FOOTHILLS EXPLORATION, INC. - Annual Report: 2018 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2018

OR

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

Commission file number 333-190836

FOOTHILLS EXPLORATION, INC.

(Exact name of registrant as specified in its charter)

(424) 901-6655

(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:

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.

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, 2018, 4,514,022 shares of common stock were held by non-affiliates and had an aggregate value of $857,664 based on the average closing bid and ask of $0.19 per share as reported by the OTCQB market.

As of April 12, 2019, there were 23,610,738 shares of common stock outstanding.

TABLE OF CONTENTS

PART I

ITEMS 1 and 2. Business and Properties.

Cautionary Statement Regarding Forward Looking Statements

This Annual Report on Form 10-K, contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended, that involve assumptions, and describe our future plans, strategies, and expectations. Such statements are generally identifiable by use of the words “may,” “will,” “should,” “expect,” “anticipate,” “estimate,” “believe,” “intend,” or “project,” “plan,” “aim”, or the negative of these words or other variations on these words or comparable terminology. Although we believe the expectations reflected in such forward-looking statements are reasonable, such expectations may not occur. These forward-looking statements are made subject to certain risks and uncertainties that could cause actual results to differ materially from those stated. Risks and uncertainties that could cause or contribute to such differences include, without limitation, those discussed in the section entitled “Risk Factors” included in this report and those factors outlined below:

Any of these factors and other factors contained in this report could cause our actual results to differ materially from the results implied by these or any other forward-looking statements made by us or on our behalf. Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and involve a variety of risks and uncertainties that are beyond our control. Our assumptions about future events may prove to be inaccurate. We caution you that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure you that those statements will be realized or the forward-looking events and circumstances will occur. All forward-looking statements speak only as of the date of this report.

Reserve engineering is a process of estimating underground accumulations of oil, natural gas and natural gas liquids that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and natural gas liquids that are ultimately recovered.

All forward-looking statements, expressed or implied, in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or any person acting on our behalf may issue.

We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as required by law. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

AVAILABLE INFORMATION

We file annual, quarterly and other reports and other information with the SEC. You can read these SEC filings and reports over the Internet at the SEC’s website at www.sec.gov or on our website at www.foothillspetro.com. You can also obtain copies of the documents at prescribed rates by writing to the Public Reference Section of the SEC at 100 F Street, NE, Washington, DC 20549 on official business days between the hours of 10:00 am and 3:00 pm. Please call the SEC at (800) SEC-0330 for further information on the operations of the public reference facilities. 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., 10940 Wilshire Blvd., 23^rd Floor, Los Angeles, California, 90024.

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.

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, the Company had minimal assets and recognized no revenues from operations and were accordingly classified as a shell company. On June 24, 2016, the Company filed an Amendment No. 1 to its Current Report on Form 8-K originally filed on June 10, 2016, indicating that they 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, the Company closed this office.

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”). The Company incurred $3,347,776 in total well costs for our working interest. Of those total costs, we incurred $1,479,406 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, and the wells were completed during Q2 2018. The Company recorded net revenues of $1,287,638 during 2018 from our working interest in both wells.

The Company’s principal office is located at 10940 Wilshire Blvd., 23rd Floor, Los Angeles, California 90024. Its telephone number is (424) 901-6655, and the website address is www.foothillspetro.com.

Overview

The Company is a development 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 under explored oil and gas assets and maximize those assets to create shareholder value.

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 4Q2018 saw significant divergence between oil and natural gas prices as fundamentals turned bearish for oil while a colder start to the winter boosted natural gas prices. West Texas Intermediate (WTI) prices fell by $27.92 from the previous quarter’s close of $73.25 to $45.33 closing price in 4Q2018, representing a quarter-over-quarter decrease of 38.1%. The flip side to oil’s story were natural gas prices as the Henry Hub natural gas price rose by $0.24/MMBtu from the previous quarter’s close of $3.01/MMBtu to $3.25/MMBtu closing price in 4Q2018, representing a quarter-over-quarter increase of 8.0%. Heading into 2019, we continue to be moderately bullish from current levels for both WTI oil prices and natural gas prices as strong global demand is partially offset by rising U.S. oil and natural gas production mainly coming from U.S. shale formations.

