note, $270,080 of principal and accrued interest on a note issued for general corporate and working capital purposes and guaranteed by our Executive Chairman of the Board, Kevin Sylla; and $1,416,438 of principal and accrued interest pursuant to a note issued to Berwin Trading Limited, a related party by virtue of having a 20% beneficial ownership in the Company.

 

32
 

 

Accounts payable and accrued expenses increased by $1,940,141 to $3,661,069 at December 31, 2017, from $1,720,928 at December 31, 2016. Included in accounts payable and accrued expenses are $529,152 and $10,600 as of December 31, 2017 and 2016, respectively, associated with Berwin, a related party. The increase is due primarily to an increase in the rate of interest from 9% to 13.5% on the principal unpaid balance agreed to with Berwin, a related party, as additional consideration for providing the Company with an extension of time to meet its obligations pursuant to the Berwin debenture. These unpaid liabilities are aged from 1 days to 366 days, and we lack the liquidity to pay them until we obtain additional capital.

 

The Company is currently in discussions with multiple parties interested in providing additional capital investment to fund the Company’s current operations, development plans for current assets, and acquisitions of producing properties presently under consideration. The Company also continues to search for producing and/or additional productive properties and seeks to strategically lease additional acreage positions adjoining leases currently owned by the Company. There can be no assurance that the Company’s efforts will be successful in any of these endeavors, or that those efforts will translate in a beneficial manner to the Company. The accompanying statements do not include any adjustments relating to the recoverability and classification of assets and/or liabilities that might be necessary, should the Company be unable to continue as a going concern.

 

Operating Activities

 

During the year ended December 31, 2017 and 2016, we used $3,307,445 and $1,590,726 of cash in operating activities, respectively. Non-cash adjustments included $1,507,768 and $0 related to assets written off, $1,353,581 and $62,960 related to stock compensation expense, $14,487 and $0 in deferred rent, $377,080 and $0 related to amortization of debt discount, $34,232 and $4,114 in depreciation, depletion and amortization, common stock and warrants issued for inducement of the note extension of $141,900 and $0, fair value of down-round feature on warrants of $59,801 and $0, financing expense on notes of $71,345 and $0, note payable issued for services of $120,629 and $0, change in derivative liabilities of $169,423 and $0, gain on settlement of debt and contingent liability $48,407 and $0 and net changes in operating assets and liabilities of $615,413 and $283,338, respectively.

 

Investing Activities

 

During the year ended December 31, 2017, we used $613,377 net cash in investing activities for acquisition of an oil and gas property.

 

During the year ended December 31, 2017, $613,377 net cash was used in investing activities, an increase of $230,480 from net cash used in investing activities during the year ended December 31, 2016. This increase is primarily due to proceeds from restricted cash of $358,129 in 2016.

 

During the year ended December 31, 2016, $382,897 net cash used in investing activities for acquisition of an oil and gas property. This included a $75,000 cash payment made for the acquisition of Total Belief Limited (“TBL”) and $358,129 cash received in the TBL acquisition. We also acquired $91,899 in equipment and $574,127 in oil and gas property.

 

Financing Activities

 

During the year ended December 31, 2017, $3,120,000 net cash provided by financing activities, which includes $1,250,000 in proceeds from the issuance of related party notes payable, $2,300,000 in proceeds from the issuance of unrelated party notes payable, $1,000,000 in repayments to notes payable, $300,000 in proceeds from the issuance of convertible note payable, and $270,000 in proceeds from issuance of common stock.

 

During the year ended December 31, 2016, we received $2,400,000 from financing activities, including $400,000 in proceeds from issuance of a convertible note and $2,000,000 in proceeds from issuance of common stock.

 

Off-Balance Sheet Arrangements

 

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

 

33
 

 

Critical Accounting Policies

 

Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources are based on our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In accordance with GAAP, we are required to make estimates and assumptions that affect the reported amounts included in our financial statements. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our most significant judgments and estimates used in preparation of our financial statements. On an ongoing basis, management reviews and refines those estimates. Management’s judgments are based on information including, but not limited to, historical experience, industry trends, conventional practices, expert opinions, terms of existing agreements and information from outside sources. Judgments are subject to an inherent degree of uncertainty, and therefore actual results could differ from these estimates.

 

Oil and Gas Properties, Full Cost Method. The Company follows the full cost method of accounting for its investments in oil and gas properties. Under the full cost method, all costs associated with the exploration of properties are capitalized into appropriate cost centers within the full cost pool. Internal costs that are capitalized are limited to those costs that can be directly identified with acquisition, exploration, and development activities undertaken and do not include any costs related to production, general corporate overhead, or similar activities. Cost centers are established on a country-by-country basis, and all of the Company’s capitalized costs associated with oil and gas properties are located within a single cost center, which is the United States.

 

Capitalized costs within the cost centers are amortized on the unit-of-production basis using proved oil and gas reserves. The cost of investments in unevaluated properties and major development projects are excluded from capitalized costs to be amortized until it is determined whether or not proved reserves can be assigned to the properties. Until such a determination is made, the properties are assessed annually to ascertain whether impairment has occurred. The costs of drilling exploratory dry holes are included in the amortization base immediately upon determination that the well is dry.

 

For each cost center, capitalized costs are subject to an annual ceiling test, in which the costs shall not exceed the cost center ceiling. The cost center ceiling is equal to: (i) the present value of estimated future net revenues computed by applying current prices of oil and gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions; plus (ii) the cost of properties not being amortized; plus (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and less (iv) income tax effects related to differences between the book and tax basis of the properties. If unamortized costs capitalized within a cost center, less related deferred income taxes, exceed the cost center ceiling, the excess is charged to expense and separately disclosed during the period in which the excess occurs.

 

Revenue Recognition. All revenue is recognized when persuasive evidence of an arrangement exists, the service or sale is complete, the price is fixed or determinable and collectability is reasonably assured. Revenue is derived from the sale of crude oil and natural gas. Revenue from crude oil sales is recognized when the crude oil is delivered to the purchaser and collectability is reasonably assured. We follow the “sales method” of accounting for oil and natural gas revenue, which means we recognize revenue on all crude oil or natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than our share of the expected remaining proved reserves. If collection is uncertain, revenue is recognized when cash is collected. We recognize reimbursements received from third parties for out-of-pocket expenses incurred as service revenues and account for out-of-pocket expenses as direct costs.

 

34
 

 

Stock-Based Compensation. Pursuant to the provisions of FASB ASC 718, Compensation – Stock Compensation, which establishes accounting for equity instruments exchanged for employee service, we utilize the Black-Scholes option pricing model to estimate the fair value of employee stock option awards at the date of grant, which requires the input of highly subjective assumptions, including expected volatility and expected life. Changes in these inputs and assumptions can materially affect the measure of estimated fair value of our share-based compensation. These assumptions are subjective and generally require significant analysis and judgment to develop. When estimating fair value, some of the assumptions will be based on, or determined from, external data and other assumptions may be derived from our historical experience with stock-based payment arrangements. The appropriate weight to place on historical experience is a matter of judgment, based on relevant facts and circumstances. We estimate volatility by considering historical stock volatility. We have opted to use the simplified method for estimating expected term, which is equal to the midpoint between the vesting period and the contractual term.

 

Off-Balance Sheet Arrangements

 

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.

 

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk

 

As a “smaller reporting company” as defined by Item 10 of Regulation S-K, the Company is not required to

 

35
 

 

ITEM 8. Financial Statements and Supplementary Data

 

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

  Page
   
Report of Independent Registered Public Accounting Firm F-1
   
Consolidated Balance Sheets as of December 31, 2017 and 2016 F-2
   
Consolidated Statements of Operations for the years ended December 31, 2017 and 2016 F-3
   
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2017 and 2016 F-4
   
Consolidated Statements of Cash Flows for the years ended December 31, 2017 and 2016 F-5
   
Notes to Consolidated Financial Statements F-6

 

36
 

 

Report of Independent Registered Public Accounting Firm

 

To the Board of Directors and
Stockholders of Foothills Exploration, Inc. and subsidiaries.

 

Opinion on the Financial Statements

 

We have audited the accompanying consolidated balance sheets of Foothills Exploration, Inc. and subsidiaries (The “Company”) as of December 31, 2017 and 2016 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, 2017 and the related notes (collectively referred to as the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the two year period ended December 31, 2017 and 2016, in conformity with accounting principles generally accepted in the United States of America.

 

The Company's Ability to Continue as a Going Concern 

 

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company has an accumulated deficit, recurring losses, and expects continuing future losses, and has stated that substantial doubt exists about the Company’s ability to continue as a going concern. Management's evaluation of the events and conditions and management’s plans regarding these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty. 

 

Basis for Opinion

 

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

 

Our audits 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. We believe that our audits provides a reasonable basis for our opinion.

 

/S/ RBSM LLP  
   
We have served as the Company’s auditor since 2015.  
Henderson, Nevada  
August 06, 2018  

 

F-1
 

 

FOOTHILLS EXPLORATION, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(AUDITED)

 

   December 31, 
   2017   2016 
         
Assets          
Current assets:          
Cash and cash equivalents  $555   $801,377 
Accounts receivable - trade   747    - 
Accounts receivable – oil and gas   31,924      
Prepaid expenses   14,721    49,140 
Total current assets   47,947    850,517 
           
Oil and gas properties, full cost accounting          
Properties not subject to amortization   2,457,218    1,181,421 
Properties subject to amortization, net   10,674,918    10,252,568 
Support facilities and equipment, net   121,502    99,446 
Net oil and gas properties   13,253,638    11,533,435 
           
Property and equipment, net   13,821    18,339 
Other assets:          
Restricted cash   240,000    240,000 
Surety and performance bonds   295,000    295,000 
Total assets  $13,850,406   $12,937,291 
           
Liabilities and Equity          
Current liabilities:          
Accounts payable - trade and accrued liabilities  $3,053,050   $1,710,328 
Accounts payable – related party   362,714    10,600 
Deferred rent   14,487    - 
Accrued interest   64,380    - 
Accrued interest - related party   166,438    - 
Notes payable   7,304,097    - 
Notes payable - related party   1,250,000    - 
Convertible note payable, net   93,272    - 
Derivative liabilities   458,387    - 
Other liabilities   305,935    213,372 
Total current liabilities   13,072,760    1,934,300 
Long-term liabilities:          
Long-term debt, net   -    6,000,000 
Asset retirement obligation   303,327    - 
Total liabilities   13,376,087    7,934,300 
           
Commitments and Contingencies   -    - 
           
Stockholders’ equity:          
Preferred stock, $0.0001 par value; 25,000,000 shares authorized; no shares outstanding   -    - 
Common stock, $0.0001 par value; 100,000,000 shares authorized; 14,900,627 and 13,779,612 shares issued and outstanding, respectively   1,490    1,378 
Stock payable   93,900    51,397 
Additional paid in capital   8,847,394    6,924,810 
Accumulated deficit   (8,468,465)   (1,974,594)
Total stockholders’ equity   474,319    5,002,991 
Total liabilities and stockholders’ equity  $13,850,406   $12,937,291 

 

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

 

F-2
 

 

FOOTHILLS EXPLORATION, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(AUDITED)

 

   Year ended December 31, 
   2017   2016 
Revenues  $155,161   $- 
           
Operating expenses          
Lease operating expense   252,753    - 
Selling, general and administrative expense   3,808,067    1,913,265 
Depletion, depreciation, amortization, and accretion expense   34,232    - 
Impairment of oil and gas properties   1,507,768    - 
Total operating expenses   5,602,820    1,913,265 
           
Loss from operations   (5,447,659)   (1,913,265)
           
Other income (expenses):          
Interest expense   (930,923)   (27,873)
Change in derivative value   (169,423)   - 
Gain on extinguishment of debt   48,407    - 
Other income   5,727    - 
Total other income (expenses)   (1,046,212)   (27,873)
           
Net Loss  $(6,493,871)  $(1,941,138)
           
Net loss per share – basic and diluted   (0.45)   (0.23)
           
Weighted average shares outstanding – basic and diluted   14,418,719    8,422,180 

 

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

 

F-3
 

 

FOOTHILLS EXPLORATION, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(AUDITED)

 

   Preferred stock   Common stock   Additional Paid in   Stock   Accumulated   Total Stockholders’ 
   Shares   Amount   Shares   Amount   Capital   Payable   Deficit   Equity 
Balance as of December 31, 2015   -   $-    4,500,000   $450   $71,980   $-   $(33,456)  $38,974 
KYLK Shares   -    -    58,809,000    5,881    (5,881)   -    -    - 
Common stock returned to treasury for cancellation   -    -    (56,449,000)   (5,645)   5,645    -    -    - 
Common stock issued for notes   -    -    1,503,759    150    999,850    -    -    1,000,000 
Shares issued for services   -    -    325,000    33    10,279    -    -    10,312 
Common stock issued for cash   -    -    3,007,519    301    1,999,699    -    -    2,000,000 
Common stock issued for acquisition   -    -    2,083,334    208    3,812,293    -         3,812,501 
Warrants issued for services   -    -    -    -    2,144    -    -    2,144 
Debt forgiveness   -    -    -    -    28,801    -    -    28,801 
Stock payable (RSUs)   -    -    -    -    -    51,397    -    51,397 
Net income   -    -    -    -    -    -    (1,941,138)   (1,941,138)
Balance as of December 31, 2016   -    -    13,779,612    1,378    6,924,810    51,397    (1,974,594)   5,002,991 
Common stock issued for cash   -    -    406,015    41    269,959    -    -    270,000 
Shares issued for services   -    -    275,000    27    453,473    -    -    453,500 
Shares issued for services (CEO, Dir)   -    -    280,000    28    135,310    (51,397)   -    83,941 
Shares issued for inducement of note payable   -    -    160,000    16    66,234    93,900    -    160,150 
Options issued for services   -    -    -    -    816,140    -    -    816,140 
Fair value of warrants issued with note payable   -    -    -    -    178,932    -    -    178,932 
Imputed interest   -    -    -    -    2,536    -    -    2,536 
Net income   -    -    -    -    -    -    (6,493,871)   (6,493,871)
Balance as of December 31, 2017   -   $-    14,900,627   $1,490   $8,847,394   $93,900   $(8,468,465)  $474,319 

 

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

 

F-4
 

 

FOOTHILLS EXPLORATION, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

    Year ended December 31,  
    2017     2016  
CASH FLOWS FROM OPERATING ACTIVITIES                
Net loss   $ (6,493,871 )   $ (1,941,138 )
Adjustments to reconcile net loss to net cash used in operating activities                
Depreciation, depletion, amortization and accretion     34,232       4,114  
Impairment of assets     1,507,768       -  
Amortization of debt discount     377,080       -  
Financing expenses on notes     71,345       -  
Fair value of down-round feature on warrants     59,801       -  
Note payable issued for services    

120,629

      -  
Change in derivative value     169,423       -  
Common stock and warrants issued for inducement of the note extension     141,900       -  
Common stock and stock payable issued for services and fair value of options     1,353,581       62,960  
Deferred rent     14,487       -  
Gain on extinguishment of debt     (48,407 )     -  
Changes in assets and liabilities, excluding effects of acquisitions:                
Accounts receivable     (32,671 )     -  
Prepaid expenses     34,419       122,586  
Accounts payable and accrued liabilities     (1,246,683 )     160,752  
Accounts payable and accrued liabilities- related party     518,552       -  
Other liabilities     110,970       -  
Net cash used in operating activities     (3,307,445 )     (1,590,726 )
                 
CASH FLOWS FROM INVESTING ACTIVITIES                
Proceeds from restricted cash     -       358,129  
Cash paid for acquisition of Total Belief Limited     -       (75,000 )
Cash paid for fixed assets     -       (91,899 )
Cash paid for acquisition of oil and gas property     (613,377 )     (574,127 )
Net cash used investing activities     (613,377 )     (382,897 )
                 
CASH FLOWS FROM FINANCING ACTIVITIES                
Proceeds from notes payable - related party     1,250,000       -  
Repayments of notes payable     (1,000,000 )     -  
Proceeds from notes payable     2,300,000       400,000  
Proceeds from convertible note payable     300,000       -  
Proceeds from sales of common stock     270,000       2,000,000  
Net cash provided by financing activities     3,120,000       2,400,000  
                 
Net increase in cash and cash equivalents     (800,822 )     426,377  
                 
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD     801,377       375,000  
                 
CASH AND CASH EQUIVALENTS, END OF PERIOD   $ 555     $ 801,377  
                 
Supplemental Disclosure of Cash Flow Information:                
Cash paid for interest   $ 20,000     $ -  
Cash paid for income taxes   $ -     $ -  
                 
Supplemental Disclosure of Noncash Investing and Financing Activities                
Prepaid expenses paid in shares   $ -     $ 893  
Asset retirement obligation   $ 291,659     $ -  
Debt discount   $ 793,144     $ -  
Stock issued for conversion of notes payable   $ -     $ 1,000,000  
Accrued interest forgiven by related party   $ -     $ 28,801  
Accounts payable settled with restricted cash   $ -     $ 25,000  
Assets acquired in acquisition from Total Belief Limited   $ -     $ 10,817,668  
Fixed assets transferred to oil and gas properties   $

(335,024

)   $ -  
Related party payable assumed in acquisition   $ -     $ (10,600 )
Liabilities assumed in acquisition   $ -     $ (613,297 )
Notes payable issued for acquisition   $ -     $ (6,000,000 )
Shares issued for acquisition   $ -     $ (3,812,500 )
Note payable issued for services   $ 120,629     $ -  
Unpaid liabilities in acquisition of oil and gas property   $ 2,683,785     $ 534,764  
Fair value of warrants issued with note payable   $ 119,131     $ -  
Fair value of shares issued for inducement of note payable   $ 160,150     $ -  

 

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

 

F-5
 

 

FOOTHILLS EXPLORATION, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 1 – Organization, going concern, and significant accounting policies

 

Business

 

Foothills Exploration, Inc., (“Company”, “Foothills Exploration”, or “Foothills”) was incorporated in the state of Delaware on May 13, 2010, under the name “Key Link Assets Corp.” for the purpose of acquiring a portfolio of heavily discounted real estate properties in the Chicago metropolitan area. The Company changed its focus and planned to acquire small and medium sized grocery stores in non-urban locales that are not directly served by large national supermarket chains.