Oil: During the 4Q2018, there were two bearish catalysts that sank oil prices. The first catalyst was the U.S. sanctions placed on Iranian exports that went into effect on November 1st. Leading up to this deadline, global oil market participants had anticipated a million plus barrels a day of Iranian crude coming off the market, which left many in the space anticipating a supply tightening. Concurrently, President Trump reached out to Saudi Arabia prior to the November 1st start date for sanctions and requested the Kingdom to increase output in anticipation of Iranian crude oil coming off the market. As the calendar rolled into November, President Trump then issued waivers for 7 countries that were importing Iranian crude oil, which also happened to be the top 7 importers of Iranian oil including China. As a result, Iranian supplies did not come of the market as expected while Saudi Arabia was cranking up production that created a glut of oil supplies over the near-term and triggered the start of a massive sell-off. This, coupled with the second catalyst, or a fear of a global slowdown with China at the forefront in December, oil prices dropped over $30/b in a virtual straight line down over the last 6 weeks of 2018. Given this backdrop, Energy Information Administration (EIA) lowered its forecasts for Brent crude oil prices to an average $61 per barrel in 2019 and $65/b in 2020, down from the previous 2018 average of $71/b.

Natural Gas: Contrary to oil prices, natural gas prices surged as high of $4.69/MMBtu in December as cold weather in November and December sent heating demand soaring before closing out the year at $3.25/MMBtu. According to the EIA, U.S. natural gas exports by pipeline to Mexico and additional liquefied natural gas (LNG) export capacity that came online during the year resulted in the United States exporting more natural gas than it imported for the second year in a row. The Energy Information Administration (“EIA”), in its “Short-Term Energy Outlook” dated January 15, 2019 forecasts that Henry Hub natural gas spot prices will average $2.89/MMBtu in 2019 and $2.92/MMBtu in 2020. The Company believes that although dry gas production will continue to grow near 8% year-over-year in 2019, demand and exports should keep pace with production keeping natural gas prices relatively firm throughout the year with risks tilted to the upside.

Commodity Price Environment

The Company’s 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.

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 The Company’s 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 the date of this annual report filing. 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.

Employees

As of December 31, 2018, and 2017, the Company had 5 employees for each period, 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.

The Company’s 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. The Company is 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:

The Company seeks to acquire high quality oil and gas assets that have been underexplored and underdeveloped. The industry’s 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. The Company aims 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 of these objectives will create and maximize shareholder value in the long term.

Our Properties

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. The Company has decided to allow the leases on the Ladysmith and Paw Paw projects to expire based on the risk-reward profile, logistical challenges and the length of the primary term left on the leases.

Ladysmith Project

The Company owns 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. The Ladysmith project encountered right-of-way issues with the Oregon Trail, Mormon Trail and the Continental Divide. These historic landmarks in Wyoming made it very difficult to access the properties for exploration activities. The Company decided to let the primary term of the leases to expire.

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 primary term of the leases in the Paw Paw project and Unit have expired. Management is looking at implementing an oil and gas leasing program to continue its exploration activities in the area. The prospect has tremendous oil shows and was determined to be drilled on the wrong side of a seismic fault.   

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 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 recognized $10,089 in net revenues in 2018 from this operated working interest.

The Company intends to continue its Bureau of Indian Affairs (“BIA”) Administrative Appeal to assert its rights and interests in the oil and gas leases on the Ute Indian Uintah and Ouray Reservation. The Company 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 decided to move forward with the BIA Administrative Appeal instead of the revised Global Settlement Agreement in order to obtain a more attractive settlement price reflecting current commodity prices.

The Company owns a very small (under 1%) non-operated working interest in certain leases located in Duchesne County, Utah. The Company recognized approximately $7,192 in net revenues during 2018 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 Uinta Basin. The initial production from the two wells commenced in December 2017, and the wells were completed in April 2018. The company has realized natural gas sales, and associated hydrocarbon revenue from the two wells since December 2017. The Company recognized approximately $1,287,638 in net revenues during 2018 from this non-operated working interest.

Plan of Operations

The Company’s major initiative moving forward is to add natural gas weighted assets to its portfolio at attractive valuations, to accelerate cash flow generation, and improve the Company’s overall reserve inventory profile. Over the near-term the Company believes that it is well positioned to capitalize on the short- and long-term demand for natural gas. The International Energy Agency (“IEA”) reported global energy consumption grew by 2.3% in 2018, twice as fast as the average rate over the last ten years. The IEA also reported increased use of fossil fuels covered 70% of the global increase in energy demand with natural gas covering almost 45% of total demand growth.