 

On May 2, 2016, Foothills Petroleum Inc., a Nevada corporation (“FPI”), acquired over 14.1 million pre-split (56.4 million post-split) shares of the Company’s common stock constituting approximately 96% of our then issued and outstanding shares (“FPI Acquired Shares”). As of May 16, 2016, we effected a 4:1 forward split of our shares of common stock.

 

On May 27, 2016, the Company entered into a Share Exchange Agreement with shareholders of FPI. See Note 2 – Share Exchange Agreement.

 

Prior to the Share Exchange, the Company had minimal assets and recognized no revenues from operations and was accordingly classified as a shell company. In light of closing the Share Exchange transaction with the shareholders of FPI, the Company became actively engaged in oil and gas operations and is no longer a shell company.

 

The consolidated balance sheets include the accounts of the Company, and its wholly-owned direct and indirect subsidiaries, Foothills Exploration, Inc. (“FTXP”), Foothills Petroleum, Inc. (“FPI”), Foothills Exploration, LLC (“FEL”), Foothills Petroleum Operating, Inc. (“FPOI”), Foothills Exploration Operating, Inc. (“FEOI”), Tiger Energy Partners International, LLC (“TEPI”), Tiger Energy Operating, LLC (“TEO”), and Tiger Energy Mineral Leasing, LLC (“TEML”).

 

The Company’s oil and gas operations are conducted by its wholly owned indirect subsidiaries. FEL is a qualified oil and gas operator in the states of Wyoming and Colorado, and TEO is a qualified oil and gas operator in the state of Utah.

 

The Company’s operating entities have historically employed, and will continue in the future to employ, on an as-needed basis, the services of drilling contractors, other drilling related vendors, field service companies and professional petroleum engineers, geologists, and landmen as required in connection with future drilling and production operations.

 

Going Concern

 

The accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America, which contemplate continuation of the Company as a going concern. The Company has incurred recurring losses from inception through December 31, 2017, has a working capital deficit at December 31, 2017, of $13,024,813, and has limited sources of revenue. These conditions have raised substantial doubt as to the Company’s ability to continue as a going concern for one year from the issuance of the financial statements. These financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.

 

To address these matters, the Company is actively meeting with investors for possible equity investments, including business combinations; investigating other possible sources to refinance our existing debt; and in continuing discussions with various individuals and groups that could be willing to provide capital to fund operations and growth of the Company.

 

F-6
 

 

Significant Accounting Policies

 

Principles of Consolidation

 

The financial statements include the accounts of Foothills Exploration, Inc., and all of its direct and indirect wholly-owned subsidiaries including Foothill Petroleum, Inc., Foothills Petroleum Operating, Inc., Foothills Exploration Operating, Inc., Foothills Exploration LLC, Tiger Energy Partners International, LLC, Tiger Energy Operating, LLC and Tiger Energy Mineral Leasing, LLC. Intercompany balances and transactions have been eliminated in consolidation.

 

Basis of Presentation and Functional Currency

 

These consolidated financial statements and related notes are presented in accordance with accounting principles generally accepted in the United States of America and are expressed in United States dollars (USD).

 

Use of Estimates

 

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date(s) of the financial statements and the reported amounts of revenues and expenses during the reporting period(s). Management bases its estimates on historical experience and on various assumptions that are believed to be reasonable in relation to the financial statements taken as a whole under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Management regularly evaluates the key factors and assumptions used to develop the estimates utilizing currently available information, changes in facts and circumstances, historical experience and reasonable assumptions. After such evaluations, if deemed appropriate, those estimates are adjusted accordingly. Actual results could differ from those estimates. Significant estimates include those related to assumptions used in impairment testing of long term assets, accruals for potential liabilities and valuing equity instruments issued for services. Actual results could differ from those estimates.

 

Reclassifications

 

Certain reclassifications have been made to amounts in prior year to conform to the current year presentation. All reclassifications have been applied consistently to the periods presented and had no effects on previously reported results of operations.

 

Cash and Cash Equivalents

 

Cash and cash equivalents include all highly liquid debt instruments with maturity of three months or less.

 

Restricted Cash

 

Cash and cash equivalents that are restricted as to withdrawal or use under the terms of certain contractual agreements are recorded in restricted cash in the non-current assets section of our consolidated balance sheet. At each of the years ended December 31, 2017 and 2016, the Company had restricted cash of $240,000. This amount is being held in escrow for the benefit of the State of Utah for certain properties located in Utah, covered under a certain Modification to Stipulated Order between the Utah Division of Oil, Gas and Mining and TEPI dated August 1, 2014 (Case No. SI/TA-102). These funds held in escrow, will be released to the Company once the Company finishes its reclamation of the various wells in question.

 

Accounts receivable and allowance for doubtful accounts

 

Accounts receivable are stated at the historical carrying amount net of an allowance for uncollectible accounts. The carrying amount of the Company’s accounts receivable approximates fair value because of the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables.

 

F-7
 

 

Trade accounts receivable comprise receivables from joint interest owners which are recorded when the Company incurs expenses on behalf of the non-operator interest owners of the properties the Company operates.

 

The Company’s oil and gas revenues receivable comprise receivables from purchasers of the Company’s production of oil and gas and other hydrocarbons and from operators of properties in which the Company has a non-operated interest, as well as from joint interest owners of properties the Company operates. During the year ended December 31, 2017, the company accrued $31,924 of net revenue receivable from EOG Resources, the operator of two wells in which the Company has a working interest, which the Company has been informed that EOG will apply to unpaid invoices of the Company’s share of costs to drill two wells until EOG has recovered those costs. During the year ended December 31, 2017, those costs were $1,501,377. See Note 4 – Property and Equipment.

 

The Company’s reported balance of accounts receivable, net of allowance for doubtful accounts, represents management’s estimate of the amount that ultimately will be realized in cash or used in the future to offset an operator’s joint interest billings.

 

The Company reviews the adequacy of the allowance for doubtful accounts on an ongoing basis, using historical payment trends, the age of the receivables and knowledge of the individual customers or joint interest owners. When the analysis indicates, management increases or decreases the allowance accordingly. However, if the financial condition of our customers were to deteriorate, additional allowances might be required.

 

Oil and Gas Properties

 

The Company follows the full cost method of accounting for its investments in oil and gas properties. Under the full cost method, all costs associated with the exploration of properties are capitalized into appropriate cost centers within the full cost pool. Internal costs that are capitalized are limited to those costs that can be directly identified with acquisition, exploration, and development activities undertaken and do not include any costs related to production, general corporate overhead, or similar activities. Cost centers are established on a country-by-country basis.

 

Capitalized costs within the cost centers are amortized on the unit-of-production basis using proved oil and gas reserves. The cost of investments in unevaluated properties and major development projects are excluded from capitalized costs to be amortized until it is determined whether or not proved reserves can be assigned to the properties. Until such a determination is made, the properties are assessed annually to ascertain whether impairment has occurred. The costs of drilling exploratory dry holes are included in the amortization base immediately upon determination that the well is dry.

 

For each cost center, capitalized costs are subject to an annual ceiling test, in which the costs shall not exceed the cost center ceiling. The cost center ceiling is equal to: (i) the present value of estimated future net revenues computed by applying current prices of oil and gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions; plus (ii) the cost of properties not being amortized; plus (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and less (iv) income tax effects related to differences between the book and tax basis of the properties. If unamortized costs capitalized within a cost center, less related deferred income taxes, exceed the cost center ceiling, the excess is charged to expense and separately disclosed during the period in which the excess occurs.

 

Support Facilities and Equipment

 

Our support facilities and equipment are generally located in proximity to certain of our principal fields. Depreciation of these support facilities is calculated on a units-of-production basis.

 

Maintenance and repair costs that do not extend the useful lives of property and equipment are charged to expense as incurred.

 

F-8
 

 

Proved Reserves

 

Estimates of the Company’s proved reserves included in this report are prepared in accordance with US GAAP and guidelines from the United States Securities and Exchange Commission (“SEC”). The Company’s engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depreciation, depletion, and amortization expense and impairment. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserves estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions, and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs, and expected performance from a given reservoir also will result in revisions to the amount of the Company’s estimated proved reserves. The Company engages independent reserve engineers to estimate its proved reserves.

 

Fixed Assets

 

The Company capitalizes expenditures related to property and equipment not directly associated with our production of oil and gas, subject to a minimum rule, that have a useful life greater than one year for: (1) assets purchased; (2) existing assets that are replaced, improved or the useful lives have been extended; or (3) all land, regardless of cost, acquisitions of new assets, additions, replacements and improvements (other than land) costing less than the minimum rule in addition to maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.

 

Depreciation is calculated using the straight-line method over the estimated useful lives of the assets.

 

Office equipment – 3 years

Vehicle(s) – 5 years

Land – not depreciated

 

Asset Retirement Obligations

 

The Company follows the provisions of the Accounting Standards Codification ASC 410 - Asset Retirement and Environmental Obligations. The fair value of an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. The Company’s asset retirement obligations relate to the abandonment of oil and gas producing facilities and facilities that support the production of oil and gas. The amounts recognized are based upon numerous estimates and assumptions, including future retirement costs, future inflation rates and the credit-adjusted risk-free interest rate. After recording these amounts, the ARO will be accreted to its future estimated value using the same assumed cost of funds, and the capitalized costs are depreciated on a unit-of-production basis. Both the accretion and the depreciation will be included in depreciation, depletion and amortization expense on our consolidated statements of operations.

 

Fair Value of Financial Instruments

 

For certain of the Company’s financial instruments, including cash and equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities and short-term debt, the carrying amounts approximate their fair values due to their short maturities. ASC Topic 820, “Fair Value Measurements and Disclosures,” requires disclosure of the fair value of financial instruments held by the Company. ASC Topic 825, “Financial Instruments,” defines fair value, and establishes a three-level valuation hierarchy for disclosures of fair value measurement that enhances disclosure requirements for fair value measures. The carrying amounts reported in the consolidated balance sheets for receivables and current liabilities each qualify as financial instruments and are a reasonable estimate of their fair values because of the short period of time between the origination of such instruments and their expected realization and their current market rate of interest. The three levels of valuation hierarchy are defined as follows:

 

F-9
 

 

  Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis
     
  Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instruments, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.
     
  Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). Level 3 instruments include derivative warrant instruments. The Company does not have sufficient corroborating evidence to support classifying these assets and liabilities as Level 1 or Level 2.

 

The Company analyzes all financial instruments with features of both liabilities and equity under ASC 480, “Distinguishing Liabilities from Equity,” and ASC 815. The carrying amounts of the Company’s financial assets and liabilities, including cash, prepaid expenses, accounts payable, accrued expenses, and other current liabilities, approximate their fair values because of the short maturity of these instruments. The fair value of notes payable and convertible notes approximates their fair values since the current interest rates and terms on these obligations are the same as prevailing market rates.

 

Certain of the Company’s debt and equity instruments include embedded derivatives that require bifurcation from the host contract under the provisions of ASC 815-40, Derivatives and Hedging. The estimated fair value of the derivative warrant instruments was calculated using a Black Scholes valuation model.

 

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017 and 2016:

 

       Fair Value Measurement at 
   Carrying Value   December 31, 2017 
       Level 1   Level 2   Level 3 
                 
Derivative assets, debt and equity instruments  $   $   $   $ 
Derivative liabilities, debt and equity instruments   458,387            458,387 

 

         Fair Value Measurement at 
    Carrying Value    December 31, 2016 
         Level 1    Level 2    Level 3 
                     
Derivative assets, debt and equity instruments  $   $   $   $ 
Derivative liabilities, debt and equity instruments                

 

The Company did not identify any other assets and liabilities that are required to be presented on the consolidated balance sheet at fair value.

 

Revenue Recognition

 

The Company recognizes revenue in accordance with the requirements of ASC 605-10-599, which directs that it should recognize revenue when (1) persuasive evidence of an arrangement exists (contracts); (2) delivery has occurred; (3) the seller’s price is fixed or determinable (per the customer’s contract); and (4) collectability is reasonably assured (based upon our credit policy). All of our revenue is attributable to sales of oil, gas, and other hydrocarbons which are sold daily, with sales aggregated on a monthly basis. In the case of revenue received for a non-operated working interest, we are paid by the operator, which is a joint interest partner and not the purchaser of the product. In the case of revenue received for an operated working interest, we are paid by the marketer to whom we sell the commodities directly pursuant to contractual arrangements.

 

F-10
 

 

Debt Issuance Costs, Debt Discount and Detachable Debt-Related Warrants

 

Costs incurred to issue debt are deferred and recorded as a reduction to the debt balance in our consolidated balance sheets. We amortize debt issuance costs over the expected term of the related debt using the effective interest method. Debt discounts relate to the relative fair value of warrants issued in conjunction with the debt and are also recorded as a reduction to the debt balance and accreted over the expected term of the debt to interest expense using the effective interest method.

 

Net Earnings (Loss) Per Common Share

 

The Company computes earnings per share under ASC 260-10, “Earnings Per Share.” The Company’s earnings (loss) per share are computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings (loss) per share reflects the potential dilution of securities, if any, that could share in the earnings (loss) of the Company and are calculated by dividing net income by the diluted weighted average number of common shares. The diluted weighted average number of common shares is computed using the treasury stock method for common stock that may be issued for outstanding stock options, warrants, and convertible debt.

 

   December 31, 
   2017   2016 
Numerator:        
Net income (loss) available to stockholders  $(6,493,871)  $(1,941,138)
Basic net income allocable to participating securities (1)        
Income (loss) available to Foothills Exploration, Inc.’s stockholders  $(6,493,871)  $(1,941,138)
           
Denominator:          
Weighted average number of common shares outstanding-Basic   14,418,719    8,422,180 
Effect of dilutive securities:          
Options and warrants (2)        
Stock payable (3)   205,000    200,000 
Weighted average number of common shares outstanding-Diluted   14,623,719    8,622,180 
           
Net income (loss) per share:          
Basic  $(0.45)  $(0.23)
Diluted  $(0.44)  $(0.23)

 

  (1) Restricted share awards that contain non-forfeitable rights to dividends are participating securities and, therefore, are included in computing earnings using the two-class method. Participating securities, however, do not participate in undistributed net losses.
     
  (2) For the year ended December 31, 2017, “out of the money” stock options representing 2,050,000 shares and warrants representing 2,683,515 shares were antidilutive and, therefore, excluded from the diluted share calculation. For the year ended December 31, 2016, “out of the money” stock options representing 450,000 shares and warrants representing 1,025,000 shares were antidilutive and, therefore, excluded from the diluted share calculation.
     
  (3) For the year ended December 31, 2017, stock payable representing 205,000 shares were anti-dilutive. For the year ended December 31, 2016, stock payable representing 200,000 shares were anti-dilutive.

 

Income Taxes

 

The Company accounts for income taxes using the asset and liability method whereby deferred tax assets are recognized for deductible temporary differences, and deferred tax liabilities are recognized for taxable temporary differences. Temporary differences are the differences between the reported amounts of assets and liabilities and their tax bases. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

 

F-11
 

 

Stock-Based Compensation

 

All share-based payments, including grants of stock to employees, directors and consultants, are recognized in the consolidated financial statements based upon their estimated fair values.

 

The Company accounts for stock, stock options, and stock warrants issued for services and compensation by employees under the fair value method. For non-employees, the fair market value of the Company’s stock is measured on the date of stock issuance or the date an option/warrant is granted as appropriate under ASC 718 “Compensation – Stock Compensation”. The Company determined the fair market value of the warrants/options issued under the Black-Scholes Pricing Model. Under the provisions ASC 718, share-based compensation cost is measured at the grant date, based on the fair value of the award, and is recognized as an expense over the employee’s requisite service period (generally the vesting period of the equity grant).

 

The Company’s accounting policy for equity instruments issued to consultants and vendors in exchange for goods and services follows ASC Topic 505. As such, the value of the applicable stock-based compensation is periodically re-measured and income or expense is recognized during their vesting terms. The measurement date for the fair value of the equity instruments issued is determined at the earlier of (i) the date at which a commitment for performance by the consultant or vendor is reached or (ii) the date at which the consultant or vendor’s performance is complete. In the case of equity instruments issued to consultants, the fair value of the equity instrument is primarily recognized over the term of the consulting agreement. In accordance with FASB guidance, an asset acquired in exchange for the issuance of fully vested, non-forfeitable equity instruments should not be presented or classified as an offset to equity on the grantor’s balance sheet once the equity instrument is granted for accounting purposes.

 

Recent Accounting Pronouncements

 

In November 2015, the FASB issued Accounting Standards Update No. 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”). ASU 2015-17 requires companies to classify all deferred tax assets and liabilities as noncurrent on the balance sheet instead of separating deferred taxes into current and noncurrent amounts. The guidance is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted. The guidance may be adopted on either a prospective or retrospective basis. The adoption of ASU 2015-17 did not have a material impact on its consolidated financial statements.

 

In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”). ASU 2016-02 addresses the financial reporting of leasing transactions. Under current guidance for lessees, leases are only included on the balance sheet if certain criteria classifying the agreement as a capital lease are met. This update will require the recognition of a right-of-use asset and a corresponding lease liability, discounted to the present value, for all leases that extend beyond 12 months. For operating leases, the asset and liability will be expensed over the lease term on a straight-line basis, with all cash flows included in the operating section of the statement of cash flows. For finance leases, interest on the lease liability will be recognized separately from the amortization of the right-of-use asset in the statement of operations and the repayment of the principal portion of the lease liability will be classified as a financing activity while the interest component will be included in the operating section of the statement of cash flows. This guidance is effective for annual and interim reporting periods beginning after December 15, 2018. Early adoption is permitted. The Company has not yet completed the analysis of how adopting this guidance will affect its consolidated financial statements.

 

In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Some of the areas of simplification apply only to nonpublic entities. For public business entities, the amendments in ASU 2016-09 are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The adoption of ASU 2016-09 did not have a material impact on its consolidated financial statements.

 

F-12
 

 

In January 2017, the FASB issued Accounting Standards Update No. 2017-01, Clarifying the Definition of a Business (“ASU 2017-01”). The standard clarifies the definition of a business by adding guidance to assist entities in evaluating whether transactions should be accounted for as acquisitions of assets or businesses. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Under ASU 2017-01, to be considered a business, the assets in the transaction need to include an input and a substantive process that together significantly contribute to the ability to create outputs. Prior to the adoption of the new guidance, an acquisition or disposition would be considered a business if there were inputs, as well as processes that when applied to those inputs had the ability to create outputs. Early adoption is permitted for certain transactions. Adoption of ASU 2017-01 may have a material impact on the Company’s consolidated financial statements if it enters into future business combinations.

 

In January 2017, the FASB issued Accounting Standards Update No. 2017-04, Simplifying the Test for Goodwill Impairment (“ASU 2017-04”). ASU 2017-04 simplifies the accounting for goodwill impairment by removing Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation and may require the services of valuation experts. ASU 2017-04 is effective for annual or interim goodwill impairment tests in fiscal years beginning after December 15, 2019 and should be applied on a prospective basis. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. The Company does not anticipate the adoption of ASU 2017-04 will have a material impact on its consolidated financial statements.

 

In July 2017, the FASB issued Accounting Standards Update No. 2017-11, Accounting for Certain Financial Instruments with Down Round Features (“ASU 2017-11”). When determining whether certain financial instruments should be classified as liabilities or equity instruments, a down round feature no longer precludes equity classification when assessing whether the instrument is indexed to an entity’s own stock. ASU 2017-11 is effective for annual or interim periods within those fiscal years beginning after December 15, 2018 and should be applied on a retrospective basis. Early adoption is permitted for all entities, including adoption in an interim period. The Company adopted ASU 2017-11 on its consolidated financial statements.

 

Other recent accounting pronouncements issued by the FASB, including its Emerging Issues Task Force, the American Institute of Certified Public Accountants, and the Securities and Exchange Commission did not or are not believed by management to have a material impact on the Company’s present or future consolidated financial statements.

 

Note 2 – Share Exchange Agreement

 

During the year ended December 31, 2016, (the “Company”):

 

(1) acquired over 14.1 million pre-split (56.4 million post-split) shares of Key Link’s common stock from five persons constituting approximately 96% of our issued and outstanding shares (the “FPI Acquired Shares”). In conjunction with this purchase we incurred a charge of $316,035 for the purchase of these shares.
   
(2) effected a 4:1 forward split of our shares of common stock.
   
(3) entered into a Share Exchange Agreement (“Share Exchange Agreement”) with the shareholders of FPI, whereby the Company acquired all of the outstanding shares of FPI for an aggregate of 6,003,759 shares of common stock of which 4,500,000 shares of common stock were issued to Wilshire Energy Partners, LLC, (“Wilshire”) and 1,503,759 of shares of common stock were issuable to Alternus Capital Holdings Ltd., a British Virgin Islands company (“Alternus”) (the “Share Exchange”) for automatic conversion of debt. As a result of the Share Exchange, FPI became the Company’s wholly owned subsidiary and the FPI Acquired Shares were subsequently returned to treasury, deemed canceled and no longer outstanding.
   
(4) exchanged warrants to purchase 700,000 shares of FPI’s common stock that were issued to Wilshire for a like amount of warrants to purchase shares of Key Link’s common stock (the “Wilshire Warrants”). The Wilshire Warrants which:

 

  have a term of five years;
     
  are exercisable at $1.25 per share as to 100,000 shares;

 

F-13
 

 

  are exercisable at $2.00 per share as to 200,000 shares;
     
  are exercisable at $3.00 per share as to 400,000 shares;
     
  do not have a cashless exercise feature; and
     
  are not exercisable for one year from the date of issuance.

 

Following the closing of the Share Exchange transaction the Company had approximately 8,363,759 shares of common stock outstanding (excluding the FPI Acquired Shares, which are deemed canceled following the Share Exchange), of which Wilshire and Alternus own in the aggregate 6,003,759 shares, or approximately 52% of the outstanding common stock.

 

Note 3 – Acquisition

 

On December 30, 2016, the Company entered into a Purchase and Sale Agreement (“PSA”) with Total Belief Limited (“TBL”), a British Virgin Islands limited liability company. Under the PSA, the Company purchased membership interests in the companies listed below, constituting all of the ownership interest and claims that TBL has or may have in these companies, as defined below.

 

Based on the closing of its agreement with TBL, the Company acquired:

 

Clear Elite Holdings Limited (“CEH”), a British Virgin Islands limited liability company, which is the owner of 100% of the membership interests of Golden Giants Limited, a British Virgin Islands limited liability company (“GGL”), which owns:

 

  100% of the membership interests of NTE-Utah, LLC, a Delaware limited liability company (“NTE-Utah”), which in turn owns 100% of the membership interests of Tiger Energy Operating, LLC (“TEO”), a Nevada limited liability company, which in turn owns 100% of the membership interests of Tiger Energy Mineral Leasing, LLC (“TEML”), a Nevada limited liability company, with owned oil and gas leases, wells, related oil and gas bonds, and oil and gas lease rights and options, found in approximately 280 acres in Uintah County, Utah, and cash assets held by the entities; and
     
  750 units of membership interests (representing 75% total equity ownership) of Tiger Energy Partners International, LLC (“TEPI”), a Nevada limited liability company with owned assets including:

 

  All rights and interests pertaining to the Global Settlement Agreement (“GSA”) for the Uintah and Ouray Reservation between Mountain Oil & Gas, Inc. and certain entities affiliated with it and the Ute Indian Tribe of the Uintah and Ouray Reservation, dated December 22, 2014;
     
  All rights and interests acquired in the Purchase and Sale Agreements between TEPI and Mountain Oil & Gas, Inc. dated April 16, 2012, and December 18, 2012
     
  All cash held in an attorney trust account earmarked for payments to certain vendors and other creditors;
     
  $240,000 cash held in escrow for State of Utah Department of Natural Resources Division of Oil, Gas and Mining (DOGM); and
     
  Cash balances in all company bank accounts

 

Prominent Sino Holdings Limited (“PSH”) and Value Train Investments Limited (“VTI”), each a British Virgin Islands limited liability company, and each a direct wholly-owned subsidiary of TBL, and that together own 55.63% of the shares of Grey Hawk Exploration, Inc. (“Grey Hawk”), a British Columbia, Canada company, constituting ownership of 13,166,667 Grey Hawk common shares. Grey Hawk owns a non-operated working interest in two non-producing wells in the southern portion of the Natural Buttes Field.

 

F-14
 

 

Pursuant to the PSA the parties agreed to determine and pay the purchase price of $10.75 million for these assets and ownership interests as follows:

 

A cash payment of $75,000 in connection with closing;
   
Additional cash payment of $675,000 payable within 10 business days following execution of the agreement;
   
2,083,334 shares of restricted common stock of the Company valued for accounting purposes at $3,812,500, or at price per share of $1.83 (valued by the parties at $4,000,000 at an agreed upon price per share of $1.92); and
   
A promissory note delivered at closing in the principal amount of $6,000,000 that:

 

  has a term of 18 months from the Closing Date;
     
  accrues no interest during its term; and
     
  requires the entire principal amount to be due and payable upon maturity.

 

The acquisition price was allocated to the assets acquired and liabilities assumed based upon their estimated fair values. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.

 

Assets    
Cash  $358,130 
Cash in escrow   240,000 
Oil and gas properties   10,016,990 
Drilling equipment   265,578 
Investment   100 
Bond deposits   295,000 
Liabilities     
Accounts payable   (389,325)
Contingent liabilities   (213,372)
Related party payable   (10,600)
Net assets acquired   10,562,501 

 

TBL had no operating activities during the year ended December 31, 2016; hence no pro forma information is included for this acquisition.

 

Concurrently with the foregoing, the Company also acquired the remaining 25% membership interests in TEPI from Green Stone Capital Partners Limited, a Cayman Islands limited liability company, in exchange for assumption of Greenstone’s proportionate share of TEPI obligations and liabilities. Kevin Sylla, who beneficially owns approximately 53% of Wilshire Energy Partners, LLC, a principal stockholder of the Company, and who has served as Managing Director of TEPI and of TEO introduced the Company to TBL. Subsequently, Mr. Sylla was appointed director and Chief Executive Officer of FPI effective March 1, 2017.

 

Note 4 – Property and Equipment

 

Oil and Gas Properties

 

The Company’s oil and gas properties at December 31, 2017 and 2016 are located in the United States of America.

 

F-15
 

 

The carrying values of the Company’s oil and gas properties, net of depletion, depreciation, amortization, and impairment at December 31, 2017 and 2016 are set forth below in the following table:

 

   December 31, 
   2017   2016 
Unproved leasehold (1)  $977,936   $1,181,421 
Proved leasehold   10,094,760    10,252,568 
Properties subject to depletion, net of depletion   580,158     
Exploratory wells – construction-in-progress (1) (2)   1,479,282     
Total  $13,132,136   $11,433,989 

 

(1) Not subject to depletion;
(2) Expected to be reclassified from exploratory to properties subject to amortization in the first quarter of 2018.

 

       Exploration and       Depreciation, Depletion, Amortization,     
Year  Acquisition   Development   Disposition   and     
Incurred  Costs   Costs   of Assets   Impairment   Total 
                     
2016 and prior  $10,252,568   $1,181,421   $   $   $11,433,989 
2017       3,223,931        (1,525,784)   1,698,147 
Total  $10,252,568   $4,405,352   $   $(1,525,784)  $13,132,136 

 

During the year ended December 31, 2017, the Company engaged in the following activities associated with its oil and gas properties:

 

Acquired a 21.6% non-operated working interest in two exploratory horizontal gas wells in the Uinta Basin from an undisclosed party. Both wells are operated by EOG. We expect total cost of both wells will be $3.2 million. These wells align with the Company’s overall growth strategy for the Uinta Basin. The well was drilled successfully and had a small amount of production, and completion will be finalized in 2018. As of December 31, 2017, the Company incurred $1,501,377 in costs for our working interest share. The wells are classified on our consolidated balance sheets as construction-in-progress and not subject to amortization until completion has occurred which is expected to be late in the first quarter of 2018.

   

Drilled a test well on the Labokay prospect to the total measured depth of 8,795 feet, where hydrocarbons shows were not in commercial quantities to warrant completion. This well was plugged and abandoned. Since the well was not commercially viable the Company’s working interest in the underlying mineral lease terminated and we no longer have a right to acquire title to said property. We incurred $1,507,768 in the drilling of this well which was charged to impairment expense. Civil lawsuits were filed against FPOI arising from unpaid accounts in connection with drilling of this well – see Note 11 – Commitments and contingencies for additional information on the lawsuits.

   

Successfully worked over two Duck Creek wells obtaining production from the Green River formation. We incurred $70,937 in capitalized workover costs associated with these wells. 

   
Incurred costs of $22,691 for bonding, legal, title, engineering, geological and surveying in our Ladysmith project in Fremont County, Wyoming.

 

During the year ended December 31, 2016, the Company engaged in the following activities associated with its oil and gas properties:

 

Completed drilling of the Federal #1 test well in the Paw Paw project in Big Horn County, Wyoming. The test well reached total depth in the Madison Formation and the Company successfully logged and acquired valid data to further evaluate the project’s potential. Oil shows were found in the Muddy, Phosphoria, and Madison formations. The Phosphoria is a regionally productive formation and could end up being the secondary zone in sidetrack operations should that type of operation be deemed commercially economic. We incurred costs of approximately $730,000 in this project.
   
Acquired various proved oil and gas assets in Utah from Total Belief Limited, a wholly owned subsidiary of New Times Energy Corporation Limited. These assets included certain oil and gas wells throughout the Uinta Basin in Utah on acreage with over 30 proved undeveloped drilling locations, additional non-operating interest in other leases, and access to approximately 6,000 acres in the Uinta Basin with proven and probable reserves and existing infrastructure in place. Through the acquisition, the Company also obtained six shut-in wells in the Natural Buttes Field, Utah. The transaction provided the Company with the rights to an agreement to acquire up to 6,000 acres and up to 16 shut-in oil and gas wells with proved and proved undeveloped reserves on Tribal lands in the Uinta Basin. This acquisition delivered to the Company an additional 40% working interest in the Ladysmith Prospect covering 3,060 acres in the Greater Green River Basin, Wyoming, bringing the Company’s total working interest in the prospect from a pre-acquisition 35% up to 75%. We incurred $10,562,501 in acquiring these assets.
   
Incurred costs of $55,848 for to acquire additional leases and working interest and for bonding, legal, title, engineering, geological and surveying in our Ladysmith project in Fremont County, Wyoming.

 

F-16
 

 

Support Facilities and Equipment

 

The Company’s support facilities and equipment serve its oil and gas production activities. The following table summarizes these properties and equipment, together with their estimated useful lives:

 

    December 31,  
    2017     2016  
             
Tank   $ 30,000     $ 30,000  
Vehicle     69,446       69,446  
Accumulated depreciation     (31 )      
Construction in progress (1)     22,087        
Total support facilities and equipment, net   $ 121,502     $ 99,446  

 

  (1) Facilities constructed in conjunction with drilling for our two exploratory horizontal wells in Uintah County, Utah.

 

The Company recognized depreciation expense of $31 and $0 during the years ended December 31, 2017 and 2016, respectively.

 

Office Furniture, Equipment, and Other

 

As of December 31, 2017, and 2016, office furniture, equipment, and other consisted of the following:

 

   December 31, 
   2017   2016 
Computer equipment and fixtures  $22,453   $22,453 
Vehicle        
Accumulated depreciation   (8,632)   (4,114)
Office furniture, equipment, and other, net  $13,821   $18,339 

 

During the year ended December 31, 2017, the vehicle was reclassified to Support Facilities and Equipment, as it is used in oil and gas field operations of the Company.

 

During the years ended December 31, 2017 and 2016, depreciation expense was $8,632 and $4,114, respectively.

 

F-17
 

 

Note 5 – Asset Retirement Obligation

 

The following table provides a reconciliation of the changes in the estimated present value of asset retirement obligations for the years ended December 31, 2017 and 2016.

 

   For the Year Ended December 31, 
   2017   2016 
         
Beginning asset retirement obligations  $   $ 
Liabilities established   291,659     
Accretion expense   11,668     
Ending asset retirement obligations  $303,327   $ 

 

Accretion expense for the year ended December 31, 2017 and 2016 was $11,668 and $0, respectively.

 

Note 6 – Notes Payable

 

A summary of the outstanding amounts of our Notes payable as of December 31, 2017 and 2016 is as follows:

 

   December 31, 
   2017   2016 
9% unsecured note payable due May 6, 2017 (1)  $-   $- 
13.5% unsecured note payable due September 8, 2017 (2)   1,050,000    - 
0% unsecured note payable due June 30, 2018 (3)   6,000,000    6,000,000 
Less: unamortized discount of imputed interest of 4% (3)   (114,268)   - 
0% unsecured note payable due January 2, 2018 (4)   250,000    - 
Less: unamortized discount of imputed interest of 4% (4)   (2,264)   - 
12% unsecured note payable June 30, 2018 (5)   120,629    - 
Total debt   7,304,097    6,000,000 
Less: current maturities   7,304,097    - 
Long-term debt, net of current maturities   -    6,000,000 

 

At December 31, 2017, the principal amounts due under our debt agreements were all classified as current on our Consolidated Balance Sheets.

 

(1) On December 30, 2016, effective January 5, 2017, Foothills borrowed $1,000,000 from Full Wealth Investment Hong Kong Limited, a limited liability company organized under the laws of Hong Kong. The Company used net proceeds of this loan to satisfy certain obligations under a Purchase and Sale Agreement with Total Belief Limited, dated December 30, 2016, for general working capital and to support certain target drilling activities. On May 18, 2017, Full Wealth Investment Hong Kong Limited sold this note to Gold Class Limited, with accrued interest increased from 9% to 13.5% per annum for the life of the debenture. On June 1, 2017, Full Wealth Investment Hong Kong Limited acquired this note from Gold Class with a 60-day term and 10% interest per annum for the life of the debenture. On August 14, 2017, we repaid $1,000,000 in principal and $20,000 in accrued interest and reclassified the remaining accrued interest of $30,000 as a gain on extinguishment of debt.
   