According to the IEA, 2017 was a year of strong growth for natural gas, mainly driven by China. Global natural gas demand grew by 3%, the highest increase since 2010. China, where demand grew 15%, accounted for nearly a third of the global increase, driven by a determined policy effort to improve air quality through coal to gas boiler conversions in the residential and industrial sectors. The IEA goes on to say that strong global demand for natural gas has led to an unprecedented surge in LNG imports, placing China as the world’s second largest LNG importer after Japan.

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 natural gas-weighted projects. The IEA is forecasting the global natural gas market will pass the 4 trillion cubic meters (tcm) mark by 2022, with an expected average annual growth rate of 1.6% throughout the forecast period. Emerging Asian markets, led by China, account for more than half of the growth in global natural gas consumption to 2023. 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 $25 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.

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.

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.

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.

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 only recently began operations in the oil and gas industry. From its inception in December 2015 through December 31, 2018, 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.

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 $25 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 that 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:

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.

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, 2018, we have warrants issued and outstanding exercisable into 5,761,015 shares of our common stock, that are exercisable in whole or in part, at exercise prices which range from $0.20 per share to $3.00 per share. The weighted average exercise price is $0.82 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 rework 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.

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.

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. The 4Q2018 saw significant divergence between oil and natural gas prices as fundamentals turned bearish for oil while a colder start to the winter boosted natural gas prices. 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:

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. Although Commodity prices recovered moderately in 2018, 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:

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 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.

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, 2018, we have warrants issued and outstanding exercisable into 5,761,015 shares of our common stock at exercise prices which range from $0.20 per share to $3.00 per share. The weighted average exercise price is $0.82 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.

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 non-affiliate 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:

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.

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, 2018, our indirect subsidiaries were parties to the following contested matters:

Utah Wells

Graco Fishing & Rental Tools, Inc. vs. Tiger Energy Operating LLC (Case No. 160800005 8 ^th 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. TEO made its third payment of $32,793 on September 11, 2018, within the 10-day cure period provided in the settlement agreement. TEO also made its fourth payment of $32,793 on November 15, 2018. On January 25, 2019, the Plaintiff issued a Writ of Execution Notice. A Notice of Sheriff Sale was filed on February 1, 2019.  

Conquest Well Servicing, LLC vs. Foothills Exploration Operating, Inc. (Case No. 179800421 8^th 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 December 31, 2018, we recorded $12,115.31 of prejudgment interest expense. A hearing on contempt by FEOI for failure to appear and an answer as to assets was set for September 13, 2018. A stipulation was filed with the court to continue the hearing to October 22, 2018. FEOI inadvertently failed to appear at this hearing, resulting in a contempt of court citation being issued. Currently, FEOI is seeking to reschedule this hearing and intends to purge any contempt by compliance with the court’s order.

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

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, 2018, 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. There has been no change in the status of this matter since the Company’s last quarterly report filed with the SEC.

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, 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. No further action filed in this matter as of the date of this current annual report.

Performance Drilling Company, LLC vs. Foothills Petroleum Operating, Inc. (Case No. 2017-3916 DIV G 14^th 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. FPOI was cited to appear through its authorized representative, B.P. Allaire, in Open Court, on 27^th of July at 9:00 a.m. to be examined as a Judgment Debtor. FPOI was ordered to produce at the above time and place all the books, papers and other documents so requested in the petition. FPOI inadvertently failed to appear at this hearing and is currently seeking to reschedule this hearing.

Monster Rentals, LLC dba Deepwell Equipment Rentals vs. Foothills Petroleum Operating, Inc. (Case No. 2017-11013 DIV E – 15^th 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. On December 5, 2017, a default judgement was entered against FPOI in favor of Plaintiff in the amount of $53,943.53, plus attorneys’ fees of $3,483 and court costs and expenses in the amount of $476.84, plus judicial interest from the date of the judicial demand, until paid, and for all costs of these proceedings. No further action filed in this matter as of the date of this current annual report.

Canal Petroleum Products, Inc. vs. Foothills Petroleum Operating, Inc. (Case No. 2017-6574; DIV. C – 15^th 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.

Smith International, Inc. vs. Foothills Petroleum Operating, Inc. (Case No. 2017-004617; DIV. E – 14^th 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. On April 3, 2018, a final judgment was entered in favor of plaintiff. No further action filed in this matter as of the date of this current annual report.

M-I, L.L.C. d/b/a MI-SWACO vs. Foothills Petroleum Operating, Inc. (Case No. 2017-004616; DIV. G – 14^th 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. On April 3, 2018, a final judgment was entered in favor of plaintiff. No further action filed in this matter as of the date of this current annual report.

Schlumberger Technology Corporation vs. Foothills Petroleum Operating, Inc. (Case No. 2017-004618; DIV. E – 14^th 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. On April 3, 2018, a final judgment was entered in favor of plaintiff. No further action filed in this matter as of the date of this current annual report.

Zealous Energy Services, LLC vs. Foothills Petroleum Operating, Inc. (Docket No. 086708 Div. C 16^th Judicial District Court, Parish of St. Martin, Louisiana)

On September 28, 2018, the Court after reviewing the record of these proceedings, found the law and evidence supported Plaintiff’s demands and, without holding a hearing, ruled as follows: the Court ordered, adjudged and decreed that a money judgement be rendered in favor of Zealous Energy Services, LLC and against Foothills Petroleum Operating, Inc. in the full and true amount of $53,026.58, plus interest at the judicial interest rate of 5% per annum from January 24, 2018, the date of judicial demand, until finally paid, plus attorney’s fees of $1,260.00 and all cost. On March 1, 2019, a Motion to Examine Judgment Debtor was filed with the court.

633 17^th Street Operating Company LLC v. Foothills Exploration, Inc. (Case No. 2019CV30189, District Court, City and County of Denver, Colorado)

This case was filed on January 16, 2019, seeking unpaid leasehold obligations in the amount of $75,107 from the Defendant. No service has been affected. The Company is seeking to resolve this claim without further litigation.

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.

On April 10, 2019, the closing sales price reported for our common stock was $0.20 per share and as of that date, we had approximately 68 holders of record of our common stock, and 23,610,738 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.

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, 2018, has a working capital deficit at December 31, 2018, of $16,084,225, 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.

Results of Operations

Year ended December 31, 2018 compared to year ended December 31, 2017

Revenue

The following table summarizes our revenues from commodity sales during the years ended December 31, 2018 and 2017.

Operating Expenses

Operating expenses for the years ended December 31, 2018 and 2017, are set forth in the table below.

Operating expenses expressed in BOE for the years ended December 31, 2018 and 2017 are set forth in the table below:

Interest Expense

Interest expense for the years ended December 31, 2018 and 2017, was $2,247,011 and $930,923, respectively. The increase in interest expense is primarily attributed to additional compensation related to notes payable extensions during the year ended December 31, 2018.

Gain on Change in Derivative Value

(Gain) or loss on change in derivative value for the years ended December 31, 2018 and 2017, was $(50,619) and $169,423, respectively. The change in derivative value is primarily attributed to convertible notes.

Other Income

Other income for the years ended December 31, 2018 and 2017, was $45,407 and $5,727, 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, 2018.

Loss on extinguishment of debt

Loss on extinguishment of debt for the years ended December 31, 2018 and 2017, was $274,846 and $48,407, respectively. The increase in loss on extinguishment of debt is primarily attributed to common stock shares exchanged for the reduction of officers and directors’ accrued unpaid wages issued below market price.

Net Loss

As a result of the foregoing, our net loss for the year ended December 31, 2018, was $6,585,506 ($0.39) per basic and diluted common share. Our net loss for the year ended December 31, 2017, was $6,493,871 ($0.45) per basic and diluted common share.

Liquidity and Capital Resources

Overview

As of December 31, 2018, the Company had a working capital deficit of $16,084,225. As of December 31, 2017, the Company had a working capital deficit of $12,784,813. The increase of $3,299,412, in the working capital deficit was attributable as follows:

Cash, Cash equivalents, restricted cash and Accounts Receivable

As of December 31, 2018, the Company had cash of 1,139, compared to $555 at December 31, 2017.

As of December 31, 2018, the Company has restricted cash of $120,000, compared to $240,000 at December 31, 2017.