(2) Effective August 9, 2017, Foothills borrowed $1,050,000 from Profit Well Limited, a Hong Kong limited liability company. The Company executed a Bridge Note with an annual percentage interest rate of 13.5% and a maturity date of September 8, 2017. Proceeds of this Bridge Note were primarily used to repay Full Wealth for the debenture dated June 1, 2017. On November 3, 2017, Profit Well Limited agreed to defer repayment of this note to a later date and acknowledged that the Company is not in default regarding this Debenture. Profit Well Limited also reaffirmed its belief that the Company will either extend or repay the obligation to the satisfaction of Profit Well. As partial consideration for the deferment, the Company agreed to issue Profit Well Limited 100,000 shares of its restricted common stock, valued at $48,000. The issuance of the shares in exchange for the maturity extension was treated as a modification of existing debt pursuant to the guidance of ASC 470-50 “Debt – Modifications and Extinguishments” (“ASC 470-50”).

 

F-18
 

 

(3) On December 30, 2016, in connection with the TBL acquisition (see Note 3 - Acquisitions), Foothills entered into a promissory note in the amount of $6,000,000. This note bears no interest during its term. The Company calculated and recorded $342,804 of imputed interest as debt discount.
   
(4)

On September 29, 2017, the Company issued to an unaffiliated investor a promissory note and three tranches of warrants for an aggregate consideration of $250,000. The Note recites that it accrues no interest if paid when due and is due and payable on January 2, 2018. If principal is not paid on or before maturity, interest will accrue at the rate of 15% per year until paid. On November 6, 2017, the Company agreed to compensate the investor 75,000 shares of the Company’s restricted common stock in connection with a more favorable term of a note entered with FirstFire Opportunity Fund, LLC. On December 30, 2017, the Company and the investor agreed to extend the maturity date of this Note to January 23, 2018, in return for a payment at maturity of the principal, accrued interest as provided in the Note, plus 30,000 shares of the Company’s restricted common stock. Because the fair value of the shares was greater than 10% of the present value of the remaining cash flows under the Note, the issuance of the shares in connection with a more favorable term of a note entered with FirstFire Opportunity Fund, LLC. was treated as a debt extinguishment and reissuance of a new debt instrument pursuant to the guidance of ASC 470-50 “Debt – Modifications and Extinguishments” (“ASC 470-50”).

 

Since January 23, 2018, the Company and the investor have been in ongoing discussions to extend the term of this Note. On March 28, 2018, the investor acknowledged that the Company is not in default regarding this Note and reaffirmed its belief that the Company will either extend the Note’s due date or repay its obligation on terms that are mutually satisfactory. The warrants have the following terms:

 

  375,000 warrants to purchase 375,000 shares of common stock of the Company at a strike price of $0.665 per share expiring on September 29, 2019;
     
  375,000 warrants to purchase 375,000 shares of common stock of the Company at a strike price of $1.25 per share expiring on September 29, 2020; and
     
  185,000 warrants to purchase 185,000 shares of common stock of the Company at a strike price of $2.00 per share expiring on September 29, 2020.

 

The aggregate relative fair value of three tranches of warrants was determined to be $105,000 on September 29, 2017, using the Black-Scholes option-pricing model based on the following assumptions: (i) volatility rate of 94%, (ii) discount rate of 0%, (iii) zero expected dividend yield, and (iv) expected life of 2-3 years. $2,536 imputed interest was recorded as debt discount. $2,536 was determined using the present value method based on the following assumptions: (i) adjusted interest rate 4% (ii) expected life of 0.26 year. The aggregate value of the warrants and imputed interest of $107,536 was considered as debt discount upon issuance and will be amortized as interest over the term of the Note or in full upon the conversion of the Note. During the year ended December 31, 2017, the Company amortized $105,272 of such discount to interest expense, and the unamortized discount as of December 31, 2017 was $2,264. At December 31, 2017, $250,000 of principal was outstanding under the Note.

 

Each tranche of warrants is subject to down round adjustment provisions if the Company during the term of that tranche issues additional securities for consideration per share, after giving effect to fees, commission and expenses, that is less, or which on conversion or exercise of the underlying security is less, than $0.665 per share (as adjusted for any change resulting from forward or reverse splits, stock dividends and similar events).

 

To satisfy most favored nation provisions in previously entered securities purchase agreements that are triggered by the transaction described above, Company issued 136,015 shares of common stock and warrants to purchase 136,015 shares of common stock, in the aggregate, to certain investors who purchased units from the Company, at a $1.00 per unit, with each unit consisting of one share and one warrant. See the Company’s Current Report on the Form 8-K filed with the SEC on June 5, 2017. Of this amount, 100,752 shares and warrants to purchase 100,752 shares of common stock will be issued to Wilshire Energy Partners LLC, an entity controlled by Kevin J. Sylla. The exercise price of these investor warrants was adjusted to $0.665 per share. We measured the value of the effect of the down round feature as the difference between the fair value of the financial instrument at an original exercise price of $1.50 and an adjusted exercise price of $0.665 and, as a result, $59,801 was recorded as down round feature as interest expense under ASC 260-10-30-1. Foothills determined the amount of $59,801 using the Black-Scholes option-pricing model based on the following assumptions: (i) volatility rate of 94%, (ii) discount rate of 0%, (iii) zero expected dividend yield, and (iv) expected life of 3 years.

 

F-19
 

 

(5) A promissory note was issued on November 1, 2017, for services rendered, bearing an interest rate of 12% per annum and with a maturity date of June 30, 2018.

 

During the years ended December 31, 2017 and 2016, respectively, we incurred $442,389 and $27,873 of interest expense, including amortization of discount and recognized a gain on extinguishment of debt of $30,000 and $0, respectively.

 

Note 7 – Notes Payable - Related Party

 

   December 31, 
   2017   2016 
13.25% unsecured note payable due May 5, 2017 (1)  $1,250,000   $  - 
Total debt   1,250,000    - 
Less: current maturities   1,250,000    - 
Long-term debt, net of current maturities  $-   $- 

 

(1)

Effective January 5, 2017, Foothills borrowed $1,250,000 from Berwin Trading Limited that, due to its 20% beneficial ownership in the Company, is a related party. This note called for interest at 9% per annum; but because it was not paid when due interest was to have accrued at a default rate of 11% from the due date of the note. The Company used net proceeds of this loan to satisfy certain obligations under a Purchase and Sale Agreement with Total Belief Limited, dated December 30, 2016, for general working capital and to support certain target drilling activities. See Note 3 – Acquisitions.

 

On May 4, 2017, the Company and Berwin agreed to extend the maturity date of the debenture to June 20, 2017, in return for an annual interest rate increase from 9% to 13.5% per annum for the life of the debenture. On November 3, 2017, Berwin agreed to defer repayment of this note to a later date and acknowledged that the Company is not in default regarding this Debenture. As partial consideration for the deferment, the Company issued Berwin 100,000 shares of its restricted common stock, valued at $48,000. The issuance of the shares in exchange for the maturity extension was treated as a modification of existing debt pursuant to the guidance of ASC 470-50 “Debt – Modifications and Extinguishments” (“ASC 470-50”).

 

During the years ended December 31, 2017 and 2016, the Company recorded interest expense of $166,438 and $0, respectively on the related party note.

 

Note 8 – Convertible Note Payable

 

   December 31, 
   2017   2016 
10% convertible note payable due May 10. 2018 (1)  $50,000   $   - 
8% convertible note payable due August 16, 2018 (2)   267,500    - 
Less: unamortized debt discount on convertible notes (1)(2)   (224,228)   - 
Total debt   93,272    - 
Less: current maturities  93,272   - 
Long-term debt, net of current maturities  $-   $- 

 

F-20
 

 

(1) On May 10, 2017, we entered into a convertible note agreement with an unrelated party, pursuant to which we borrowed $50,000 at an annual percentage rate of 10% with a term of 12 months, which is due on May 10, 2018. This note may, at the option of the lender, be converted at any time prior to September 7, 2017, into fully-paid, restricted and non-assessable shares of common stock of the Company at a price equal to 100% of the selling price of such common stock in a private placement to institutional and/or accredited investors initiated by the Company during thunder this convertible note until May 10, 2018. On November 7, 2017, the Company issued 50,000 warrants to purchase 50,000 shares of common stock of the Company at a strike price of $1.00 per share expiring on May 7, 2019. If the Company fails to pay the principal and accrued unpaid interest due and payable to Lender on or before the due date of the convertible note, then the Lender shall be provided the right to convert at either $0.665 per share or upon the same terms offered in FirstFire Opportunity Fund, LLC Note’s conversion options. The relative fair value of warrant was determined to be $3,381 on November 7, 2017, using the Black-Scholes option-pricing model based on the following assumptions: (i) volatility rate of 77%, (ii) discount rate of 0%, (iii) zero expected dividend yield, and (iv) expected life of 1.5 years. The issuance of the warrants in exchange for the maturity extension was treated as a modification of existing debt pursuant to the guidance of ASC 470-50 “Debt – Modifications and Extinguishments” (“ASC 470-50”).
   
(2) On November 17, 2017, the Company issued to FirstFire Opportunity Fund, LLC, an unaffiliated investor, a senior convertible promissory note in the principal amount of $267,500 and received proceeds of $250,000 before giving effect to certain transactional costs including legal fees. As part of this transaction the Company also issued (i) warrants having an 18-month term, to purchase 267,500 shares of the Company’s common stock at an exercise price of $1.00 per share and (ii) 60,000 shares of the Company’s restricted common stock. This note accrues interest of 8% per annum and is due and payable on August 17, 2018. The Note agreements give the lender the right to convert the loan amounts due into common stock at a conversion price of the lower of (i) $0.665 per share or (ii) 50% of the lowest per share market values during the twenty (20) trading days immediately preceding a conversion date. If the lowest traded price of the Common Stock is less than the Conversion Price on the date following the Conversion Date on which the Holder actually receives from the Company, then the Conversion Price shall be deemed to have been retroactively adjusted, as of the Conversion Date, to a price equal to 75% multiplied by the lowest closing price of the Common Stock on the Free Trading Shares Receipt Date. This note is secured by a personal guaranty from the Company’s Executive Chairman, Kevin Sylla. The net proceeds of this note will be used for general corporate and working capital purposes. The aggregate relative fair value of warrant was determined to be $10,750 on November 17, 2017, using the Black-Scholes option-pricing model based on the following assumptions: (i) volatility rate of 78%, (ii) discount rate of 0%, (iii) zero expected dividend yield, and (iv) expected life of 1.5 year. Fair value of 60,000 shares of common stock was determined $18,250 using allocation of proceeds. The Company accounted for the conversion feature as a derivative valued at $288,964, of which $67,964 was expensed immediately to interest expense. $288,964 was determined using the Black-Scholes option-pricing model based on the following assumptions: (i) volatility rate of 78%, (ii) discount rate of 0%, (iii) zero expected dividend yield, and (iv) expected life of 0.75 year. The aggregate value of the original debt discount, warrant, conversion feature and 60,000 shares of common stock of $267,500 was considered as debt discount upon issuance and is being amortized to interest expense over the term of the Note or in full upon the conversion of the Note. As of December 31, 2017, Company accounted for the conversion feature as a derivative valued at $458,387 which was determined using the Black-Scholes option-pricing model based on the following assumptions: (i) volatility rate of 77%, (ii) discount rate of 0%, (iii) zero expected dividend yield, and (iv) expected life of 0.6 year.

 

During the years ended December 31, 2017 and 2016, the Company incurred $49,071 and $0, respectively, of interest expense on the convertible notes and amortization of discount.

 

Note 9 – Common Stock

 

Effective April 1, 2016, Foothills appointed two directors to its board. Each director was granted 125,000 shares of common stock (the “Foothills Directors Shares”), vesting according to the following schedule: (i) 40% vesting ninety (90) days from the appointment date; (ii) 20% vesting one hundred eighty (180) days from the appointment date; (iii) 20% vesting two hundred seventy (270) days following the appointment date; (iv) 20% vesting three hundred sixty (360) days following the appointment date. During the year ended December 31, 2017, we issued 25,000 shares of common stock to each director. As of December 31, 2017, the Company issued 125,000 shares to each director and the Company incurred compensation expense for each director of $1,250 for these share issuances. These Foothills Director Shares issued in April 2016 all vested approximately one year later pursuant to the terms and conditions of the grant.

 

F-21
 

 

On May 2, 2016, FPI acquired 14,112,250 pre-split shares of the common stock of Key Link Assets Corp. (“Key Link” or the “Company”) from five persons constituting approximately 96% of our issued and outstanding shares (the “FPI Acquired Shares”). These shares were acquired for cash of $316,035, which was expensed in the period it was incurred.

 

As of May 16, 2016, Foothills effected a 4:1 forward split of its shares of common stock. All references to the number of shares issued and outstanding in these financial states have been retrospectively restated for the forward split.

 

The 14,112,250 pre-split shares were converted into 56,449,000 shares post-split and were returned to treasury for cancellation. A total of 2,360,000 shares remained outstanding held by the shareholders of the merged public company post the reverse merger acquisition.

 

On May 2, 2016, after obtaining the FPI Acquired Shares, FPI caused the Company to appoint its two non-executive directors to the Board of the Company. These directors exchanged their rights to the FPI Directors Shares for Company shares having substantially the same terms and provisions. On May 2, 2016, the Company also granted 150,000 restricted shares of its common stock to its CEO as a part of his compensation package. The shares have the same vesting schedule as directors’ shares described above. These shares granted in May 2016 all vested approximately one year later pursuant to the terms and conditions of the grant. During the year ended December 31, 2017, we issued 30,000 shares of common stock. As of December 31, 2017, 150,000 shares were issued and the Company incurred compensation expense of $1,500 for these share issuances.

 

On May 27, 2016, we entered into a Share Exchange Agreement with the shareholders of FPI whereby we acquired all of the outstanding shares of FPI for an aggregate of 6,003,759 shares of our common stock, of which 4,500,000 shares of our common stock were issued to Wilshire Energy Partners, LLC, (“Wilshire”) and 1,503,759 of our shares of common stock were issuable to Alternus (“Share Exchange”). As a result of the Share Exchange, FPI became our wholly owned subsidiary and the FPI Acquired Shares were returned to treasury, deemed canceled and no longer outstanding. We also exchanged warrants to purchase 700,000 shares of Foothills’ common stock, that were issued to Wilshire on May 4, 2016, for a like amount of warrants to purchase shares of the Company’s common stock (the “Wilshire Warrants”). The Wilshire Warrants:

 

  have a term of five years;
     
  are exercisable at $1.25 per share as to 100,000 shares;
     
  are exercisable at $2.00 per share as to 200,000 shares;
     
  are exercisable at $3.00 per share as to 400,000 shares;
     
  do not have a cashless exercise feature; and
     
  were not exercisable for one year.

 

On June 30, 2016, we entered into a Securities Purchase Agreement with Berwin Trading Limited, a British Virgin Islands company (“Berwin”), pursuant to which we sold and agreed to issue 3,007,519 shares of our common stock, $0.0001 par value, at a purchase price of $0.665 per share for an aggregate amount of $2,000,000.

 

On December 30, 2016, we issued 2,083,334 shares of common stock in connection with the TBL acquisition (see Note 3), at a purchase price of $1.83 per share for an aggregate amount of $3,812,500.

 

On May 31, 2017, we entered into a Securities Purchase Agreement with Wilshire Energy Partners, LLC, a principal shareholder, pursuant to which we sold and agreed to issue 200,000 units at a purchase price of $1.00 per unit for an aggregate amount of $200,000. Each unit consisted of one share of the Company’s common stock and one warrant to purchase a share of the Company’s common stock, exercisable for a period of three years from the date of original issuance at an exercise price of $1.50 per share. Wilshire Energy Partners, LLC, is controlled by Kevin J. Sylla, our Executive Chairman and Chief Executive Officer of FPI. See Form 8-K filed by the Company on June 5, 2017 with the Commission and exhibit thereto. On September 29, 2017, we issued 100,752 additional shares of common stock and total warrants as amended to purchase 300,752 shares of common stock of the Company at a strike price of $0.665 per share due to down round feature triggered by warrant issued at a strike price of $0.665 per share on the day of trigger.

 

F-22
 

 

On June 15, 2017, we entered into a Securities Purchase Agreement with an investor, pursuant to which we sold and agreed to issue 20,000 units at a purchase price of $1.00 per unit for an aggregate amount of $20,000. Each unit consisted of one share of the Company’s common stock and one warrant to purchase one additional share of the Company’s common stock, exercisable for a period of three years from the date of original issuance at an exercise price of $1.50 per share. We received the initial $10,000 on June 15, 2017, and the balance of the subscribed amount in July 2017. On September 29, 2017, we issued 10,075 additional shares of common stock and total warrants as amended to purchase 30,075 shares of common stock of the Company at a strike price of $0.665 per share due to a down round feature triggered by a warrant issued at a strike price of $0.665 per share on the day of trigger.

 

On June 30, 2017, we entered into a Securities Purchase Agreement with a third-party investor, pursuant to which we sold and agreed to issue 25,000 units at a purchase price of $1.00 per unit for an aggregate amount of $25,000. Each unit consisted of one share of the Company’s common stock and one warrant to purchase one additional share of the Company’s common stock, exercisable for a period of three years from the date of original issuance at an exercise price of $1.50 per share. On September 29, 2017, we issued 12,594 additional shares of common stock and total warrants as amended to purchase 37,594 shares of common stock of the Company at a strike price of $0.665 per share due to a down round feature triggered by a warrant issued at a strike price of $0.665 per share on the day of trigger.

 

On July 10, 2017, we entered into a Securities Purchase Agreement pursuant to which we sold 25,000 units at a purchase price of $1.00 per unit for an aggregate amount of $25,000. Each unit consisted of one share of the Company’s common stock and one warrant to purchase a share of the Company’s common stock, exercisable for a period of three years from the date of original issuance at an exercise price of $1.50 per share.

 

We measured the value of the effect of the down round feature as the difference between the fair value of the financial instrument at an original exercise price of $1.50 and an adjusted exercise price of $0.665 and, as a result, $59,801 was recorded as down round feature as interest expense under ASC 260-10-30-1. Foothills determined the amount of $59,801 using the Black-Scholes option-pricing model based on the following assumptions: (i) volatility rate of 94%, (ii) discount rate of 0%, (iii) zero expected dividend yield, and (iv) expected life of 3 years.

 

On November 3, 2017, the Company issued 100,000 shares of common stock upon extension of the Berwin debenture, valued at $48,000.

 

On November 3, 2017, the Company agreed to issue 100,000 shares of common stock upon extension of the Profit Well debenture. The Company recorded $48,000 in stock payable.

 

On November 6, 2017, the Company agreed to issue 75,000 shares of common stock upon extension of a debenture entered on September 29, 2017. The Company recorded $36,000 in stock payable.

 

On November 17, 2017, the Company issued 60,000 shares of common stock in connection with a senior convertible promissory note. These shares were valued at $18,250.

 

On December 30, 2017, the Company agreed to issue 30,000 shares of common stock upon extension of a debenture entered on September 29, 2017. The Company recorded $9,900 in stock payable.

 

Each of the purchasers is an accredited investor within the meaning of the federal securities laws. The Company paid no brokerage, commission or finder’s fee in connection with these transactions. These transactions were exempt from registration under Section 4(a)(2) of the Securities Act of 1933.

 

During the year ended December 31, 2017, the Company issued 275,000 shares of common stock to various third parties for services, valued at $453,500.

 

As of December 31, 2017, the Company had 14,900,627 shares of common stock issued and outstanding.

 

F-23
 

 

Restricted Stock Units (RSUs)

 

Effective August 11, 2016, and on August 15, 2016, Foothills granted one of its executive officers, Mr. R. Lanclos, 100,000 restricted stock units (RSUs) of the Company which vested as follows (i) 20,000 vested on February 15, 2017, (ii) 20,000 vested on May 15, 2017, and (iii) 60,000 vested on August 15, 2017. The Company has the right, but not the obligation to repurchase all or any portion of RSUs granted to the executive at a price of $0.665 per share if the executive’s employment with the Company is terminated for any reason within 30 months of start of employment on August 15, 2015. These RSU’s were valued at $67,000 on the grant day. As of December 31, 2017, 100,000 shares were vested and were issued to Mr. Lanclos.

 

On August 15, 2016, Foothills also granted one of its executive officers, Mr. E. Ovalle, 100,000 restricted stock units (RSUs) of the Company which vested as follows (i) 20,000 vested on February 15, 2017, (ii) 20,000 vested on May 15, 2017, and (iii) 60,000 vested on August 15, 2017. The Company has the right, but not the obligation to repurchase all or any portion of RSUs granted to the executive at a price of $0.665 per share if executive’s employment with the Company is terminated for any reason within 30 months of start of employment on August 15, 2015. These RSU’s were valued at $67,000 on the grant day. As of December 31, 2017, 100,000 shares were vested and were issued to Mr. Ovalle.

 

Warrants

 

On May 27, 2016, the Company granted to Wilshire Energy Partners, LLC, warrants (“Wilshire Warrants”) to purchase (i) 100,000 common shares at a strike price of $1.25 per share, (ii) 200,000 common shares at a strike price of $2.00 per share and (iii) 400,000 common shares at a strike price of $3.00 per share. The Wilshire Warrants commence to be exercisable on the earlier of (i) 12-month anniversary of the closing of a going public transaction or (ii) June 30, 2017 and expire on June 1, 2021.

 

On May 27, 2016, the Company granted to an unrelated party warrants to purchase (i) 125,000 common shares at a strike price of $1.25 per share, (ii) 100,000 common shares at a strike price of $2.00 per share and (iii) 100,000 common shares at a strike price of $3.00 per share. The warrants commence to be exercisable on the earlier of (i) 12-month anniversary of the closing of a going public transaction or (ii) June 30, 2017 and expire on June 1, 2021.

 

The fair value of above warrants was determined to be $2,144 on May 27, 2016, using the Black-Scholes option-pricing model based on the following assumptions: (i) volatility rate of 120%, (ii) discount rate of 0%, (iii) zero expected dividend yield, and (iv) expected life of 5 years.

 

On November 7, 2017, the Company issued 50,000 warrants to purchase 50,000 shares of common stock of the Company at a strike price of $1.00 per share expiring on May 7, 2019 in connection with a senior convertible promissory note in the principal amount of $50,000. If the Company fails to pay the principal and accrued unpaid interest due and payable to Lender on or before the due date of the convertible note, then the Lender shall be provided the right to convert at either $0.665 per share or upon the same terms offered in FirstFire Opportunity Fund, LLC Note’s conversion options. The relative fair value of warrant was determined to be $3,381 on November 7, 2017, using the Black-Scholes option-pricing model based on the following assumptions: (i) volatility rate of 77%, (ii) discount rate of 0%, (iii) zero expected dividend yield, and (iv) expected life of 1.5 years.

 

On November 17, 2017, the Company issued an unaffiliated investor warrants to purchase 267,500 shares of the Company’s common stock at an exercise price of $1.00 per share and expires in 18 months, in connection with a senior convertible promissory note in the principal amount of $267,500.  The aggregate relative fair value of warrant was determined to be $10,750 on November 17, 2017, using the Black-Scholes option-pricing model based on the following assumptions: (i) volatility rate of 78%, (ii) discount rate of 0%, (iii) zero expected dividend yield, and (iv) expected life of 1.5 year.

 

F-24
 

 

The following table summarizes all stock warrant activity for the year ended December 31, 2017 and 2016:

 

   Number of
Warrants
   Weighted Average
Exercise Price
   Weighted Average
Remaining
Contractual Term
 
Balance outstanding, December 31, 2015   -   $-    - 
Granted   1,025,000    2.32    4.42 
Exercised   -    -    - 
Cancelled or expired   -    -    - 
Balance outstanding, December 31, 2016   1,025,000   $2.32    4.42 
Granted   1,658,515    1.09    2.18 
Exercised   -    -    - 
Cancelled or expired   -    -    - 
Balance outstanding, December 31, 2017   2,683,515   $1.56    2.65 
Exercisable, December 31, 2017   -   $-    - 

 

Options

 

On May 19, 2016, the Company granted to each of its then three directors options to purchase (i) 50,000 common shares at a strike price of $2 per share, vesting when the Company achieves and maintains a total average daily production level of 100 barrels of oil equivalent per day (“BOE/D”) for at least 30 days, (ii) 50,000 common shares at a strike price of $3 per share, vesting when the Company achieves and maintains a total average daily production level of 200 BOE/D for at least 60 days, and (iii) 50,000 common shares at a strike price of $4 per share, vesting when the Company achieves and maintains a total average daily production level of 500 BOE/D for at least 90 days.

 

On February 27, 2017, the Company granted to Mr. Christopher Jarvis, currently an officer and director, options to purchase 400,000 common shares at a strike price of $1.99 per share, vesting quarterly over two years commencing with the first quarter following the 90-day probationary period.

 

The fair value of 400,000 options was determined to be $616,055 on February 27, 2017, using the Black-Scholes option-pricing model based on the following assumptions: (i) volatility rate of 129%, (ii) discount rate of 0%, (iii) zero expected dividend yield, and (iv) expected life of 5 years.

 

On February 27, 2017, the Company granted to Mr. Kevin Sylla, currently our Executive Chairman of the Board, options to purchase 1,200,000 common shares at a strike price of $1.99 per share, vesting quarterly over the term of three years.

 

The fair value of 1,200,000 options was determined to be $1,986,902 on February 27, 2017, using the Black-Scholes option-pricing model based on the following assumptions: (i) volatility rate of 129%, (ii) discount rate of 0%, (iii) zero expected dividend yield, and (iv) expected life of 7 years.

 

During December 31, 2017 and 2016, we recorded $816,139 and $0 option expense. As of December 31, 2017, the unamortized option expense was $1,786,818.

 

The following table summarizes all stock option activity for the year ended December 31, 2017 and 2016:

 

   Number of Option   Weighted Average Exercise Price   Weighted Average Remaining Contractual Term 
Balance outstanding, December 31, 2015   -   $-    - 
Granted   450,000    3.00    9.39 
Exercised   -    -    - 
Cancelled or expired   -    -    - 
Balance outstanding, December 31, 2016   450,000   $3.00    9.39 
Granted   1,600,000    -    - 
Exercised   -    -    - 
Cancelled or expired   -    -    - 
Balance outstanding, December 31, 2017   2,050,000   $2.21    6.26 
Exercisable, December 31, 2017   -   $-    - 

 

F-25
 

 

Note 10– Other Related Party Transactions

 

Alternus Capital Holdings Limited

 

On December 24, 2015, FPI entered into a convertible promissory note in the amount of $600,000 with Alternus. The two-year note originally matured on December 23, 2017, and accrued interest at 8% per year. By its terms the Note was automatically required to convert the outstanding principal and interest due under the terms of the Note upon a merger or other combination occurring between FPI and an entity with shares listed for trading, which occurred on May 27, 2016. The conversion price of the Note was established at $0.665 per share (the “Conversion Price”), subject to adjustment as described below. On April 5, 2016, and under substantially similar terms described herein, FPI received an additional $400,000 from Alternus. Under the agreements between Alternus and Foothills, Alternus had the right but not the obligation to subscribe for an aggregate of up to $3,500,000 of convertible notes, which, in the event of that full subscription, would convert into not less than 30% of the then outstanding shares of the “public” company. Through May 27, 2016, the date the Share Exchange, Alternus had invested $1,000,000 and based on the Conversion Price was issued 1,503,759 shares of the Company’s common stock in full satisfaction of its two notes. As a result, Alternus became a 10% beneficial owner in the Company and a related party. All accrued interest was waived and recorded as additional paid in capital.

 

Wilshire Energy Partners, LLC

 

On May 31, 2017, we entered into a Securities Purchase Agreement with Wilshire, pursuant to which we sold and agreed to issue 200,000 units at a purchase price of $1.00 per unit for an aggregate amount of $200,000. Each unit consisted of one share of the Company’s common stock and one warrant to purchase a share of the Company’s common stock, exercisable for a period of three years from the date of original issuance at an exercise price of $1.50 per share. Wilshire Energy Partners, LLC, is controlled by Kevin J. Sylla, our Executive Chairman and Chief Executive Officer of FPI, and has been determined to be a Related Party. See the Company’s 8-K filed June 5, 2017 with the Commission and exhibit thereto. On September 29, 2017, we issued 100,752 additional shares of common stock and amended warrants to purchase 300,752 shares of common stock of the Company at a strike price of $0.665 per share due to a down round feature triggered by a warrant issued at a strike price of $0.665 per share on the day of trigger.

 

On December 30, 2016, the Company, entered into a purchase and sale agreement with Total Belief Limited (see Note 3 - Acquisitions). As a result of the acquisition the Company assumed a $10,600 related party payable due to Equipment Solutions, Inc., which is owned by a director of the Company, Alex Hemb. During the year ended December 31, 2017, the balance was paid.

 

Note 11 – Commitments and Contingencies

 

Contractual Obligations

 

Operating Leases

 

Effective May 1, 2017, the Company entered into a 39-month lease, expiring July 31, 2020, for its Denver, Colorado, corporate office at a total rental of approximately $10,051 per month. During the year ended December 31, 2017, the Company paid $47,821 for its Denver office space.

 

On October 5, 2016, the Company launched its Exploration Division and opened a new office in Houston, Texas, to support the division’s staff, at a monthly rental amount of $2,298. On March 27, 2018, the Company closed that office. During the year ended December 31, 2017, the Company paid $6,894 for its Houston office space.

 

The Company leases a copier at monthly rental of $135 through September 23, 2020, for its Denver, Colorado, office. During the year ended December 31, 2017, the Company paid $1,649 in rental for the copier.

 

F-26
 

 

During 2017, the Company’s rental expense was $1,649 for all operating leases.

 

During 2016, the Company’s rental expense was $0 for all operating leases.

 

Information regarding all the Company’s contractual lease obligations, at December 31, 2017, is set forth in the following table.

 

   Operating Leases 
     
2018  $123,668 
2019   125,816 
2020   74,347 
2021 and thereafter    
Total  $323,831 

 

Legal proceedings

 

The Company has determined that judgments rendered in the first quarter of 2018 in connection with all but four of the following legal proceedings against the Company are Type 1 subsequent events that provide additional evidence with respect to conditions that existed at the date of the balance sheet. Therefore, the financial statements reflect the effects of prejudgment judgments awards to plaintiffs as through the year ended December 31, 2017, noted below in accordance with Auditing Standard 2801.03.

 

Utah Wells

 

SCI Welding & Oilfield Service vs. Tiger Energy Operating LLC (Case No. 169000023, 8th District Court, Duchesne County, State of Utah)

 

This case concerns the collection of unpaid debt owed by TEO, relating to the workover of wells in Duchesne County, Utah, in the amount of $53,407. On September 29, 2017, the TEO and SCI Welding reached an agreement to settle the matter for $35,000 which TEO paid to SCI Welding. We recorded $18,407 as gain on extinguishment of debt. A Stipulated Motion to Dismiss (signed by all parties) and an Order by the Court Dismissing Case was filed on October 11, 2017. This is a final settlement of this matter with no further judicial action required.

 

Graco Fishing & Rental Tools, Inc. vs. Tiger Energy Operating LLC (Case No. 160800005 8th Judicial District Court, Duchesne County, State of Utah)

 

Plaintiff in this case sought collection of unpaid debt incurred by TEO for services rendered in connection with its workover of wells in Duchesne County, Utah. On June 1, 2016, a default judgment of $159,965 was obtained against TEO by Plaintiff. Graco filed a writ of execution against the A Rust 2, Dye-Hall 2-21 A1, Wilkins 1-24 A5 and Rust 3-22A-4 wells located in Duchesne County executing on properties not owned by us. A Motion to Set Aside the sheriff’s sale of these properties was filed with the court based on the fact that TEO was not the owner of these properties. A hearing for this matter was held on May 1, 2017, in Duchesne County, Utah, at which time a Company representative was present to comply with the court’s order to produce documents. Prior to the hearing, TEO made an initial settlement offer, which was eventually rejected by Graco. A writ of execution was issued to seize the property subject of litigation on March 8, 2018.

 

Graco had scheduled certain foreclosure sales of TEO’s interests in various oil and gas wells to take place on May 3, 2018 (the “Sales”). On April 27, 2018, the parties reached a settlement and release agreement whereby TEO agreed to make five (5) payments totaling $163,964.59 to Graco. The first payment due on May 9, 2018, has already been made to the judgment holder. The second payment of $32,792.92 is due on July 9, 2018; the third payment of $32,792.92 is due on September 9, 2018; the fourth payment of $32,792,92 is due on November 9, 2018; and fifth and final payment of $32,792.92 is due on January 9, 2019. If any of the above payments are not made when due, Grace will have the right to immediately execute the Sales. Graco will maintain and apply liens and notices of its judgment until the total payment has been paid in full by TEO. TEO shall be provided with a 10-day period within which to cure any default under the settlement agreement, other than making the first payment described above. TEO made its second payment of $32,793 on July 19, 2018, within the 10-day cure period provided in the settlement agreement.

 

F-27
 

 

Conquest Well Servicing, LLC vs. Foothills Exploration Operating, Inc. (Case No. 179800421 8th Judicial District Court in and for Uintah County, State of Utah)

 

Plaintiff filed this action on September 11, 2017, for collection of unpaid services and materials in the amount of $49,689 in connection with a workover of wells in Uintah County, Utah. A Settlement Agreement and Stipulation to Entry of Judgment was agreed to by the parties and filed with the court on October 10, 2017. Judgment in the amount of $54,937.10 including $5,248.10 in pre-judgement interest was filed on December 18, 2017. An order requesting company asset inquiry was issued on February 20, 2018. As of July 26, 2018, no further action has been taken.

 

Peak Well Service, LLC v. Tiger Energy Operating, LLC (Case No. 2:16-CV-00957-EJF United States District Court for the District of Utah Court)

 

Peak Well Service, LLC (“Peak”), filed mechanics and materialman’s liens against the Wilkins, Rust 2 Well, Dye Hall 2, Rust 3, and Josie 1 wells operated by TEO for unpaid accounts in connection with work on these wells. A settlement was reached between TEO and Peak pursuant to a confidential settlement agreement. Pursuant to the settlement agreement, lien releases on each of these well liens were filed on February 8, 2017. This settlement is a final resolution of this creditor claim.

 

BIA Administrative Appeal – Tiger Energy Partners International, LLC

 

Notice of Appeal: Dated May 8, 2013
Appellant: Tiger Energy Partners International, LLC
Appellee: Superintendent Uintah and Ouray Agency
Decision April 12, 2013
Concerning: Notice of Expiration of Oil and Gas Leases

 

This Administrative appeal concerns the ownership and validity of Northern Ute (the “Tribe”) Tribal leases acquired by Tiger Energy Partners International, LLC (TEPI) in a transaction with Mountain Oil and Gas and its affiliated companies. Pursuant to the Global Settlement Agreement (GSA) negotiated between the Tribe and TEPI, the Company proposes to resolve any issues regarding the ownership of the subject leases and other lands thus acquired. The status of the appeal by TEPI remained unchanged at December 31, 2017, awaiting decision by the Regional Director of the BIA on the merits of the appeal. The decision of the Regional Director is stayed by the parties having entered into the GSA. The Tribe and Tiger remain in discussion regarding approval of the Global Settlement Agreement by the Regional Director.

 

Labokay Well – Parish of Calcasieu, State of Louisiana

 

R.W. Delaney Construction Company vs. Foothills Petroleum Operating, Inc. (Cause No. 2017-CV-0330 – County Court of Adams County, Mississippi)

 

This case was filed on September 18, 2017 and concerns the collection of amounts incurred by FPOI for services performed by plaintiff in the amount of $72,495 in connection with drilling the Labokay test well in Calcasieu Parish, Louisiana.

 

A judgment was entered on January 22, 2018, in the County Court of Adams County, Mississippi in the principal amount of $72,495.00, plus pre-judgement interest in the amount of $12,763, plus attorney’s fees in the amount of $18,124, plus costs in the amount of $196, for a total amount of $103,578, plus post-judgment interest at the rate of 8% per annum. On May 9, 2018, District Court for the City and County of Denver, Colorado, granted plaintiff with an order granting their petition to domesticate this foreign judgment with the Denver District Court, which now has the same effect and is subject to the same procedures, defenses, and proceedings for reopening, vacating, or staying as a judgment from the Denver District Court, and may be enforced or satisfied in like manner.

 

F-28
 

 

Performance Drilling Company, LLC vs. Foothills Petroleum Operating, Inc. (Case No. 2017-3916 DIV G 14th Judicial District Court in Parish of Calcasieu, State of Louisiana)

 

This case was filed on September 25, 2017, for payment of services performed by plaintiff in the amount of $205,251 for unpaid accounts in connection with its drilling of the Labokay test well. On January 16, 2018, a default judgment was entered against FPOI, in the amount of $205,251.24; together with accrued interest of $29,861 from March 18, 2017, through December 31, 2017; plus, additional interest from January 1, 2018, at the rate of one and one-half percent (1.5%) per month until paid (a per diem rate of $103.69); plus, an additional sum for reasonable attorney’s fees of $2,500, and all costs of the court proceedings. As of December 31, 2017, we recorded $29,861 of prejudgment interest expense.

 

Monster Rentals, LLC dba Deepwell Equipment Rentals vs. Foothills Petroleum Operating, Inc. (Case No. 2017-11013 DIV E – 15th Judicial District Court in Parish of Acadia, State of Louisiana)

 

This case was filed on October 24, 2017 and concerns the collection of amounts incurred by FPOI for services performed by plaintiff in the amount of $53,943.53 in connection with the Labokay test well in Calcasieu Parish, Louisiana.

 

Canal Petroleum Products, Inc. vs. Foothills Petroleum Operating, Inc. (Case No. 2017-6574; DIV. C – 15TH Judicial District Court, Lafayette Parish, Louisiana)

 

This case was filed on November 14, 2017 and concerns the collection of amounts incurred by FPOI for services performed by plaintiff in the amount of $35,981 for unpaid accounts in connection with its drilling of the Labokay test well.

 

On January 25, 2018, a default judgment was entered against FPOI in the amount of $35,981 inclusive of interest as of September 6, 2017; plus, finance charges to accrue after September 6, 2017, of one and one-half percent per month (18% per annum) until paid on the unpaid principal amount of $32,956; plus, legal fees of $8,239 together with related court costs.

 

As of December 31, 2017, we recorded $5,002 of prejudgment interest expense.

 

Smith International, Inc. vs. Foothills Petroleum Operating, Inc. (Case No. 2017-004617; DIV. E – 14th Judicial District Court, Calcasieu Parish, Louisiana)

 

This case was filed on November 7, 2017 and concerns the collection of amounts incurred by FPOI for services performed by plaintiff in the amount of $30,244 in connection with its drilling of the Labokay test well.

 

On March 23, 2018, the court issued a preliminary judgement in favor of plaintiff in the amount of $30,244, plus interest in the contractual amount of 18% per annum from the date the payment was originally due until the judgment date, plus legal interest from the judgment date until amounts are paid, plus reasonable attorneys’ fees. As of December 31, 2017, we recorded $868 of prejudgment interest expense.

 

M-I, L.L.C. d/b/a MI-SWACO vs. Foothills Petroleum Operating, Inc. (Case No. 2017-004616; DIV. G – 14th Judicial District Court, Calcasieu Parish, Louisiana)

 

This case was filed on November 7, 2017 and concerns the collection of amounts incurred by FPOI for services performed by plaintiff in the amount of $51,275 in connection with the Labokay test well.

 

On March 23, 2018, the court issued a preliminary judgment in favor of plaintiff in the amount of $51,275, plus interest in the contractual amount of 1.5% per month from the date the payment was originally due until the judgement date, plus legal interest from the judgment date until amounts are paid, plus reasonable attorney’s fees expended in the prosecution and collection of debt. As of December 31, 2017, we recorded $1,538 of prejudgment interest expense.

 

F-29
 

 

Schlumberger Technology Corporation vs. Foothills Petroleum Operating, Inc. (Case No. 2017-004618; DIV. E – 14th Judicial District Court, Calcasieu Parish, Louisiana)

 

This case was filed on November 7, 2017 and concerns the collection of amounts incurred by FPOI for services performed by plaintiff in the amount of $28,904 for unpaid accounts in connection with its drilling of the Labokay test well in Calcasieu Parish, Louisiana.

 

On March 23, 2018, the court issued a preliminary judgment in favor of plaintiff in the amount of $28,904, plus interest in the contractual amount of 1.5% per month from the date the payment was originally due until the judgment date, plus legal interest from the judgment date until amounts are paid, plus reasonable attorney’s fees expended in the prosecution and collection of debt.

 

As of December 31, 2017, and 2016, the balance of contingent liabilities was $305,935 and $213,372, respectively. During the years ended December 31, 2017 and 2016, we recorded $145,970 and $0 in contingent liabilities

 

Note 12 - Income Taxes

 

On December 22, 2017, the Tax Cuts and Jobs Act (the TCJA), which significantly modified U.S. corporate income tax law, was signed into law by President Trump. The TCJA contains significant changes to corporate income taxation, including but not limited to the reduction of the corporate income tax rate from a top marginal rate of 35% to a flat rate of 21%, limitation of the tax deduction for interest expense to 30% of earnings (except for certain small businesses), limitation of the deduction for net operating losses to 80% of current year taxable income and generally eliminating net operating loss carrybacks, allowing net operating losses to carryforward without expiration, one-time taxation of offshore earnings at reduced rates regardless of whether they are repatriated, elimination of U.S. tax on foreign earnings (subject to certain important exceptions), immediate deductions for certain new investments instead of deductions for depreciation expense over time, and modifying or repealing many business deductions and credits (including changes to the orphan drug tax credit and changes to the deductibility of research and experimental expenditures that will be effective in the future). Notwithstanding the reduction in the corporate income tax rate, the overall impact of the new federal tax law is uncertain, including to what extent various states will conform to the newly enacted federal tax law.

 

The Company has not recorded the necessary provisional adjustments in the financial statements in accordance with its current understanding of the TCJA and guidance currently available as of this filing. But is reviewing the TCJA’s potential ramifications.

 

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of the Company’s deferred tax assets as of December 31, 2017, and 2016 are summarized below.

 

In assessing the potential realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the Company attaining future taxable income during the periods in which those temporary differences become deductible. As of December 31, 2017, and 2016, management determined it is More likely than not that the Deferred Tax Assets will not be utilized, since a loss Company to date and no evidence of income in the past. 

 

No federal tax provision has been provided for the years ended December 31, 2017, and 2016 due to the losses incurred during such periods. Reconciled below is the difference between the income tax rate computed by applying the U.S. federal statutory & estimated State tax rate and the effective tax rate for the years ended December 31, 2017, and 2016.

 

   2017   2016 
Net operating loss carryforward  $(2,029,437)  $(671,362)
Stock based compensation   40,248    3,931 
Fair value of options   195,873    281 
Total deferred tax assets   (1,793,316)   (667,150)
Valuation allowance  $1,793,316   $667,150 
Net deferred tax asset   -    - 

 

   2017   2016 
U.S federal statutory income tax   -34.00%   -34.00%
State tax, net of federal tax benefit   -5.80%   -5.80%
Stock based compensation   0.00%   0.00%
Change in valuation allowance   39.80%   39.80%
Effective tax rate   0.00%   0.00%

 

At December 31, 2017 and 2016, the Company has available net operating loss carryforwards for federal and state income tax purposes of approximately $21,793,316 and $667,150, respectively, which, if not utilized earlier, expire through 2037.

 

Utilization of net operating loss carryforwards may be subject to substantial annual limitations due to the “change in ownership” provisions of the Internal Revenue Code Sections 382 and 383. The annual limitation may result in the expiration of substantial net operating loss carryforwards before utilization. The Company has not calculated its IRC Section 382 and 383 change of ownership to date, within the meaning of Internal Revenue Code Section 382 and 383, which would limited the use of net operating losses or render such worthless.

 

F-30
 

 

Note 13 – Subsequent Events

 

Completion of two non-operated exploratory wells

 

In Q2 2018, the two non-operated exploratory wells in which the Company has a 21.62% working interest and 17.1% net revenue interest were completed, and the costs shown as “construction in progress” will be reclassified to oil and gas properties subject to amortization in the second quarter of 2018. See Note 4 – Property and Equipment.

 

Extension of Debt Maturity

 

13.5% unsecured note payable due September 8, 2017

 

On February 28, 2018, Profit Well and the Company agreed to extend the maturity date of the debenture to June 30, 2018, and as consideration for the extension, the Company agreed to compensate Profit Well with 200,000 shares of restricted common stock. In addition, the parties agreed that if payment of said principal and interest due and payable is made late, then a penalty payment of $100,000 shall become due and payable to Profit Well by the Company. The Company and Profit Well are in ongoing discussions to extend the term of this Note and the Company believes it will either extend, rework or repay the obligation to the satisfaction of Profit Well. As partial consideration for the deferral, the Company will offer Profit Well 100,000 shares of its restricted common stock.

 

0% unsecured note payable due January 2, 2018

 

Since January 23, 2018, the Company and the investor have been in ongoing discussions to extend the term of this Note. On March 28, 2018, the investor acknowledged that the Company is not in default regarding this Note and reaffirmed its belief that the Company will either extend the Note’s due date or repay its obligation on terms that are mutually satisfactory. The Company and this investor are in ongoing discussions to extend the term of this Note and the Company believes it will either extend, rework or repay the obligation to the satisfaction of the investor.

 

8% convertible note payable due August 16, 2018

 

In June 2018, the Company made a principal payment in the amount of $100,000. Furthermore, the Company agreed to pay the remaining balance of $229,025 on or before thirty-five (35) days from June 5th, 2018. The Note may be converted if the Note Balance is not paid on or before thirty-five (35) days from June 5th 2018. FirstFire agreed that the Note is not in default. As consideration for agreeing to provide the Company with this extension of time to pay, the Company issued the investor 150,000 shares of restricted common stock, valued at $18,000.

 

Extension of Debt Maturity – Related Party

 

13.25% unsecured note payable due May 5, 2017

 

On February 28, 2018, Berwin and the Company agreed to extend the maturity date of the debenture to June 30, 2018, and as consideration for the extension, the Company agreed to compensate Berwin with 250,000 shares of restricted common stock. In addition, the parties agreed that if payment of said principal and interest due and payable is made late, then a penalty payment of $125,000 shall become due and payable to Berwin by the Company. The Company and Berwin are in ongoing discussions to extend the term of this Note and the Company believes it will either extend, rework or repay the obligation to the satisfaction of Berwin. As partial consideration for the deferral, the Company will offer Berwin 100,000 shares of its restricted common stock.

 

Contingent Liabilities – Legal Proceedings

 

Conquest Well Servicing, LLC vs. Foothills Exploration Operating, Inc. (Case No. 179800421 8th Judicial District Court in and for Uintah County, State of Utah)

 

An order requesting company asset inquiry was issued on February 20, 2018. As of July 26, 2018, no further action has been taken.

 

Note 14 - Supplemental Oil and Gas Reserve Information (Unaudited) 

 

The Company’s oil and gas properties and proved reserves are located in the United States.

 

Results of operations from oil and gas producing activities

 

The results of operations from the Company’s oil and gas producing activities for the years ended December 31, 2017 and 2016 are summarized below:

 

   December 31, 
   2017   2016 
Net revenues from production:          
Sales of oil and gas production to third parties  $155,161   $ 
           
Production costs:          
Oil and gas lease operating expense   (252,753)    
Depletion, depreciation, amortization, accretion, and impairment expense   (1,525,784)    
Income tax expense         
Results of operations  $(1,623,376)  $ 

 

F-31
 

 

Results of operations for producing activities comprise all activities associated with our exploration for and production of oil and gas. Net revenues from production include only the revenues from the production and sale of oil, natural gas, natural gas liquids, and residue gas. Production costs are those incurred to operate and maintain wells and related equipment and facilities used in oil and gas operations. Income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion, and amortization allowances, after giving effect to permanent differences. The results of operations exclude general office overhead, and interest expense attributable to oil and gas activities.

 

Capitalized costs

 

Capitalized costs and accumulated depletion, depreciation, and amortization relating to the Company’s oil and gas producing activities as of December 31, 2017 and 2016 are summarized below:

 

    2017     2016  
Unproved properties not being amortized   $ 2,509,274     $ 1,181,421  
                 
Proved properties subject to amortization   $ 10,762,380       10,352,014  
Accumulated depreciation, depletion, and amortization   $ (18,016 )        
Net capitalized costs   $ 13,253,638     $ 11,533,435  

 

Costs incurred in oil and gas property acquisition, exploration, and development activities

 

The following table summarizes the Company’s costs incurred in property acquisition, exploration and development activities for the year ended December 31, 2017:

 

   2017 
Proved acreage  $18,653 
Producing assets   580,158 
Incomplete construction   1,501,369 
Exploration costs   (148,533)
Development costs    
Net capitalized costs  $1,951,647 

 

Estimated quantities of proved reserves

 

The supplemental unaudited presentation of proved reserve quantities and related standardized measure of discounted future net cash flows provides estimates only and does not purport to reflect realizable values or fair market values of the Company’s reserves. The Company emphasizes that reserves estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, significant changes to these estimates can be expected as future information becomes available. All of the Company’s reserves are located in the United States.

 

Proved reserves are those estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment, and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure is required to rend them capable of production.

 

F-32
 

 

The standardized measure of discounted future net cash flows is computed by applying the average first day of the month price of oil and gas during the 12 month period before the end of the year (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves, less the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows.

 

The reserves estimates set forth below were prepared by a third party engineering firm using reserves definitions and pricing requirements prescribed by the SEC. Chapman Petroleum Engineering Ltd. (“Chapman”) prepared our reserves report at January 1, 2018. Chapman is an independent consultant, does not own any interest in the Company’s properties, and is not engaged contingent upon the value of the Company’s properties. Chapman prepared reserves estimates under a discounted cash flow analysis of estimated future net revenue, applying knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods in properly using and applying reserves definitions. The data utilized were furnished to Chapman by the Company or obtained from public data sources. Chapman is a professional engineering firm specializing in the technical and financial evaluation of oil and gas assets.

 

Estimated quantities of oil and natural gas reserves 

 

The following table sets forth certain data pertaining to changes in reserves quantities of the proved, proved developed, and proved undeveloped reserves for the years ended December 31, 2017 and 2016.

 

    December 31,  
    Crude Oil     Natural Gas     Crude Oil     Natural Gas  
    (MSTB)     (MCF)     (MSTB)     (MCF)  
    2017     2017     2016     2016  
TOTAL PROVED RESERVES                                
Beginning of year     1,622       811              
Purchases of minerals in place                 1,622       811  
Sales of minerals in place                        
Extensions and discoveries     4,174       8,353              
Revisions of previous estimates     (1,620     (811            
Production     (2 )                  
End of period     4,174       8,353       1,622       811  
                                 
PROVED DEVELOPED RESERVES                                
Proved developed producing                        
Proved developed nonproducing                 193       97  
End of period     4,174       8,353       1,622       811  
Total proved undeveloped     4,174       8,353       1,429       714  

 

F-33
 

 

Standardized measure of discounted future net cash flows

 

As required by the Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to net proved reserves. The standardized measure includes costs for future dismantlement, abandonment, and rehabilitation obligations. The Company believes the standardized measure does not provide a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions, which represent discrete points in time and may cause significant variability in cash flows from year to year as prices change.

 

Net cash flows at December 31,   2017     2016  
             
Future cash inflows   $ 268,949,000     $ 74,093,600  
Future production costs     (103,926,000 )     (17,313,400 )
Future development costs     (48,000,000 )     (19,750,000 )
Future income tax expense     (23,275,919 )     (12,590,268 )
Future net cash flows     93,747,081       24,439,932  
10% annual discount for estimated timing of cash flow     (68,046,395 )     (14,908,800 )
Standard measure of discounted future net cash flows related to proved reserves   $ 25,700,686     $ 9,531,132  

 

Changes in standardized measure of discounted future net cash flows

 

The principal sources of changes in the standardized measure of the future net cash flows for the years ended December 31, 2017 and 2016 are:

 

   2017 
Balance, beginning of period  $9,531,132 
Sales and transfers of oil and gas produced during the period   97,592 
Sales of minerals in place    
Purchases of minerals in place    
Net change in sales price, net of production costs   (4,564,023)
Net changes due to extensions and discoveries   50,755,047 
Changes in estimated future development costs   (25,709,147)
Previously estimated development costs incurred during the period    
Net change due to revisions in quantity estimates   (16,007,121)
Other   11,284,522 
Accretion of discount   3,599,200 
Net change in income tax   (3,286,516)
Balance, end of period  $25,700,686 

 

ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

 

None.

 

ITEM 9A. Controls and Procedures.

 

Evaluation of Disclosure Controls and Procedures.

 

We are required to maintain “disclosure controls and procedures” as such term is defined in Rule 13a-15(e) under the Act. Based on their evaluation as of the end of the period covered by this Annual Report on Form 10-K/A, B.P. Allaire, who is both our Chief Executive Officer and our Interim Chief Financial Officer, has concluded that our disclosure controls and procedures were not effective to ensure that the information relating to our company, required to be disclosed in our Securities and Exchange Commission reports (i) is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and (ii) is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure as a result of material weaknesses in our internal control over financial reporting. Notwithstanding the existence of the material weaknesses discussed below, our management, including our CEO/CFO, has concluded that the consolidated financial statements included in this Annual Report on Form 10-K/A fairly present, in all material respects, our financial position, results of operations and cash flows for the periods presented in this Annual Report on Form 10-K/A in conformity with GAAP.

 

37
 

 

This annual report does not include an attestation report from our independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our independent registered public accounting firm pursuant to the Jumpstart Our Business Startups Act (the “JOBS Act”). Under the JOBS Act we are not required to comply with Section 404(b) because we are an “emerging growth company.”

 

Management’s Report on Internal Control over Financial Reporting.

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Act. Our internal control over financial reporting is 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. Our internal control over financial reporting includes those policies and procedures that:

 

  pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
     
  provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
     
  provide reasonable assurance regarding prevention or timely detection of unauthorized acquisitions, use or disposition of our assets that could have a material effect on the financial statements.

 

Because of the 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.

 

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2017. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013). Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of these controls. Based on this assessment, our management has concluded that as of December 31, 2017, our internal control over financial reporting was not effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles as a result of material weaknesses.

 

We have identified the following factors that have led management to determine that material weaknesses exist in our internal control over financial reporting as of December 31, 2017:

 

  1. We do not have written documentation of our internal control policies and procedures. Written documentation of key internal controls over financial reporting is a requirement of Section 404 of the Sarbanes-Oxley Act. Management evaluated the impact of our failure to have written documentation of our internal controls and procedures on our assessment of our disclosure controls and procedures and has concluded that the control deficiency that resulted represented a material weakness.
     
  2. We do not have sufficient segregation of duties within accounting functions, which is a basic internal control. Due to our size and nature, segregation of all conflicting duties may not always be possible and may not be economically feasible. However, to the extent possible, the initiation of transactions, the custody of assets and the recording of transactions should be performed by separate individuals. Management evaluated the impact of our failure to have segregation of duties on our assessment of our disclosure controls and procedures and has concluded that the control deficiency that resulted represented a material weakness.

 

38
 

 

These factors represent material weaknesses in our internal controls over financial reporting. Although we believe the possibility of errors in our financial statements is remote, and expect to continue to use a third party accountant to address shortfalls in staffing and to assist us with accounting and financial reporting responsibilities in an effort to mitigate the lack of segregation of duties, until such time as we hire a full time principal financial officer and expand our staff with qualified personnel, we expect to continue to report material weaknesses in our internal control over financial reporting.

 

Changes in Internal Control over Financial Reporting.

 

There have been no changes in our internal control over financial reporting during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

Inherent Limitations on Effectiveness of Controls.

 

The design of any system of control is based upon certain assumptions about the likelihood of future events. There can be no assurance that any design will succeed in achieving its stated objectives under all future events, no matter how remote, or that the degree of compliance with the policies or procedures may not deteriorate. Because of its inherent limitations, disclosure controls and procedures may not prevent or detect all misstatements. Accordingly, even effective disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.

 

ITEM 9B. Other Information.

 

None.

 

PART III

 

ITEM 10. Directors, Executive Officers and Corporate Governance.

 

Directors and Executive Officers

 

Our directors and executive officers, their ages, positions held, and duration of such, are as follows:

 

Name   Age   Title
Kevin J. Sylla   43   Executive Chairman and Director
B.P. Allaire   46   Chief Executive Officer, Interim Chief Financial Officer and Director
Christopher C. Jarvis   46   Executive Vice President of Finance and Director
Alex M. Hemb   54   Director

 

Business Experience

 

The following is a brief account of the education and business experience of each director and executive officer during at least the past five years, indicating each person’s principal occupation during the period, and the name and principal business of the organization by which he was employed.

 

Kevin J. Sylla – Executive Chairman and Director

 

Mr. Sylla was appointed Executive Chairman of the Company on May 26, 2017. He was also appointed Chief Executive Officer and director of Foothills Petroleum, Inc., in March 2017. Mr. Sylla has served as Managing Director of Tiger Energy Operating, LLC, Tiger Energy Partners International, LLC, and Tiger Energy Mineral Leasing, LLC, for the past five years and he will continue in those roles for the foreseeable future. Mr. Sylla played a key advisory role in the successful combination and integration of Tiger properties into Foothills Exploration. He has over 10 years of oil and gas industry experience with extensive knowledge in business development, mergers and acquisitions, and management of oil and gas field operations.

 

39
 

 

Mr. Sylla has participated extensively in the financing, acquisition and development of numerous domestic oil and gas properties. His acquisition experience has been focused on improving operating and financial efficiencies with underperforming assets resulting in enhanced value creation. Effective January 28, 2010 Mr. Sylla, without admitting or denying findings consented to a fine and to a suspension from association with any FINRA member from February 16, 2010 through February 15, 2011. This civil matter arose as a result of a customer loan to an entity partially owned by Mr. Sylla at a time when that activity was impermissible under NASD conduct rules then in effect. Mr. Sylla is the managing member of Wilshire Energy Partners, LLC, a principal shareholder of the Company and has provided consulting services to the Company since its formation. During his career, Mr. Sylla has drilled, reworked and overseen the management of hundreds of wells. Mr. Sylla completed the Petroleum Land Management Program at Texas Christian University and earned his Energy & Finance Management Certification from the University of Denver.

 

B. P. Allaire – Chief Executive Officer, Interim Chief Financial Officer and Director

 

Mr. Allaire has served as president, chief executive officer, interim chief financial officer and director of the Company since April 2016. He has also served as president, chief operating officer and interim chief financial officer of Foothills Petroleum, Inc., the Company’s principal operating subsidiary since its formation and organization in December 2015. Mr. Allaire has also served as manager of Foothills Exploration, LLC, an indirect subsidiary of the Company, since December 2015. From 2011 to 2015, Mr. Allaire was President and CEO of Veritas Energy Management, LLC, a marketing and management company engaged in the acquisition, development and management of on-shore oil and gas properties in the mid-continent and gulf-coast regions of the U.S. From 2007 to 2012, Mr. Allaire was Managing Partner of Versailles Capital Partners, LLC, a multi-disciplined business development and strategic advisory services firm, which incubated the business plan and helped secure funding for a wine industry rollup play called Global Distillers & Vintners Holdings, Inc. After Global Distillers became a portfolio company of Versailles, Mr. Allaire represented Versailles’ interest by serving as Vice Chairman and Chief Financial Officer of Global Distillers & Vintners from May 2008 to June 2010.

 

Mr. Allaire is an entrepreneurial management executive and seasoned business operator with over 25 years of domestic and international work experience across numerous functional roles spanning finance, sales, marketing, strategy, business development, mergers and acquisitions and operations management across various industry sectors. He is experienced in the integration of acquired companies into complex corporate entities with multiple wholly-owned subsidiaries. Mr. Allaire has served as an Officer and/or Director of numerous companies across several industries during his management career. They have included oil and gas partnerships, wine and spirit import and distribution enterprises, and a business development and strategic advisory services firm.

 

Mr. Allaire graduated with a B.S. in Management, A.S. in Finance & Investments, and A.S. in Advertising & Public Relations all from Johnson & Wales University in Providence, Rhode Island. He earned his M.B.A. from Harvard University’s Graduate School of Business.

 

Christopher C. Jarvis – Executive Vice President of Finance, and Director

 

Mr. Jarvis has been a director of the Company since April 2016 and was appointed Executive Vice President of Finance for the Company and Vice President of Risk Management for Foothills Petroleum, Inc. in March 2017. Mr. Jarvis has over 20 years of capital markets and investments experience covering the equity, commodity, and fixed-income markets. He engineered and executed energy risk management hedges for large multi-national companies and as a publishing analyst, he was ranked #1 by Bloomberg’s BARR analyst ranking system. Mr. Jarvis is a Certified Financial Analyst (CFA) and also a Certified Market Technician (CMT). He routinely appears on CNBC, Fox Business News, and Reuters. He is a contributor to major print media outlets including Reuters, Bloomberg and the Wall Street Journal as an oil and gas analyst.

 

40
 

 

Mr. Jarvis earned a B.A. in Arts History from University of Massachusetts and an M.B.A. from the University of Connecticut, with a concentration in Finance. He is a member of the CFA Institute and also the Market Technicians Association (MTA). He has been a member of the University of Connecticut Financial Accelerator Advisory Board for the last 10 years and previously served as the Vice President of the Autism Society of New Hampshire (2004-09).

 

Alex M. Hemb – Director

 

Mr. Hemb has served as a director of the Company since April 2016. Mr. Hemb has over 25 years’ experience as a Petroleum Engineer both onshore and offshore and has worked as a consulting petroleum engineer for the past 15 years. Mr. Hemb has broad international work experience as well having also worked in Norway, Canada, Belize, Germany, and Scotland in addition to the U.S. He engineered and developed technology for separating oil and water and commercialized this into a successful company providing oil/water separation services to the oil and gas industry.

 

Mr. Hemb is currently the Vice President of Engineering for Helmer Directional Drilling, where he has worked for the past 15 years. He spent nine years working across a variety of engineering, planning and sales roles with Baker Hughes both in the U.S. and internationally. He has a proven management track record, having performed a success turn-around of the Norwegian division of CETCO, returning the division to profitability by reducing losses, growing new business, right-sizing the company and hiring his replacement Managing Director to lead the division. Mr. Hemb has a B.S. and M.Sc. in Petroleum Engineering from Montana Tech, and holds numerous certifications from various oil and gas technical schools. He completed compulsory Military Training in Norway and served as a Military Police based at NATO’s Northern European HQ.

 

Board Leadership Structure and Role in Risk Oversight

 

Our board of directors is primarily responsible for overseeing our risk management processes. The board of directors receives and reviews periodic reports from management, auditors, legal counsel, and others, as considered appropriate regarding our company’s assessment of risks. The board of directors focuses on the most significant risks facing our Company and our Company’s general risk management strategy, and also ensures that risks undertaken by our Company are consistent with the board’s appetite for risk. While the board oversees our Company’s risk management, management is responsible for day-to-day risk management processes. We believe this division of responsibilities is the most effective approach for addressing the risks facing our Company and that our board leadership structure supports this approach. In May 2017, the board of directors appointed Kevin J. Sylla as the Company’s Executive Chairman and thereby adopted a policy to separate the positions of Chairman and Chief Executive Officer. Currently, Mr. Allaire serves as our president, chief executive officer and interim chief financial officer.

 

Terms of Office

 

Our directors are elected and hold office until his or her successor is elected and qualified, or until his or her earlier resignation or removal from office in accordance with our bylaws and the provisions of the Delaware General Corporation law. Our officers are appointed by our board of directors and serve at its pleasure.

 

Involvement in Certain Legal Proceedings

 

To our knowledge other than as described above, directors and executive officers of the Company have not been involved in any of the following events during the past ten years:

 

  1. any bankruptcy petition filed by or against such person or any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time;
     
  2. any conviction in a criminal proceeding or being subject to a pending criminal proceeding (excluding traffic violations and other minor offenses);
     
  3. being subject to any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining him from or otherwise limiting his involvement in any type of business, securities or banking activities or to be associated with any person practicing in banking or securities activities;

 

41
 

 

  4. being found by a court of competent jurisdiction in a civil action, the SEC or the Commodity Futures Trading Commission to have violated a Federal or state securities or commodities law, and the judgment has not been reversed, suspended, or vacated;
     
  5. being subject of, or a party to, any federal or state judicial or administrative order, judgment decree, or finding, not subsequently reversed, suspended or vacated, relating to an alleged violation of any Federal or state securities or commodities law or regulation, any law or regulation respecting financial institutions or insurance companies, or any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or
     
  6. being subject of or party to any sanction or order, not subsequently reversed, suspended, or vacated, of any self-regulatory organization, any registered entity or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.

 

Board Committees

 

The Board of Directors acts as the Audit Committee and has no separate committees. Our Board has not formulated any plan to establish an audit or compensation committee in the near future. We envision that the audit committee, should it be formed, will be primarily responsible for reviewing the services performed by our independent auditors and evaluating our accounting policies and systems of internal controls. We envision that the compensation committee, should it be formed, will be primarily responsible for reviewing and approving our salary and benefits policies and other compensation of our executive officers. Until these committees are established, these decisions will continue to be made by our Board of Directors.

 

Compliance with Section 16(a) of the Exchange Act.

 

Not applicable.

 

ITEM 11. Executive Compensation.

 

The following table sets forth all compensation paid in respect to our principal executive officer and principal financial officer for the years ended December 31, 2017, and 2016.

 

EXECUTIVE COMPENSATION

 

Position  Year   Salary
($)
   Bonus
($)
   Stock
Awards
($)
   Option
Awards
($)
   Non-equity
Incentive
Plan
Compensation ($)
   All Other
Compensation
($)
   Total
($)
 
Kevin J. Sylla   2017    203,600    -    -    557,058    -    -    760,658 
Executive Chairman   2016    -    -    -    -    -    -    - 
                                         
B.P. Allaire   2017    99,700    -    501    -    -    -    100,201 
Chief Executive Officer   2016    58,500    -    999    275    -    -    59,774 
                                         
Christopher Jarvis   2017    134,000    -    418    259,081    -    -    393,499 
EVP, Finance   2016    45,000    -    832    275    -    -    46,107 

 

 

42
 

 

Employment Offers

 

Appointment of Christopher Jarvis as Executive Vice President of Finance of Foothills Exploration, Inc. and Vice President of Risk Management of Foothills Petroleum, Inc.

 

On March 3, 2017, the Company announced that it had appointed Christopher Jarvis, a current member of the board of directors of the Company, as Executive Vice President of Finance of the Company and Vice President of Risk Management of Foothills Petroleum, Inc. (“FPI”), a wholly owned subsidiary of the Company. This appointment commenced March 1, 2017. There is no family relationship between Mr. Jarvis and the Company or FPI’s officers and directors. Other than the employment terms described below, Mr. Jarvis and the Company or FPI have not entered into any transaction, nor is any transaction proposed, which would require disclosure pursuant to Item 404(a) of Regulation S-K.

 

Mr. Jarvis received an annual salary of $240,000 and is entitled to annual increases of 3% per annum. Mr. Jarvis is also entitled to receive bonuses that will be based on performance standards which will be established by the Company. Mr. Jarvis received a $10,000 signing bonus on the effective date of employment and options to purchase 400,000 shares of Company’s common stock. The options have an exercise price of $2.02 per share, a five-year term and will vest quarterly over 24-month term of employment commencing June 1, 2017, but subject to no exercise for 12 months and subject further to all unvested options being accelerated upon any change of control event. Mr. Jarvis will also receive a car allowance in the amount of $800 per month and cell phone allowance in the amount of $100 per month once the Company’s net total oil and gas production reaches 750 barrels of oil equivalent per day for at least 90 consecutive days, including production from all wholly-owned subsidiaries and portion of production which may be beneficially allocated to the Company from sister companies in which the Company owns at least 50% in interest. Upon approval of the Company’s Board of Directors, Mr. Jarvis may become eligible to participate in the Company’s equity incentive plan, should one be established.

 

Mr. Jarvis’s employment with the Company is at will and may be terminated for or without cause. If Mr. Jarvis is terminated without cause following the 90-day probationary period, he may receive a pro-rated bonus through the balance of the calendar year in which termination occurred. Upon acceptance of position as fulltime executive of the Company and FPI, the Executive Director Agreement dated between Mr. Jarvis and the Company will terminate, however Mr. Jarvis will retain restricted stock units granted to him pursuant to the foregoing agreement subject to the vesting terms described therein.

 

Appointment of Kevin J. Sylla as Director and Chief Executive Officer of Foothills Petroleum, Inc.

 

On March 3, 2017 the Company announced that it had appointed Kevin J. Sylla, as Director and Chief Executive Officer of FPI. Mr. Sylla will also continue serving as manager of the Company’s indirect subsidiaries, Tiger Energy Operating LLC (“TEO”), Tiger Energy Partners International LLC (“TEPI”), and Tiger Energy Mineral Leasing LLC (“TEML”). This appointment commenced March 1, 2017. There is no family relationship between Mr. Sylla and the Company or FPI’s officers and directors. Other than the employment terms described below, Mr. Sylla and the Company or FPI have not entered into any transaction, nor is any transaction proposed, which would require disclosure pursuant to Item 404(a) of Regulation S-K.

 

Mr. Sylla has an annual salary of $360,000 with annual increases of 3% per annum upon successful completion of a 90-day probationary period. Mr. Sylla will also receive bonuses that will be based on performance standards that will be established by the Company. Mr. Sylla received a $10,000 signing bonus on the effective date of employment and an option to purchase 1.2 million shares of Company’s common stock. The options shall have an exercise price of $2.02 per share, a seven-year term and will vest quarterly over a 36 months term of employment commencing June 1, 2017, but subject to no exercise for 12 months and subject further to all unvested options being accelerated upon any change of control event. Mr. Sylla will also receive a car allowance in the amount of $800 per month and cell phone allowance in the amount of $100 per month once the Company’s net total oil and gas production reaches 750 barrels of oil equivalent per day for at least 90 consecutive days, including production from all wholly-owned subsidiaries and portion of production which may be beneficially allocated to the Company from sister companies in which the Company owns at least fifty percent 50% in interest. Upon approval of the Company’s Board of Directors, Mr. Sylla may become eligible to participate in the Company’s equity incentive plan, should one be established.

 

Mr. Sylla’s employment with the Company is at will and may be terminated for or without cause. If Mr. Sylla is terminated without cause following the 90-day probationary period, he may receive pro-rated bonus through the balance of the calendar year in which termination occurred.

 

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Potential Payments upon Termination or Change-in-Control

 

SEC regulations state that we must disclose information regarding agreements, plans or arrangements that provide for payments or benefits to our executive officers in connection with any termination of employment or change in control of our company. We currently have no employment agreements nor any compensatory plans or arrangements with any of our executive officers that may result from the resignation, retirement or any other termination of any of our executive officers, from a change-in-control, or from a change in any executive officer’s responsibilities following a change-in-control.

 

Outstanding Equity Awards at Fiscal Year-End

 

The following table sets forth outstanding equity awards to our named executive officers as of December 31, 2017.

 

   Option and Restricted Stock Awards 
   Number of securities underlying   Number of securities underlying   Equity incentive plan awards: number of securities underlying         
   unexercised   unexercised   unexercised   Option     
   options   options   unearned   exercise   Option 
   (#)   (#)   options   price   expiration 
Name  Exercisable    Unexercisable    (#)    (US$)    date 
Kevin J. Sylla (1)   -    1,200,000    -   $1.99    2/27/24 
B.P. Allaire (2)   -    150,000    -   $      2.00-$4.00    5/19/26 
Christopher Jarvis (2)(3)   -    550,000    -   $      1.99-$4.00    5/19/26 
Alex Hemb (2)   -    150,000    -   $      2.00-$4.00    5/19/26 

 

(1) On February 27, 2017, 1,200,000 options were granted to Kevin J. Sylla having a 7-year term, vesting quarterly over 3 years, but subject to no exercise for 12 months and subject further to all unvested options being accelerated upon any change of control event. The strike price for the options was set at 110% of the closing bid price on the date that employment commenced. On March 1, 2017, the date employment commenced, the closing bid price of the Company’s common stock was $1.84 per share, which makes the strike price of these options $2.02 per share.
   
(2) On May 19, 2016, 150,000 options were granted to B.P. Allaire, Christopher Jarvis and Alex Hemb individually, having a 5-year term, for (i) 50,000 common shares at a strike price of $2 per share, vesting when the Company achieves and maintains a total average daily production level of 100 barrels of oil equivalent per day (“BOE/D”) for at least 30 days, (ii) 50,000 common shares at a strike price of $3 per share, vesting when the Company achieves and maintains a total average daily production level of 200 BOE/D for at least 60 days, and (iii) 50,000 common shares at a strike price of $4 per share, vesting when the Company achieves and maintains a total average daily production level of 500 BOE/D for at least 90 days.
   
(3) On February 27, 2017, 400,000 options were granted to Christopher Jarvis having a 5-year term, vesting quarterly over the term of employment commencing with the first quarter following the 90-day probationary period but subject to no exercise for 12 months and subject further to all unvested options being accelerated upon any change of control event. The strike price for the options was set at 110% of the closing bid price on the date that employment commenced. On March 1, 2017, the date employment commenced, the closing bid price of the Company’s common stock was $1.84 per share, which makes the strike price of these options $2.02 per share.

 

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Director Compensation

 

The following table sets forth director compensation for the fiscal year ended December 31, 2017 (excluding compensation to the Company’s executive officers set forth in the summary compensation table above) paid by the Company.

 

    Fees Earned or Paid in Cash    Stock Awards    Option Awards    Non-Equity     Incentive Plan Compensation    Nonqualified Deferred Compensation Earnings    All Other Compensation    Total 
Name   ($)    ($)    ($)    ($)    ($)    ($)    ($) 
Alex Hemb       -    -    -    -    -    -   $- 
Christopher Jarvis   -    -    -    -    -    -   $- 
Kevin J. Sylla     -    -    -    -    -    -   $- 

 

Risk Management

 

We do not believe risks arising from our compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us.

 

Indemnification

 

Under our Bylaws, we may indemnify an officer or director who is made a party to any proceeding, including a lawsuit, because of his position, if he acted in good faith and in a manner he or she reasonably believed to be in our best interest. We may advance expenses incurred in defending a proceeding. To the extent that the officer or director is successful on the merits in a proceeding as to which he is to be indemnified, we must indemnify him against all expenses incurred, including attorney’s fees. With respect to a derivative action, indemnity may be made only for expenses actually and reasonably incurred in defending the proceeding, and if the officer or director is judged liable, only by a court order. The indemnification is intended to be to the fullest extent permitted by the laws of the State of Delaware.

 

Regarding indemnification for liabilities arising under the Securities Act of 1933, which may be permitted to directors or officers under Delaware law, we are informed that, in the opinion of the Securities and Exchange Commission, indemnification is against public policy, as expressed in the Act and is, therefore, unenforceable.

 

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

 

The following table sets forth certain information concerning the number of shares of our common stock beneficially owned based on June __1, 2018 issued and outstanding shares of common stock filing as of the filing of this Annual Report on Form 10-K/A by: (i) each of our directors; (ii) each of our named executive officers; and (iii) each person or group known by us to beneficially own more than 5% of our outstanding shares of common stock.

 

Beneficial ownership is determined in accordance with SEC rules and generally includes voting or investment power with respect to securities. Other than as described in the notes to the table, we believe that all persons named in the table have sole voting and investment power with respect to shares beneficially owned by them. All share ownership figures include shares issuable upon exercise of options or warrants exercisable within 60 days of the date of this filing of this Annual Report on Form 10-K/A, which are deemed outstanding and beneficially owned by such person for purposes of computing his or her percentage ownership, but not for purposes of computing the percentage ownership of any other person. Unless otherwise indicated below, beneficial ownership is calculated based on the shares of common stock issued and outstanding stock as of the date of the filing of this Annual Report on Form 10-K/A.

 

Name and address  Shares of
Common Stock
   Percentage
of Common
Stock
 
Directors and Officers (1):          
Kevin J. Sylla   2,005,000    13.5%
B.P. Allaire   150,000    1.0%
Christopher Jarvis   125,000    0.8%
Alex Hemb   125,000    0.8 
All Officers and Directors as a Group (5 persons)   2,405,000    17.3%
           
5% or Greater Beneficial Owners          
Wilshire Energy Partners, LLC (2)   4,800,752    20.1%
Berwin Trading Limited (3)   3,107,519    20.9%
Total Belief Limited (4)   2,083,334    14.0%
Lan Fang Ouyang (5)   1,503,759    10.1%

 

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  1. The address for each of the officer and directors is 633 17th Street, Suite 1700, Denver, Colorado, 80202.
  2. The address for Wilshire Energy Partners, LLC, is 11111 Santa Monica Blvd, Suite 1700, Los Angeles. CA 90025
  3. The address for Berwin Trading Limited is Flat B, 28/F, Block 9, Larvotto, 8 Praya Road, Ap Lei Chau, Hong Kong.
  4. The address for Total Belief Limited is Room 1402, 14/F, New World Tower I, 16-18 Queen’s Road Central, Hong Kong.
  5. The address for Lan Fang Ouyang is Room 607, Yin Zuo Ge, Xu Fei Hua Da, Yaun, 2057 Cui Zhu Road, Luo Hu, Shenzhen, Guangdong 51800, China.

 

ITEM 13. Certain Relationships and Related Transactions, and Director Independence.

 

Certain Relationships and Related Transactions

 

Berwin Trading Limited

 

Effective January 5, 2017, Foothills borrowed $1,250,000 from Berwin Trading Limited, a British Virgin Islands limited liability company. The Company executed a promissory note, titled as a Debenture, with the lender dated as of December 30, 2016, with proceeds being received by the Company on January 5, 2017. This loan is unsecured, bears interest at 9% per year and is due and payable in 120 days from the receipt of funds. If any amount payable is not paid when due, any such overdue amount shall bear interest at the default rate of 11% from the date of such non-payment until such amount is paid in full. The Company used net proceeds of this loan to satisfy certain obligations under a Purchase and Sale Agreement with Total Belief Limited, dated December 30, 2016, for general working capital and to support certain target drilling activities. On May 4, 2017, the Company and Berwin agreed to extend the maturity date of the debenture to June 20, 2017, in return for an annual interest rate increase from 9% to 13.5% per annum for the life of the debenture. On November 3, 2017, Berwin agreed to defer repayment of this note to a later date and acknowledged that the Company is not in default regarding this Debenture. Berwin also reaffirmed its belief that the Company will either extend or repay the obligation to their satisfaction. As partial consideration for the deferment, the Company issued Berwin 100,000 shares of its restricted common stock, valued at $48,000. The issuance of the shares in exchange for the maturity extension was treated as a modification of existing debt pursuant to the guidance of ASC 470-50 “Debt – Modifications and Extinguishments” (“ASC 470-50”). On February 28, 2018, Berwin and the Company agreed to extend the maturity date of the debenture to June 30, 2018, and as consideration for the extension, the Company agreed to compensate Berwin with 250,000 shares of restricted common stock. In addition, the parties agreed that if payment of said principal and interest due and payable is made late, then a penalty payment of $125,000 shall become due and payable to Berwin by the Company. As of December 31, 2017, the balance of accrued interest was $166,438. During the year ended December 31, 2017, the Company recorded interest expense in the amount of $166,438.

 

Alternus Capital Holdings Ltd.

 

Through Wilshire’s assistance Foothills Petroleum entered into two agreements with Alternus whereby Foothills obtained a total of $1,000,000 of financing in the form of convertible notes that upon completion of the Share Exchange were converted, at $0.665 per share, into 1,503,759 shares of common stock of the Company. See notes 2, 9 and 10 for additional discussion of the transactions with Alternus.

 

The foregoing descriptions of the BDSA and of the agreements with Alternus are summaries only that outline the principal terms of those documents and those descriptions are qualified in their entirety by reference to those agreements which are attached as exhibits to our Form 8-K filed with the Securities and Exchange Commission on June 10, 2016 and incorporated herein thereby.

 

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Review, Approval or Ratification of Transactions with Related Persons

 

As we have not adopted a Code of Ethics, we rely on our board to review related party transactions on an ongoing basis to prevent conflicts of interest. Our board reviews a transaction in light of the affiliations of the director, officer or employee and the affiliations of such person’s immediate family. Transactions are presented to our board for approval before they are entered into or, if this is not possible, for ratification after the transaction has occurred. If our board finds that a conflict of interest exists, then it will determine the appropriate remedial action, if any. Our board approves or ratifies a transaction if it determines that the transaction is consistent with our best interests.

 

Family Relationships

 

There are no family relationships between any of our former directors or executive officers and new directors or new executive officers.

 

Director Independence

 

We do not currently have any independent directors.

 

ITEM 14. Principal Accounting Fees and Services.

 

Audit Fees

 

The aggregate fees billed for the two most recently completed fiscal years ended December 31, 2017, and December 31, 2016, for professional services rendered by RBSM, LLP, for the audit of our annual consolidated financial statements, quarterly reviews of our interim, unaudited consolidated financial statements and services normally provided by the independent accountant in connection with statutory and regulatory filings or engagements for these fiscal periods were as follows:

 

   Year Ended
December 31, 2017
   Year Ended
December 31, 2016
 
Audit Fees and Audit Related Fees  $31,000   $42,000 
Tax Fees   2,650    - 
All Other Fees   -    - 
Total  $33,650   $42,000 

 

In the above table, “audit fees” are fees billed by our company’s external auditor for services provided in auditing our company’s annual financial statements for the subject year. “Audit-related fees” are fees not included in audit fees that are billed by the auditor for assurance and related services that are reasonably related to the performance of the audit review of our company’s financial statements. “Tax fees” are fees billed by the auditor for professional services rendered for tax compliance, tax advice and tax planning. “All other fees” are fees billed by the auditor for products and services not included in the foregoing categories.

 

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PART IV

 

ITEM 15. Exhibits, Financial Statement Schedules.

 

Exhibit No.   Description
     
2.1   Share Exchange Agreement between Registrant and Foothills Petroleum, Inc., dated May 27, 2016 (Incorporated by reference from the Current Report on Form 8-K filed with the SEC on June 10, 2016)
     
3.1   Certificate of Incorporation of the registrant as amended (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on August 9, 2016)
     
3.2   Bylaws of the Company (incorporated by reference to the Company’s Registration Statement on Form S-1 filed with the SEC on August 27, 2013)
     
10.1   Form of Executive Employment Agreement between registrant and Ritchie Lanclos dated August 15, 2016 (Incorporated by reference from the Current Report on Form 8-K filed with the SEC on August 19, 2016)
     
10.2   Form of Executive Employment Agreement between registrant and Eleazar Ovalle dated August 15, 2016 (Incorporated by reference from the Current Report on Form 8-K filed with the SEC on August 19, 2016)
     
10.3   Services Agreement between registrant and Wilshire Energy Partners dated August 15, 2016 (Incorporated by reference from the Current Report on Form 8-K filed with the SEC on August 19, 2016)
     
10.4   Securities Purchase Agreement between Registrant and Alternus Capital Holdings Ltd. dated December 23, 2015**
     
10.5   Securities Purchase Agreement between Registrant and Alternus Capital Holdings Ltd. dated April 5, 2016**
     
10.6   Securities Purchase Agreement between Registrant and Berwin Trading Limited dated June 30, 2016 (Incorporated by reference from the Current Report on Form 8-K filed with the SEC on July 7, 2016)
     
10.7   Form of Convertible Promissory Note**
     
10.8   Form of Wilshire Warrant**
     
10.9   Business Development Services Agreement with Wilshire Energy Partners LLC and Aegis International LLC**
     
10.10   Executive Director Agreement between Foothills Petroleum, Inc. and Alex M. Hemb dated March 24, 2016**
     
10.11   Executive Director Agreement between Foothills Petroleum, Inc. and Christopher Jarvis dated March 24, 2016**
     
10.12   Form of Stock Purchase Agreement, dated as of May 2, 2016, between Shawn Clark, Christopher J. Dunkel, Glenn Petersen, Dena M. Womack, Tysen J. Kamin and Foothills Petroleum, Inc. (Incorporated by reference from the Current Report on Form 8-K filed with the SEC on May 6, 2016)
     
10.13   Participation Agreement between registrant and Magna Operating, LLC (Incorporated by reference from the Current Report on Form 8-K filed with the SEC on December 16, 2016)

 

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10.14   Purchase and Sale Agreement between Total Belief Limited and Foothills Exploration Operating, Inc.***
     
10.15   Form of Promissory Note issued to Total Belief Limited by registrant***
     
10.16   Form of Note Transfer and Assumption Agreement***
     
10.17   Purchase and Sale Agreement between Green Stone Capital Partners Limited and Foothills Exploration Operating, Inc.***
     
10.18   Debenture - Berwin Trading Limited (Incorporated by reference from the Current Report on Form 8-K filed with the SEC on January 11, 2017)
     
10.19   Debenture - Full Wealth Investment Hong Kong Limited (Incorporated by reference from the Current Report on Form 8-K filed with the SEC on January 11, 2017)
     
10.20   Offer Letter between registrant and Christopher Jarvis (Incorporated by reference from the Current Report on Form 8-K filed with the SEC on March 6, 2017)
     
10.21   Offer Letter between registrant and Kevin J. Sylla (Incorporated by reference from the Current Report on Form 8-K filed with the SEC on March 6, 2017)
     
21.1   Subsidiaries and indirect subsidiaries of Registrant
     
31.1*   Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
     
31.2*   Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
     
32.1*   Certification of Chief Executive Officer pursuant to Section 906 Certifications under Sarbanes-Oxley Act of 2002
     
101.INS*   XBRL Instance Document
     
101.SCH*   XBRL Taxonomy Extension Schema
     
101.CAL*   XBRL Taxonomy Extension Calculation Linkbase
     
101.DEF*   XBRL Taxonomy Extension Definition Linkbase
     
101.LAB*   XBRL Taxonomy Extension Label Linkbase
     
101.PRE*   XBRL Taxonomy Extension Presentation Linkbase

 

* Filed herewith.
** Incorporated by reference to the registrant’s 8-K filed with the Securities and Exchange Commission on June 10, 2016
*** Incorporated by reference to the registrant’s 8-K filed with the Securities and Exchange Commission on January 6, 2017

 

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SIGNATURES

 

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

 

  FOOTHILLS EXPLORATION, INC.
     
Dated: August 06, 2018 By: /s/ B. P. Allaire
  Name: B. P. Allaire
  Title: Chief Executive Officer and Interim Chief Financial Officer (Principal Executive Officer and Principal Financial and Accounting Officer)

 

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

 

Signature   Title(s)   Date
         
/s/ B. P. Allaire   Chief Executive Officer and Interim Chief Financial Officer   August 06, 2018
B. P. Allaire   (Principal Executive Officer and Principal Financial and Accounting Officer)    
         
/s/ Alex M. Hemb   Director   August 06, 2018
Alex M. Hemb        
         
/s/ Christopher C. Jarvis   Executive Vice President of Finance and Director   August 06, 2018
Christopher C. Jarvis        

 

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