As of December 31, 2018, the Company had accounts receivable of $10,090, compared to $32,671 at December 31, 2017. This decrease in accounts receivable is due primarily to netting account receivable to accounts payable related to EOG Resources.

Liabilities

As of December 31, 2018, the outstanding balance of principal on notes and convertible notes payable net of debt discount was $9,060,233 a net increase of $412,864 from the outstanding balance of $8,647,369 as of December 31, 2017. This net increase was due to accrued interest on notes payable and amortization of debt discount.

Accounts payable and accrued expenses increased by $2,589,141 to $6,250,210 at December 31, 2018, from $3,661,069 at December 31, 2017. Included in accounts payable and accrued expenses are $687,770 and $362,714 as of the December 31, 2018 and December 31, 2017, respectively, primarily associated with accrued payable to management for unpaid compensation. These unpaid liabilities are aged from 1 days to 635 days, and the Company lacks the liquidity to pay them until it obtains additional capital.

Management knows that its existing cash on hand is insufficient to fund its current operations. 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 years ended December 31, 2018 and 2017, the Company used $373,416 and used $3,307,445 of cash in operating activities, respectively. Non-cash adjustments included $2,474,714 and $1,507,768 related to assets written off, $1,032,129 and $1,353,581 related to stock compensation expense, ($14,487) and $14,487 in deferred rent, $572,386 and $377,080 related to amortization of debt discount, $434,073 and $34,232 in depreciation, depletion, amortization and accretion, common stock and warrants issued for inducement of the note extension of $153,775 and $141,900, note payable issued for services of $0 and $120,629, fair value of down-round feature on warrants $0 and $59,801, financing expense on notes $0 and $71,345, interest of $459,923 and $0, extinguishment of debt of ($274,846) and ($48,407), change in derivative liabilities of ($50,619) and $169,423, and net changes in operating assets and liabilities of $1,425,043 and $615,413, respectively.

Investing Activities

During the years ended December 31, 2018 and 2017, respectively, $0 and $613,377 net cash was used in investing activities, a decrease of $613,377. This decrease is primarily due to lack of working capital.

Financing Activities

During the years ended December 31, 2018 and 2017, $254,000 and $3,120,000 net cash used and provided by financing activities, a decrease of $2,866,000. This change is primarily due to notes payable entered into during January 2017 and $320,000 repayment to convertible notes payable made during year ended December 31, 2018.

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.

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. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers” (“ASC Topic 606”). This standard provides a single set of guidelines for revenue recognition to be used across all industries and requires additional disclosures. The updated guidance introduces a five-step model to achieve its core principal of the entity recognizing revenue to depict the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Company adopted the updated guidance effective January 1, 2018 using the full retrospective method. The new standard did not have a material impact on its financial position and results of operations, as it did not change the manner or timing of recognizing revenue. Under ASC Topic 606, in order to recognize revenue, the Company is required to identify an approved contract with commitments to perform respective obligations, identify rights of each party in the transaction regarding goods to be transferred, identify the payment terms for the goods transferred, verify that the contract has commercial substance and verify that collection of substantially all consideration is probable. The adoption of ASC Topic 606 did not have an impact on the Company’s operations or cash flows.

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

The Company does not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on its 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 is not applicable.

ITEM 8. Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2018 and 2017 and the related consolidated statements of operations, stockholders’ (deficit) equity, and cash flows for each of the years in the two-year period ended December 31, 2018 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 consolidated financial position of the Company as of December 31, 2018 and 2017 and the consolidated results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2018 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 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 consolidated financial statements do n t 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 audit 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 provide a reasonable basis for our opinion.

FOOTHILLS EXPLORATION, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(AUDITED)

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

FOOTHILLS EXPLORATION, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(AUDITED)

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

FOOTHILLS EXPLORATION, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

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

FOOTHILLS EXPLORATION, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

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

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.

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, 2018, has a working capital deficit at December 31, 2018, of $16,084,225, 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.

Note 2 - 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 the years ended December 31, 2018 and 2017, the Company had restricted cash of $120,000 and $240,000, respectively. 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. During July and August 2018, $120,000 was released to the Company when we finished reclamation of two wells.

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.

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, 2018, the company accrued $31,924 of net revenue receivable from EOG Resources, Inc. (“EOG”), the operator of two wells in which the Company has a 21.62% 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, 2018, those costs were $1,868,370. 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.

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: