10-K 1 form10-k.htm

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

 

FORM 10-K

 

 

 

(Mark One)

 

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

 

For the Fiscal Year Ended December 31, 2020

 

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

 

For the transition period from                to               

 

Commission File No. 1-32955

 

 

 

HOUSTON AMERICAN ENERGY CORP.

(Exact name of registrant specified in its charter)

 

 

 

Delaware   76-0675953

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

801 Travis Street, Suite 1425, Houston, Texas 77002

(Address of principal executive offices)(Zip code)

 

Issuer’s telephone number, including area code: (713) 222-6966

 

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

 

Title of each class

  Trading Symbol  

Name of each exchange on which registered

Common Stock, $0.001 par value   HUSA   NYSE American

 

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

 

None

(Title of Class)

 

 

 

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

 

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

 

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

 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes [X] No [  ]

 

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

 

Large accelerated filer [  ] Accelerated filer [  ] Non-accelerated filer [X]
Smaller reporting company [X] Emerging growth company [  ]    

 

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. [  ]

 

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. [  ]

 

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

 

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant on June 30, 2020, based on the closing sales price of the registrant’s common stock on that date, was approximately $10.7 million. Shares of common stock held by each current executive officer and director and by each person known by the registrant to own 10% or more of the outstanding common stock have been excluded from this computation in that such persons may be deemed to be affiliates.

 

The number of shares of the registrant’s common stock, $0.001 par value, outstanding as of March 29, 2021 was 9,923,338.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the Company’s Proxy Statement for its 2021 Annual Meeting are incorporated by reference into Part III of this Report.

 

 

 

 
 

 

TABLE OF CONTENTS

 

     

Page

PART I    
  Item 1. Business 3
  Item 1A. Risk Factors 14
  Item 1B. Unresolved Staff Comments 25
  Item 2. Properties 25
  Item 3. Legal Proceedings 25
  Item 4. Mine Safety Disclosures 25
     
PART II    
  Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities 26
  Item 6. Selected Financial Data 26
  Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 27
  Item 7A. Quantitative and Qualitative Disclosures About Market Risk 35
  Item 8. Financial Statements and Supplementary Data 35
  Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 35
  Item 9A. Controls and Procedures 35
  Item 9B. Other Information 35
     
PART III    
  Item 10. Directors, Executive Officers, and Corporate Governance 36
  Item 11. Executive Compensation 36
  Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 36
  Item 13. Certain Relationships and Related Transactions, and Director Independence 36
  Item 14. Principal Accountant Fees and Services 36
     
PART IV    
  Item 15. Exhibits and Financial Statement Schedules 37
  Item 16. Form 10-K Summary 37
   
SIGNATURES 38

 

2
 

 

FORWARD-LOOKING STATEMENTS

 

This annual report on Form 10-K contains forward-looking statements within the meaning of the federal securities laws. These forwarding-looking statements include without limitation statements regarding our expectations and beliefs about the market and industry, our goals, plans, and expectations regarding our properties and drilling activities and results, our intentions and strategies regarding future acquisitions and sales of properties, our intentions and strategies regarding the formation of strategic relationships, our beliefs regarding the future success of our properties, our expectations and beliefs regarding competition, competitors, the basis of competition and our ability to compete, our beliefs and expectations regarding our ability to hire and retain personnel, our beliefs regarding period to period results of operations, our expectations regarding revenues, our expectations regarding future growth and financial performance, our beliefs and expectations regarding the adequacy of our facilities, and our beliefs and expectations regarding our financial position, ability to finance operations and growth and the amount of financing necessary to support operations. These statements are subject to risks and uncertainties that could cause actual results and events to differ materially. See “Item 1A. Risk Factors” for a discussion of certain risk factors. We undertake no obligation to update forward-looking statements to reflect events or circumstances occurring after the date of this annual report on Form 10-K.

 

As used in this annual report on Form 10-K, unless the context otherwise requires, the terms “we,” “us,” “the Company,” and “Houston American” refer to Houston American Energy Corp., a Delaware corporation.

 

PART I

 

Item 1. Business

 

General

 

Houston American Energy Corp is an independent oil and gas company focused on the development, exploration, exploitation, acquisition, and production of natural gas and crude oil properties. Our principal properties, and operations, are in the U.S. Permian Basin. Additionally, we have properties in the U.S. Gulf Coast region, particularly Texas and Louisiana, and in the South American country of Colombia.

 

We focus on early identification of, and opportunistic entrance into, existing and emerging resource plays. We do not operate properties but typically seek to partner with, or invest along-side, larger operators in the development of resources or retain interests, with or without contribution on our part, in prospects identified, packaged and promoted to larger operators. By entering these plays earlier, identifying stranded blocks and partnering with, investing along-side or promoting to, larger operators, we believe we can capture larger resource potential at lower cost and minimize our exposure to drilling risks and costs and ongoing operating costs.

 

We, along with our partners, actively manage our resources through opportunistic acquisitions and divestitures where reserves can be identified, developed, monetized and financial resources redeployed with the objective of growing reserves, production and shareholder value.

 

Properties

 

Our exploration and development projects are focused on existing property interests, and future acquisition of additional property interests, in the Texas Permian Basin, the onshore Texas and Louisiana Gulf Coast region and in the South American country of Colombia.

 

Each of our property interests differ in scope and character and consists of one or more types of assets, such as 3-D seismic data, owned mineral interests, leasehold positions, lease options, working interests in leases, partnership or limited liability company interests, corporate equity interests or other mineral rights. Our percentage interest in each property represents the portion of the interest in the property we share with other partners in the property. Because each property consists of a bundle of assets that may or may not include a working interest in the project, our stated interest in a property simply represents our proportional ownership in the bundle of assets that constitute the property. Therefore, our interest in a property should not be confused with the working interest that we will own when a given well is drilled. Each of our exploration and development projects represents a negotiated transaction between the project partners relating to one or more properties. Our working interest may be higher or lower than our stated interest.

 

3
 

 

The following table sets forth information relating to our principal properties as of December 31, 2020:

 

      Average   Gross   Net proved   2020 Net Production 
  

Net acreage(1)

  

working interest %

  

producing wells(1)

  

reserves (boe)

  

Oil (bbls)

  

Natural Gas (mcf)

 
Texas   1,252                20.0%   4    

223,892

    11,048          66,938 
Louisiana and Oklahoma(1)   291    23.4%           337    2,495 
                               
Total U.S.   1,543    20.6%   4    

223,892

    11,385    69,433 
Colombia   56,111    5.4%                
                               
Total   57,654    5.6%   4    223,892    11,385    69,433 

 

  (1) Excludes acreage, and associated wells, on which we hold royalty interests but no working interest.

 

In 2020, (1) we acquired a 20% working interest in two lease blocks covering an aggregate 820 gross acres within the 20,367-acre (gross) area of mutual interest (the “Hockley County AMI”) associated with our existing Northern Shelf of the Permian Basin acreage in Hockley County, Texas; (2) we acquired a 100% working interest in 46.1 gross acres in Yoakum County, Texas; (3) our acreage position in Hockley County, Texas was reduced by 1,564 gross acres as a result of lease expirations; (4) we sold our interest in two marginal wells and associated acreage in Louisiana; and (5) our acreage position in Reeves County, Texas was reduced by 160 gross (40 net) acres as a result of a lease expiration.

 

- United States Properties:

 

In the United States, our properties and operations are principally located in the on-shore Permian Basin and Gulf Coast regions of Louisiana and Texas.

 

Texas Properties – Permian Basin

 

Reeves County. We hold a 20.4% average working interest in 480 gross acres in Reeves County, Texas, consisting of (1) the 320 gross acre Johnson Lease, in which we hold a 25% working interest, subject to a proportionate 5% back-in after payout, and (2) the 160 gross acre O’Brien Lease, in which we hold an average 11.2% working interest. Our Reeves County acreage lies within the Delaware sub-basin of the Permian Basin, with resource potential in the Wolfcamp, Bone Spring and Avalon formations. During 2017, we drilled and completed our initial wells on both lease blocks, the Johnson State #1H well and the O’Brien #3H well, both horizontally drilled and hydraulically fractured wells in the Wolfcamp A formation. The Johnson #1H well continued on production at December 31, 2020. The O’Brien #3H well was shut-in for repairs at December 31, 2020.

 

In June 2018, a new operator took control of operations of our Reeves County acreage, following the acquisition of the interests of the former operator. No wells have been drilled on our Reeves County acreage since the change of operatorship. As of December 31, 2020, no additional development or drilling operations are planned with respect to our Reeves County acreage.

 

Yoakum County. We hold a 12.5% working interest, subject to a proportionate 10% back-in after payout, in an approximately 650 gross acre block in Yoakum County, Texas and hold a 100% working interest in 46.1 gross acres subject to our obligation to offer participation in that acreage to our partners in the area of mutual interest associates with our Yoakum County acreage. Our Yoakum County acreage lies within the Midland sub-basin of the Permian Basin.

 

During 2019, we drilled the Frost #1H well, the first well on our Yoakum County acreage. The well was horizontally drilled, hydraulically fractured in the San Andres Formation and completed and commenced production in mid-2019. A second well on our Yoakum County acreage, the Frost #2H well, was horizontally drilled, hydraulically fractured in the San Andres Formation and completed and commenced production during the third quarter of 2020. Subject to the operator’s evaluation of the performance of the initial wells, additional wells may be drilled on our Yoakum County acreage in the future.

 

4
 

 

Northern Shelf of Permian Basin – Hockley County. We hold a 20% working interest, subject to an obligation to pay 26.667% of drilling and related costs on the initial well, in an approximately 5,080-acre lease block (including 820 gross acres acquired during 2020 within the Hockley County AMI) in the Northern Shelf of the Permian Basin in Texas. We also hold the right to participate, at cost and for a period of five years, in a 20,367-acre area (gross) of mutual interest that includes the existing lease block.

 

During 2020, we drilled the Lou Brock #1-H well, the first well on our Hockley County acreage. The well has horizontally drilled and hydraulically fractured. As a result of issues incurred during the fracking process, the well is shut-in pending evaluation of options to remedy the fracking issues. Pending evaluation of the performance of the initial well, no additional drilling operations are presently planned on the Hockley County acreage.

 

Louisiana Properties

 

Our principal producing and exploration properties in Louisiana consist of the following:

 

  East Baton Rouge Parish — we hold a 23.437% mineral interest in 2,485 gross acres, of, or as to, which (i) we hold a 2.8376% net royalty interest in 498.12 acres, (ii) we hold a 5.273% net royalty interest in 743.94 acres, and (iii) 1,242.94 acres are unleased.

 

There are no known present plans to conduct additional drilling operations on our Louisiana acreage.

 

- Colombian Properties:

 

At December 31, 2020, we held interests in multiple prospects, all operated by Hupecol Operating and affiliates, in Colombia covering 1,031,610 gross acres. We identify our Colombian prospects by the concessions operated.

 

The following table sets forth information relating to our interests in prospects in Colombia at December 31, 2020:

 

Property  Operator  Ownership
Interest(1)
   Total Gross
Acres
   Total Gross
Developed
Acres
   Gross
Productive
Wells
 
CPO-11 – Venus Exploration Area  Hupecol   2.0%   69,128         
CPO-11  Hupecol   1.0%   570,277         
Los Picachos  Hupecol   12.5%   86,235         
Macaya  Hupecol   12.5%   195,201         
Serrania  Hupecol   12.5%   110,769         
                        
Total           1,031,610         

 

  (1) In 2021, we agreed to increase our ownership interest in the CPO-11 block with our ownership interest in the Venus Exploration Area increasing to 6.99% and our ownership interest in the remainder of the block increasing to 3.495%.

 

At December 31, 2020, we held interests in four concessions operated by Hupecol Operating Co. in Colombia. The CPO-11 concession, including the Venus Exploration Area, is located in the Llanos Basin. The Loc Picachos, Macaya and Serrania concessions are located in the Caguan Putumayo Basin of Colombia. The concessions cover an aggregate area of 1,031,610 gross acres.

 

CPO-11

 

During 2019, we acquired a two percent ownership interest in Hupecol Meta, LLC (“Hupecol Meta”). Hupecol Meta owns the 639,405 gross acre CPO-11 block in the Llanos Basin in Colombia. The CPO-11 block is comprised of the 69,128 acre Venus Exploration area and 570,277 acres which was 50% farmed out by Hupecol to Parex Resources. In 2021, Hupecol Meta increased its ownership interest in the CPO-11 block and we agreed to contribute $99,716 of additional capital to increase our ownership interest in Hupecol Meta to 7.85%. Through our ownership interest in Hupecol Meta, after the agreed 2021 increase in ownership, we will hold a 6.99% interest in the Venus Exploration area and a 3.495% interest in the remainder of the CPO-11 block.

 

5
 

 

The CPO-11 block covers almost 1,000 square miles with multiple identified leads and prospects. The Venus Exploration area includes an existing productive vertical well that is presently shut-in. Pursuant to the farm-out agreement covering the balance of the CPO-11 block, the Daisy-1 well, a vertical well, began drilling in December 2019 and was determined to be a dry hole in early 2020. The Matuno-1 well, a vertical well drilled at no cost to Houston American, was drilled during 2020 and was a dry hole. Hupecol will evaluate industry conditions and drilling results from the initial planned wells before formalizing drilling plans for additional wells on the CPO-11 block. Future wells in the Venus Exploration area, if any, are expected to be horizontal wells.

 

Serrania Block

 

Our interest in the Serrania concession was acquired through a Farmout Agreement with the original operator of the block pursuant to which we paid 25% of designated Phase 1 geological and seismic costs in return for a 12.5% interest in the Contract for Exploration and Production covering the concession.

 

Seismic work on the Serrania Block was completed in 2010. Drilling preparation and seismic processing work was performed in 2011 and 2012 in connection with the planned drilling of initial test wells on the concession. The National Hydrocarbon Agency of Colombia (the “ANH”) granted extensions of required development commitments, including drilling of a first test well on the Serrania concession, until conditions in the area allow operations.

 

The Serrania concession is subject to longstanding local opposition to the granting of necessary permits to commence drilling operations. Hupecol is presently engaged in litigation and negotiations with the National Hydrocarbon Agency of Colombia (the “ANH”) to either secure the necessary permits to drill and develop the concession or receive compensation for the concession and the funds expended.

 

Given the ongoing opposition, Hupecol has determined to stop all activity on the block for the foreseeable future pending a final definitive settlement either permitting drilling or compensating Hupecol for the block. COVID-19 has caused all actions in Colombia to be delayed.

 

Los Picachos and Macaya Prospects

 

Our Los Picachos and Macaya prospects adjoin our Serrania concession. Hupecol has advised us that they have put on hold plans to begin seismic and other work on the Los Picachos and Macaya concessions until a satisfactory resolution of the ongoing permitting disputes. The ANH has granted extensions of required development commitments, including seismic acquisition, until conditions in the area allow operations.

 

As operator of our various prospects, Hupecol has substantial control over the timing of drilling and selection of prospects to be drilled and we have limited ability to influence the selection of prospects to be drilled or the timing of such drilling operations and have no effective means of controlling the costs of such drilling operations. Accordingly, our drilling budget is subject to fluctuation based on the prospects selected to be drilled by Hupecol, the decisions of Hupecol regarding timing of such drilling operations and the ability of Hupecol to drill and operate wells within estimated budgets.

 

Drilling Activity

 

During 2020, we drilled three wells. The following table summarizes the number of wells drilled during 2020, 2019 and 2018, excluding any wells drilled under farmout agreements, royalty interest ownership, or any other wells in which we do not have a working interest.

 

   Year Ended December 31, 
   2020   2019   2018 
  

Gross

  

Net

  

Gross

  

Net

  

Gross

  

Net

 
Development wells, completed as:                              
Productive                  
Non-productive                        
Total development wells                        
                               
Exploratory wells, completed as:                              
Productive   1    0.20    1    0.125         
Non-productive   2    0.02                 
Total exploratory wells   3    0.22    1    0.125         

  

6
 

 

Productive wells are wells that are found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

 

As of December 31, 2020, we had testing operations ongoing on one well, the Lou Brock #1-H well in Hockley County, Texas.

 

Productive Wells

 

Productive wells consist of producing wells and wells capable of production, including shut-in wells. A well bore with multiple completions is counted as only one well. As of December 31, 2020, we owned interests in four gross wells (excluding wells in which we hold only royalty interests). As of December 31, 2020, we had ownership interests in productive wells, categorized by geographic area, as follows:

 

   Oil Wells   Gas Wells 
United States          
Gross   4     
Net   0.68     
Colombia          
Gross        
Net        
Total          
Gross   4     
Net   0.68     

 

Volume, Prices and Production Costs

 

The following table sets forth certain information regarding the production volumes, average prices received and average production costs associated with our sales of gas and oil, categorized by geographic area, for each of the three years ended December 31, 2020, 2019, and 2018:

 

  

Year Ended December 31,

 
  

2020

  

2019

  

2018

 
Net Production:               
Gas (Mcf):               
United States   69,433    116,629    253,053 
Colombia            
Total   69,433    116,629    253,053 
                
Oil (Bbls):               
United States   11,385    13,674    23,842 
Colombia            
Total   11,385    13,674    23,842 
                
Average sales price:               
Gas ($ per Mcf)               
United States  $1.14   $2.02   $3.27 
Colombia            
Total  $1.14   $2.02   $3.27 
                
Oil ($ per Bbl)               
United States  $35.63   $55.73   $57.43 
Colombia            
Total  $35.63   $55.73   $57.43 
                
Average production costs ($ per BOE):               
United States  $16.59   $22.38   $53.19 
Colombia            
Total  $16.59   $22.38   $53.19 

 

7
 

 

Natural Gas and Oil Reserves

 

Reserve Estimates

 

The following tables sets forth, by country and as of December 31, 2020, our estimated net proved oil and natural gas reserves, and the estimated present value (discounted at an annual rate of 10%) of estimated future net revenues before future income taxes (“PV-10”) and after future income taxes (“Standardized Measure”) of our proved reserves, each prepared in accordance with assumptions prescribed by the Securities and Exchange Commission (“SEC”).

 

The PV-10 value is a widely used measure of value of oil and natural gas assets and represents a pre-tax present value of estimated cash flows discounted at ten percent. PV-10 is considered a non-GAAP financial measure as defined by the SEC. We believe that our PV-10 presentation is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account the related future income taxes, as such taxes may differ among various companies because of differences in the amounts and timing of deductible basis, net operating loss carry forwards and other factors. We believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our proved reserves to the reserve estimates of other companies. PV-10 is not a measure of financial or operating performance under GAAP and is not intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

 

These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards.

 

  

Reserves (1)

 
  

Oil

  

Natural Gas

  

Total (2)

 
   (bbls)   (mcf)   (boe) 
Reserve category               
Proved Developed Producing               
United States   96,513    764,274    223,892 
Colombia            
Total Proved Developed Producing Reserves   96,513    764,274    223,892 
Proved Undeveloped               
United States            
Colombia            
Total Proved Undeveloped Reserves            
Total Proved Reserves   96,513    764,274    223,892 

 

   Proved Developed   Proved Undeveloped   Total Proved 
             
PV-10 (1)  $1,174,132   $   $1,174,132 
Standardized measure (3)  $1,174,132   $   $1,174,132 

 

  (1) In accordance with applicable financial accounting and reporting standards of the SEC, the estimates of our proved reserves and the PV-10 set forth herein reflect estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions at December 31, 2020. For purposes of determining prices, we used the unweighted arithmetical average of the prices on the first day of each month within the 12-month period ended December 31, 2020. The average prices utilized for purposes of estimating our proved reserves were $37.83 per barrel of oil and $1.82 per mcf of natural gas for our US properties, adjusted by property for energy content, quality, transportation fees and regional price differentials. The prices should not be interpreted as a prediction of future prices. The amounts shown do not give effect to non-property related expenses, such as corporate general administrative expenses and debt service, future income taxes or to depreciation, depletion and amortization.
     
  (2) Natural gas is converted on the basis of six Mcf of gas per one barrel of oil equivalent.
     
  (3) The Standard Measure differs from PV-10 only in that the Standard Measure reflects estimated future income taxes.

 

8
 

 

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

 

Reserve Estimation Process, Controls and Technologies

 

The reserve estimates, including PV-10 and Standard Measure estimates, set forth above were prepared by Russell K. Hall & Associates, Inc. for our Permian Basin, Texas reserves.

 

These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards.

 

Our year-end reserve reports are prepared by reserve engineering firms based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geosciences and engineering data, and other information provided to them by our management team. Upon analysis and evaluation of data provided, the reserve engineering firms issue a preliminary appraisal report of our reserves. The preliminary appraisal report and changes in our reserves are reviewed by our President and board for reasonableness of the results obtained. Once any questions have been addressed, the reserve engineering firms issue final appraisal reports, reflecting their conclusions.

 

Russell K. Hall & Associates is an independent Midland, Texas based professional engineering firm providing reserve evaluation services to the oil and gas industry. Their report was prepared under the direction of Russell K. Hall, founder and President of Russell K. Hall & Associates. Mr. Hall holds a BS in Mechanical Engineering from the University of Oklahoma, is a registered professional engineer and a member of the Society of Petroleum Engineers, the Society of Independent Professional Earth Scientists and the West Texas Geological Society. Mr. Hall has more than 30 years of experience in reserve evaluation for the oil and gas industry and the oil and gas finance industry. Russell K. Hall & Associates, and its employees, have no interest in our company or our properties and were objective in determining our reserves.

 

The SEC’s rules with respect to technologies that a company can use to establish reserves allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

 

Our reserve engineering firm used a combination of production and pressure performance, simulation studies, offset analogies, seismic data and interpretation, geophysical logs and core data to calculate our reserves estimates.

 

Proved Undeveloped Reserves

 

The following table summarizes activity within our proved undeveloped reserve category for the year ended December 31, 2020:

 

  

For the Year Ended

December 31, 2020

 
Proved undeveloped reserves (Boe):     
Beginning of year   282,123 
Decrease due to evaluation reassessments   (282,123)
End of year    

 

The decrease in proved undeveloped reserves during the year ended December 31, 2020 was attributable to evaluation reassessments relating to our Reeves County, Texas acreage.

 

9
 

 

Developed and Undeveloped Acreage

 

The following table sets forth the gross and net developed and undeveloped acreage (including both leases and concessions, but excluding acreage in which we hold a royalty interest but no working interest), categorized by geographical area, which we held as of December 31, 2020:

 

  

Developed

  

Undeveloped

 
  

Gross

   Net  

Gross

  

Net

 
United States   2,043    440    5,456    1,103 
Colombia           1,031,610    56,111 
Total   2,043    440    1,037,066    57,214 

 

Developed acreage is comprised of leased acres that are within an area spaced by or assignable to a productive well and acreage in which we hold a mineral interest with no potential development related lease expirations. Undeveloped acreage is comprised of leased acres with defined remaining terms and not within an area spaced by or assignable to a productive well.

 

As is customary in the oil and natural gas industry, we can generally retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by paying delay rentals during the remaining primary term of leases. The oil and natural gas leases in which we have an interest are for varying primary terms and, if production under a lease continues from our developed lease acreage beyond the primary term, we are entitled to hold the lease for as long as oil or natural gas is produced.

 

The leases and concessions comprising the U.S. undeveloped acreage set forth in the table above relate primarily to our Northern Shelf acreage which is comprised of a large number of leases most having primary terms of three years and will expire at the end of their respective primary terms unless production from the acreage has been established prior to such date, in which event the lease or concession will remain in effect until the cessation of production.

 

Title to Properties

 

Title to properties is subject to royalty, overriding royalty, carried working, net profits, working and other similar interests and contractual arrangements customary in the gas and oil industry, liens for current taxes not yet due and other encumbrances. As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than preliminary review of local records).

 

Investigation, including a title opinion of local counsel, generally is made before commencement of drilling operations.

 

Marketing

 

At December 31, 2020, we had no contractual agreements to sell our gas and oil production and all production was sold on spot markets.

 

Employees

 

As of December 31, 2020, we had 2 full-time employees and no part time employees. The employees are not covered by a collective bargaining agreement, and we do not anticipate that any of our future employees will be covered by such agreements.

 

10
 

 

Competition

 

We encounter intense competition from other oil and gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and gas companies, numerous independent oil and gas companies and individuals. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources and have been engaged in the oil and gas business for a much longer time than our Company. These companies may be able to pay more for productive oil and gas properties, exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

 

Regulatory Matters

 

Regulation of Oil and Gas Production, Sales and Transportation

 

The oil and gas industry is subject to regulation by numerous national, state and local governmental agencies and departments. Compliance with these regulations is often difficult and costly and noncompliance could result in substantial penalties and risks. Most jurisdictions in which we operate also have statutes, rules, regulations or guidelines governing the conservation of natural resources, including the unitization or pooling of oil and gas properties, minimum well spacing, plugging and abandonment of wells and the establishment of maximum rates of production from oil and gas wells. Some jurisdictions also require the filing of drilling and operating permits, bonds and reports. The failure to comply with these statutes, rules and regulations could result in the imposition of fines and penalties and the suspension or cessation of operations in affected areas.

 

Environmental Regulation

 

Various federal, state and local laws and regulations relating to the protection of the environment, including the discharge of materials into the environment, may affect our exploration, development and production operations and the costs of those operations. These laws and regulations, among other things, govern the amounts and types of substances that may be released into the environment, the issuance of permits to conduct exploration, drilling and production operations, the discharge and disposition of generated waste materials and waste management, the reclamation and abandonment of wells, sites and facilities, financial assurance and the remediation of contaminated sites. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or cessation of operations in affected areas.

 

The environmental laws and regulations applicable to our U.S. operations include, among others, the following United States federal laws and regulations:

 

  Clean Air Act, and its amendments, which govern air emissions;
     
  Clean Water Act, which governs discharges into waters of the United States;
     
  Comprehensive Environmental Response, Compensation and Liability Act, which imposes liability where hazardous releases have occurred or are threatened to occur (commonly known as “Superfund”);
     
  Resource Conservation and Recovery Act, which governs the management of solid waste;
     
  Oil Pollution Act of 1990, which imposes liabilities resulting from discharges of oil into navigable waters of the United States;
     
  Emergency Planning and Community Right-to-Know Act, which requires reporting of toxic chemical inventories;
     
  Safe Drinking Water Act, which governs the underground injection and disposal of wastewater; and
     
  U.S. Department of Interior regulations, which impose liability for pollution cleanup and damages.

 

Colombia has similar laws and regulations designed to protect the environment.

 

We routinely obtain permits for our facilities and operations in accordance with these applicable laws and regulations on an ongoing basis. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of our facilities or operations.

 

11
 

 

The ultimate financial impact of these environmental laws and regulations is neither clearly known nor easily determined as new standards are enacted and new interpretations of existing standards are rendered. Environmental laws and regulations are expected to have an increasing impact on our operations. In addition, any non-compliance with such laws could subject us to material administrative, civil or criminal penalties, or other liabilities. Potential permitting costs are variable and directly associated with the type of facility and its geographic location. Costs, for example, may be incurred for air emission permits, spill contingency requirements, and discharge or injection permits. These costs are considered a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations.

 

Although we do not operate the properties in which we hold interests, noncompliance with applicable environmental laws and regulations by the operators of our oil and gas properties could expose us, and our properties, to potential costs and liabilities associated with such environmental laws. While we exercise no oversight with respect to any of our operators, we believe that each of our operators is committed to environmental protection and compliance. However, since environmental costs and liabilities are inherent in our operations and in the operations of companies engaged in similar businesses and since regulatory requirements frequently change and may become more stringent, there can be no assurance that material costs and liabilities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production.

 

Hydraulic Fracturing Regulation

 

Hydraulic fracturing, or “fracking”, is a common practice used to stimulate production of oil and natural gas from tight formations, including shales. Fracking involves the injection of fluids—usually consisting mostly of water but typically including small amounts of chemical additives—as well as sand into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore.

 

Except as applies to federal lands, fracking generally is exempt from regulation under many federal environmental rules and is generally regulated at the state level.

 

For example, in Texas, the Texas Railroad Commission administers regulations related to oil and gas operations, including regulations pertaining to protection of water resources in connection with those operations. The Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit after February 1, 2012. This law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (OSHA) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission.

 

There is public controversy regarding fracking with regard to the use of fracking fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. Lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations restricting hydraulic fracturing are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations as well as make it easier to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause operators to incur substantial compliance costs, and compliance or the consequences of any failure to comply could have a material adverse effect on well operations and economics.

 

We do not operate wells but contract well operations to third party operators. Operators of our wells may perform fracking operations, or contract third parties to perform such operations, on wells in which we participate. Many newer wells would not be economical without the use of fracking to stimulate production from the well. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

 

12
 

 

Climate Change Legislation and Greenhouse Gas Regulation

 

Federal, state and local laws and regulations are increasingly being enacted to address concerns about the effects the emission of “greenhouse gases” may have on the environment and climate. These effects are widely referred to as “climate change.” Since its December 2009 endangerment finding regarding the emission of greenhouse gases, the Environmental Protection Agency (the “EPA”) has begun regulating sources of greenhouse gas emissions under the federal Clean Air Act. Among several regulations requiring reporting or permitting for greenhouse gas sources, the EPA finalized its “tailoring rule” in May 2010 that determines which stationary sources of greenhouse gases are required to obtain permits to construct, modify or operate on account of, and to implement the best available control technology for, their greenhouse gases. The EPA’s final greenhouse gas reporting requirements pertain to certain oil and gas production facilities.

 

Moreover, the U.S. Congress has considered establishing a cap-and-trade program to reduce U.S. emissions of greenhouse gases. Under past proposals, the EPA would issue or sell a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of such legislation, if ever adopted, would be to impose increasing costs on the combustion of carbon-based fuels such as crude oil, refined petroleum products, and natural gas. In addition, while the prospect for such cap-and-trade legislation by the U.S. Congress remains uncertain, several states have adopted, or are in the process of adopting, similar cap-and-trade programs.

 

As a crude oil and natural gas company, the debate on climate change is relevant to our operations because the equipment we use to explore for, develop and produce crude oil and natural gas emits greenhouse gases. Additionally, the combustion of carbon-based fuels, such as the crude oil and natural gas we sell, emits greenhouse gases. Thus, any current or future federal, state or local climate change initiatives could adversely affect demand for the crude oil and natural gas we produce by stimulating demand for alternative forms of energy that do not rely on the combustion of fossil fuels, and therefore could have a material adverse effect on our business. Although our compliance with any greenhouse gas regulations may result in increased compliance and operating costs, we do not expect the compliance costs for currently applicable regulations to be material. Moreover, while it is not possible at this time to estimate the compliance costs or operational impacts for any new legislative or regulatory developments in this area, we do not anticipate being impacted to any greater degree than other similarly situated competitors.

 

Web Site Access to Reports

 

Our Web site address is www.houstonamerican.com. We make available, free of charge on our Web site, our annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and all amendments to these reports as soon as reasonably practicable after such material is electronically filed with, or furnished to, the United States Securities and Exchange Commission. Information contained on our website is not incorporated by reference into this report and you should not consider information contained on our website as part of this report.

 

13
 

 

Item 1A. Risk Factors

 

Our business activities and the value of our securities are subject to significant hazards and risks, including those described below. If any of such events should occur, our business, financial condition, liquidity and/or results of operations could be materially harmed, and holders and purchasers of our securities could lose part or all of their investments.

 

Company and Organization Risks

 

We have experienced recurring operating losses and may not attain profitability; attainment of profitability will require successful drilling and development operations to support substantial increases in production and revenues.

 

We have incurred losses from operations in each year since 2011 and, at December 31, 2020, had an accumulated deficit of $72,021,911. While we have implemented cost control initiatives that have brought down our cash overhead in recent years, our ability to attain profitability is substantially dependent upon increasing our production and production revenues while continuing to control costs. In order to increase production and revenues, we will need to successfully drill new wells on our existing, or future acquired, acreage at a pace, and with results, significantly greater than in recent years. If, for any reason, we are unable to substantially increase our production and revenues, while controlling drilling costs and overhead, we may never attain, or sustain, profitability. Our ability to so increase production and revenues and attain profitability is subject to all of the other risks of oil and gas operations as well as our ability to fund our share of drilling and development operations.

 

Our ability to operate profitably and our financial condition are highly dependent on energy prices. A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

 

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

 

  changes in global supply and demand for oil and natural gas, including changes in demand resulting from general and specific economic conditions relating to the business cycle and other factors (e.g., global health pandemics such as COVID-19);
     
  the actions of the Organization of Petroleum Exporting Countries, or OPEC;
     
  the price and quantity of imports of foreign oil and natural gas;
     
  political conditions, including embargoes, in or affecting other oil-producing activity;
     
  the level of global oil and natural gas exploration and production activity;
     
  the level of global oil and natural gas inventories;
     
  weather conditions;
     
  technological advances affecting energy consumption, including renewable energy initiatives that result in energy consumption transitioning away from fossil fuels; and
     
  the price and availability of alternative fuels.

 

Global economic growth drives demand for energy from all sources, including fossil fuels. Should the U.S. and global economies experience weakness, demand for energy may decline. Similarly, should growth in global energy production outstrip demand, excess supplies may arise. Declines in demand and excess supplies may result in accompanying declines in commodity prices and deterioration of our financial position along with our ability to operate profitably and our ability to obtain financing to support operations.

 

14
 

 

With respect to our business, we have experienced periodic declines in demand thought to be associated with slowing economic growth in certain markets, including the effects of the COVID-19 pandemic, coupled with new oil and gas supplies coming on line and other circumstances beyond our control that resulted in oil and gas supply exceeding global demand which, in turn, resulted in steep declines in prices of oil and natural gas. There can be no assurance as to how low the current price decline will persist or that a reoccurrence of price weakness will not arise in the future.

 

Past declines in prices reduced, and any declines that may occur in the future can be expected to reduce, our revenues and profitability as well as the value of our reserves. Such declines adversely affect well and reserve economics and may reduce the amount of oil and natural gas that we can produce economically, resulting in deferral or cancellation of planned drilling and related activities until such time, if ever, as economic conditions improve sufficiently to support such operations. Any extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

 

The COVID-19 pandemic materially adversely affected our operations during 2020 and may continue to adversely affect our operations for the foreseeable future.

 

In early 2020, global health care systems and economies began to experience historic strain from the spread of the COVID-19 coronavirus. As the virus spread, global economic activity began to slow and future economic activity was forecast to, and did, slow with a resulting forecast of a decline in oil and gas demand. As a result, global energy prices declined precipitously. The decline in prices adversely affected our revenues and profitability in 2020 and, while energy prices have partially recovered, may adversely affect the economics of our existing wells and planned future wells, possibly resulting in impairment charges to existing properties and delaying or abandoning planned drilling operations as uneconomical.

 

In response to the COVID-19 pandemic, our staff has begun working remotely and many of our key vendors, service suppliers and partners have similarly begun to work remotely. As a result of such remote work arrangements, we anticipate that certain operational, reporting, accounting and other processes will slow which may result in longer time to execute critical business functions, higher operating costs and uncertainties regarding the quality of services and supplies, any of which could substantially adversely affect our operating results for as long as the current pandemic persists and potentially for some time after the pandemic subsides.

 

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to compete.

 

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

 

Our ability to acquire additional mineral acreage and to drill and develop our existing acreage as well as other acreage that may be acquired is subject to availability of financing on satisfactory terms.

 

Our financial resources are limited and may not be adequate to fully drill and develop our acreage or to consummate any meaningful acquisition. While our available funds as of March 29, 2021 are expected to be adequate to fund our share of well costs on wells expected to be drilled, as of that date, during 2021, our funds on hand are not expected to be adequate to support a long-term drilling and development plan with respect to our existing acreage holdings, should such a plan be implemented.

 

15
 

 

We may continue to seek to access the capital markets to support planned drilling operations or acquisitions through sales of common stock, preferred stock or other securities or may seek debt financing to support such capital requirements. We do not presently have any commitments to provide equity or debt financing to support any future drilling operations or acquisitions and there can be no assurance that such financing will be available if and when needed on acceptable terms or at all. If we are unable to fund our share of drilling and completion costs of future wells, we may experience flat and declining production and revenues and decreased profitability and may be subject to penalties with respect to our interest in acreage.

 

We may be unable to make attractive acquisitions and any acquisitions may be subject to substantial risks that could adversely affects our business.

 

Acquisitions of additional mineral acreage at favorable prices is part of our strategy to increase and diversify our holdings and grow our production and revenues. We expect to focus our acquisition efforts in the Permian Basin and in Colombia with an emphasis on partnering with proven operators in the area to acquire positions at favorable prices. Competition for mineral acreage in the Permian Basin is intense. Other operators, particularly large operators, have historically paid substantially higher prices for Permian Basin acreage than we have paid. There can be no assurance that we will be able to successfully acquire additional acreage in the Permian Basin, Colombia or elsewhere at favorable prices or at all. Even if we are successful in acquiring additional acreage on favorable terms, it is possible that such acreage (i) will be more speculative than higher priced acreage, (ii) may face challenges or limitations in drilling and operations such as lack of, or limited access to, critical infrastructure, or (iii) may prove uneconomical.

 

Our success depends on our staff, which is small in size and limited in technical capabilities, and third party consultants, the loss of any of whom could disrupt our business operations.

 

Our success will depend on our ability to attract and retain key staff members. Our staff is extremely small in size and possesses limited technical capabilities. We do not presently maintain any significant internal technical capabilities but rely on the engineering, geological and other technical skills of our board and, from time to time, third party consultants. If members of our staff should resign or we are unable to attract the necessary personnel, our business operations could be adversely affected.

 

Our charter and bylaws, as well as provisions of Delaware law, could make it difficult for a third party to acquire our company and also could limit the price that investors are willing to pay in the future for shares of our common stock.

 

Delaware corporate law and our charter and bylaws contain provisions that could delay, deter or prevent a change in control of our Company or our management. These provisions could also discourage proxy contests and make it more difficult for our stockholders to elect directors and take other corporate actions without the concurrence of our management or board of directors. These provisions:

 

  authorize our board of directors to issue “blank check” preferred stock, which is preferred stock that can be created and issued by our board of directors, without stockholder approval, with rights senior to those of our common stock;
     
  provide for a staggered board of directors and three-year terms for directors, so that no more than one-third of our directors could be replaced at any annual meeting;
     
  provide that directors may be removed only for cause; and
     
  establish advance notice requirements for submitting nominations for election to the board of directors and for proposing matters that can be acted upon by stockholders at a meeting.

 

We are also subject to anti-takeover provisions under Delaware law, which could also delay or prevent a change of control. Taken together, these provisions of our charter, bylaws, and Delaware law may discourage transactions that otherwise could provide for the payment of a premium over prevailing market prices of our common stock and also could limit the price that investors are willing to pay in the future for shares of our common stock.

 

16
 

 

Oil and Gas Operating Risks

 

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

 

Our future success will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Please read “Reserve estimates depend on many assumptions that may turn out to be inaccurate” (below) for a discussion of the uncertainty involved in these processes. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following:

 

  delays imposed by or resulting from compliance with regulatory requirements;

 

  pressure or irregularities in geological formations;

 

  shortages of or delays in obtaining equipment and qualified personnel;

 

  equipment failures or accidents;

 

  adverse weather conditions;

 

  reductions in oil and natural gas prices;

 

  title problems; and

 

  limitations in the market for oil and natural gas.

 

Cost overruns, curtailments, delays and cancellations of operations as a result of the above factors and other factors common in our industry may materially adversely affect our operating results and financial position and our ability to maintain our interests in prospects.

 

We are dependent upon third party operators of our oil and gas properties.

 

Under the terms of the operating agreements related to our oil and gas properties, third parties act as the operator of each of our oil and gas wells and control the drilling and operating activities to be conducted on our properties. Therefore, we have limited control over certain decisions related to activities on our properties, which could affect our results of operations. Decisions over which we have limited control include:

 

  the timing and amount of capital expenditures;

 

  the timing of initiating the drilling and recompleting of wells;

 

  the extent of operating costs; and

 

  the level of ongoing production.

 

Decisions made by our operators may be different than those we would make reflecting priorities different than our priorities and may materially adversely affect our operating results and financial position, including potential declines in production and revenues from properties, declines in value of properties and lease expirations, among other potential consequences.

 

17
 

 

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

 

Our prospects are properties on which we have identified what we believe, based on available seismic and geological information, to be indications of oil or natural gas potential. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require substantial seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

 

Our operations are expected to involve use of horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

 

Our operations, in most instances, are expected to involve utilizing some of the latest drilling and completion techniques as developed by our service providers, including horizontal drilling and completion techniques. Risks that we face while drilling horizontal wells include, but are not limited to, the following:

 

  landing the wellbore in the desired drilling zone;

 

  staying in the desired drilling zone while drilling horizontally through the formation;

 

  running casing the entire length of the wellbore; and

 

  being able to run tools and other equipment consistently through the horizontal wellbore.

 

Risks that we face while completing wells include, but are not limited to, the following:

 

  the ability to fracture stimulate the planned number of stages;

 

  the ability to run tools the entire length of the wellbore during completion operations; and

 

  The ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

 

Horizontal drilling in emerging areas with little or no history of use of such techniques is more uncertain than drilling in areas that are more developed and have a longer history of established horizontal drilling operations. If our horizontal drilling fail to adequately address the risks described, we may incur costs overruns, underperformance by wells or non-productive wells.

 

The unavailability or high cost of drilling rigs, equipment, supplies, personnel, water disposal and oil field services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget and operate profitably.

 

Shortages or the high cost of drilling rigs, equipment, supplies or personnel, including shortages or unavailability of personnel, supplies and equipment arising from the COVID-19 pandemic, could delay or adversely affect our development and exploration operations. If the price of oil and natural gas increases, the demand for production equipment and personnel will likely also increase, potentially resulting, at least in the near-term, in shortages of equipment and personnel. In addition, larger producers may be more likely to secure access to such equipment by virtue of offering drilling companies more lucrative terms. In particular, high levels of horizontal drilling and hydraulic fracturing operations in the Permian Basin have created increased demand, and higher costs, for associated drilling and completion services, water supply, handling and disposal and access to production handling and transportation infrastructure, each of which have resulted in higher than anticipated prices with respect to our initial Reeves County wells. If we are unable to acquire access to such resources, or can obtain access only at higher prices, not only would this potentially delay our ability to convert our reserves into cash flow but could also significantly increase the cost of producing those reserves, thereby negatively impacting anticipated net income.

 

18
 

 

We may not be able to obtain access on commercially reasonable terms or otherwise to pipelines and storage facilities, gathering systems and other transportation, processing, fractionation and refining facilities to market our oil and gas production; we rely on a limited number of purchasers of our products.

 

The marketing of oil and gas production depends in large part on the availability, proximity and capacity of pipelines and storage facilities, gathering systems and other transportation, processing, fractionation and refining facilities, as well as the existence of adequate markets. If there were insufficient capacity available on these systems, if these systems were unavailable to us, or if access to these systems were to become commercially unreasonable, the price offered for our production could be significantly depressed, or we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons while we construct our own facility or await the availability of third party facilities. We rely on facilities developed and owned by third parties in order to store, process, transport, fractionate and sell our oil and gas production. Our plans to develop and sell our oil and gas reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient transportation, storage or processing and fractionation facilities to us, especially in areas of planned expansion where such facilities do not currently exist.

 

The amount of oil and gas that can be produced is subject to limitations in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering, transportation, refining or processing facilities, or lack of capacity on such facilities. Curtailments arising from these and similar circumstances may last from a few days to several months, resulting in lost or curtailed production and revenues.

 

We may operate in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. This may be particularly true with respect to our Colombian acreage where infrastructure is limited or, in some cases, non-existent. Such restrictions on our ability to sell our oil or natural gas could have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.

 

To the extent that we enter into transportation contracts with pipelines that are subject to FERC regulation, we are subject to FERC requirements related to use of such capacity. Any failure on our part to comply with FERC’s regulations and policies or with an interstate pipeline’s tariff could result in the imposition of civil and criminal penalties.

 

A limited number of companies purchase a majority of our production. The loss of a significant purchaser could have a material adverse effect on our ability to sell production.

 

Our oil and gas holdings and operations are concentrated, and we are dependent upon the results of drilling and production operations on a small number of prospects and wells; in particular, our Permian Basin holdings and wells. If those properties and wells perform below expectations, we may experience production, revenues and profitability below expectations.

 

We have historically been focused on development of a small number of geographically concentrated prospects. Accordingly, we lack diversification with respect to the nature and geographic location of our holdings. As a result, we are exposed to higher dependence on individual resource plays and may experience substantial losses should a single individual prospect prove unsuccessful. At December 31, 2020, we owned interests in 1,543 net acres and 0.675 net wells in the United States and 56,111 net acres and no wells in Colombia. While we have resumed activities in Colombia with the acquisition of an interest in the CPO-11 block, our production, revenues and profitability for the foreseeable future are expected to be highly dependent upon the results of existing and future wells we may drill in the Permian Basis. In order grow our revenues and improve profitability, we must continue to drill productive wells. If existing wells, or future wells we may drill, in the Permian Basin perform below expectations, we may experience flat or declining production and revenues and may be unable to attain profitability.

 

19
 

 

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flows and income.

 

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and, therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. If we are unable to develop, exploit, find or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing properties would be incapable of sustaining commercial production.

 

A substantial percentage of our properties are unproven and undeveloped; therefore, the cost of proving and developing our properties and risk associated with our success is greater than would be the case if the majority of our properties were categorized as proved developed producing.

 

Because a substantial percentage of our properties are unproven and/or undeveloped, we require significant capital to prove and develop such properties before they may become productive. Because of the inherent uncertainties associated with drilling for oil and gas, some of these properties may never be successfully drilled and developed to the extent that they result in positive cash flow. Even if we are successful in our drilling and development efforts, it could take several years for a significant portion of our unproven properties to be converted to positive cash flow.

 

We may incur substantial uninsured losses and be subject to substantial liability claims as a result of our oil and natural gas operations.

 

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

 

  environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;
     
  abnormally pressured formations;
     
  mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
     
  fires and explosions;
     
  personal injuries and death; and
     
  natural disasters.

 

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to our company. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of a significant accident or other event that is not fully covered by insurance could have a material adverse effect on our business, results of operations or financial condition.

 

If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.

 

Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we have written down the carrying value of our oil and natural gas properties periodically and may be required to further write down the carrying value of oil and gas properties in the future. A write-down would constitute a non-cash charge to earnings. It is likely the cumulative effect of a write-down could also negatively impact the trading price of our securities.

 

20
 

 

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

 

The process of estimating oil and natural gas reserves is complex, requiring interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves reported.

 

In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.

 

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development activities, prevailing 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, as reported from time to time, should not be assumed to be the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on costs on the date of the estimate and average prices over the preceding twelve months. Actual future prices and costs may differ materially from those used in the present value estimate. If future prices decline or costs increase it could negatively impact our ability to finance operations, and individual properties could cease being commercially viable, affecting our decision to continue operations on producing properties or to attempt to develop properties. All of these factors would have a negative impact on earnings and net income, and most likely the trading price of our securities.

 

Our operations will be subject to environmental and other government laws, regulations and policies that are costly, could potentially subject us to substantial liabilities and potentially result in decreased demand for products.

 

Crude oil and natural gas exploration and production operations in the United States and in Colombia are subject to extensive federal, state and local laws and regulations. Oil and gas companies are subject to laws and regulations addressing, among others, land use and lease permit restrictions, bonding and other financial assurance related to drilling and production activities, spacing of wells, unitization and pooling of properties, environmental and safety matters, plugging and abandonment of wells and associated infrastructure after production has ceased, operational reporting and taxation. Failure to comply with such laws and regulations can subject us to governmental sanctions, such as fines and penalties, as well as potential liability for personal injuries and property and natural resources damages. We may be required to make significant expenditures to comply with the requirements of these laws and regulations, and future laws or regulations, or any adverse change in the interpretation of existing laws and regulations, could increase such compliance costs. Regulatory requirements and restrictions could also delay or curtail our operations and could have a significant impact on our financial condition or results of operations.

 

Our oil and gas operations are subject to stringent laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations:

 

  require the acquisition of a permit before drilling commences;
     
  restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;

 

21
 

 

  limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
     
  impose substantial liabilities for pollution resulting from operations.

 

Failure to comply with these laws and regulations may result in:

 

  the imposition of administrative, civil and/or criminal penalties;
     
  incurring investigatory or remedial obligations; and
     
  the imposition of injunctive relief.

 

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Although we intend to be in compliance in all material respects with all applicable environmental laws and regulations, we cannot assure you that we will be able to comply with existing or new regulations. In addition, the risk of accidental spills, leakages or other circumstances could expose us to extensive liability.

 

We are unable to predict the effect of additional environmental laws and regulations that may be adopted in the future, including whether any such laws or regulations would materially adversely increase our cost of doing business or affect operations in any area.

 

Under certain environmental laws that impose strict, joint and several liability, we may be required to remediate our contaminated properties regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were or were not in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations. Moreover, new or modified environmental, health or safety laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. Therefore, the costs to comply with environmental, health or safety laws or regulations or the liabilities incurred in connection with them could significantly and adversely affect our business, financial condition or results of operations.

 

In addition, many countries as well as several states and regions of the U.S. have agreed to regulate emissions of “greenhouse gases” and have adopted policies to actively promote alternative energy “green energy” sources that are specifically designed to replace fossil fuels. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning of natural gas and oil, are greenhouse gases. Regulation of greenhouse gases could adversely impact some of our operations and “green energy” initiatives could substantially reduce demand for our products in the future.

 

Increased regulation, or limitations on the use, of hydraulic fracturing could increase our cost of operations and reduce profitability.

 

Our existing Permian Basin wells have been hydraulically fractured and future wells that we may drill in the Permian Basin are expected to be economically viable only if hydraulic fracturing is utilized to increase flows of oil and natural gas, particularly in shale formations. The use of hydraulic fracturing has been the subject of much scrutiny and debate in recent years with many activists and state and federal legislators and regulators actively pushing for most stringent regulation of such operations or even the ban of such operations.

 

In the event that state or federal regulation of hydraulic fracturing is increased or hydraulic fracturing is substantially curtailed or prohibited through law or regulation, our cost of drilling and operating wells may increase substantially. In some cases, increased costs associated with increased regulation of hydraulic fracturing, or the prohibition of hydraulic fracturing, may result in wells being uneconomical to drill and operate that would otherwise be economical to drill and operate in the absence of such regulations or prohibitions. Should wells be determined to be uneconomical as a result of increasing regulation of hydraulic fracturing, we may be required to write-down or abandon oil and gas properties that are determined to be uneconomical to drill and develop. Additionally, potential litigation arising from alleged harm resulting from hydraulic fracturing may materially adversely affect our financial results and position regardless of whether we prevail on the merits of such litigation.

 

22
 

 

International Operations Risks

 

Our operations in Colombia are subject to uncertainty, delays and other risks relating to political and economic instability.

 

We currently have interests in multiple oil and gas concessions in Colombia and anticipate that operations in Colombia may constitute a substantial element of our strategy going forward.

 

The political climate in Colombia is unstable and could be subject to radical change over a very short period of time. While each of our past and current oil and gas concessions in Colombia have been granted by the federal government, we have experienced multiple extended delays in obtaining necessary permits to commence drilling operations on three of our four current concessions. The delays in obtaining necessary permits have been attributed to numerous factors beyond our control but not uncommon in Colombia, including strong local opposition to drilling operations based on environmental and other concerns. In the face of such opposition, our operator has shelved any near term drilling on the three concessions in question and is pursuing discussions with the federal government and local governments to determine if there are any viable options to drill those concessions or if acceptable arrangements can be made to compensate for the inability to drill and develop the concessions. Unless we are able to secure necessary permits or to secure substitute concessions, we may be forced to abandon or suspend our operations with respect to those concessions and record a loss of our entire investment in those concessions.

 

Armed conflict between government forces and anti-government insurgent groups and illegal paramilitary groups—both funded by the drug trade—has persisted in Colombia for more than 40 years with insurgents attacking civilians and violent guerilla activity continues in many parts of the country. During 2016, the government and the insurgents announced a peace accord to end hostilities. The peace accord was, however, rejected in a popular referendum. While the parties have expressed a continuing commitment to the peace process, until such process is finalized, any operations we may conduct in Colombia, and any assets we may hold in Colombia, may continue to be subject to risk associated with guerilla activity that may disrupt operations and result in losses from operations and of assets. There can also be no assurance that we can maintain the safety of our operations and personnel in Colombia or that this violence will not affect our operations in the future. Continued or heightened security concerns in Colombia could also result in a significant loss to us.

 

Where the local political climate and/or guerilla activity in an area threaten our ability to secure necessary support of the local populace or necessary permits to operate, or our ability to assure the safety of our personnel and/or assets, we have, in the past delayed, and may in the future delay, the commencement of operations on prospects until such concerns are satisfactorily resolved. While our operator works diligently with local and federal officials to overcome such uncertainties and obstacles, there can be no assurance that conditions in the vicinity of our planned operations will ever support exploration and/or development operations with respect to one or multiple prospects. Even though we have conducted successful operations on multiple prospects in Colombia, our current prospects continue to be characterized by political risks and, in fact, our operator has on more than one occasion delayed planned operations on prospects due to such political risks with such delays extending, in some cases, for multiple years. In the event of continued, or future, delays in operations on prospects arising from political risks, we may experience financial loss associated with our cost of holding prospects, the incurrence of costs associated with addressing political risks or the loss of value associated with our inability to explore and develop potentially valuable prospects.

 

Additionally, Colombia is among several nations whose eligibility to receive foreign aid from the United States is dependent on its progress in stemming the production and transit of illegal drugs, which is subject to an annual review by the President of the United States. Although Colombia is currently eligible for such aid, Colombia may not remain eligible in the future. A finding by the President that Colombia has failed demonstrably to meet its obligations under international counter-narcotics agreements may result in the loss of certain financial aid and the imposition of trade sanctions.

 

Each of these consequences could result in adverse economic consequences in Colombia and could further heighten the political and economic risks associated with our operations there. Any changes in the holders of significant government offices could have adverse consequences on our relationship with key governmental agencies and the Colombian government’s ability to control guerrilla activities and could exacerbate the factors relating to our foreign operations. Any sanctions imposed on Colombia by the United States government could threaten our ability to obtain necessary financing to develop the Colombian properties or cause Colombia to retaliate against us, including by nationalizing our Colombian assets. Accordingly, the imposition of the foregoing economic and trade sanctions on Colombia would likely result in a substantial loss and a decrease in the price of our common stock.

 

23
 

 

Our operations in Colombia are controlled by operators which may carry out transactions affecting our Colombian assets and operations without our consent.

 

Our operations in Colombia are subject to a substantial degree of control by the operators of the properties in which we hold indirect interests in Colombia. We are an investor in a number of ventures operated by Hupecol and our interest in the assets and operations of Hupecol related entities and ventures represent all of our current assets in Colombia. During 2008, 2010 and 2012, respectively, Hupecol sold its interest in multiple concessions and entities holding multiple concessions each representing, at the time, the largest prospect(s) in terms of reserves and revenues in which we then held an interest. In early March 2009, Hupecol determined to temporarily shut-in production from our Colombian properties. It is possible that Hupecol will carry out similar sales or acquisitions of prospects or make similar decisions in the future. Our management intends to closely monitor the nature and progress of future transactions by Hupecol in order to protect our interests. However, we have no effective ability to alter or prevent a transaction and are unable to predict whether or not any such transactions will in fact occur or the nature or timing of any such transaction.

 

We may be exposed to additional expenses and losses arising from the financial position of our joint interest partners in Colombia.

 

Our Colombian properties are developed under financial arrangements with various joint interest partners. If other joint interest partners are unable, or unwilling, to satisfy their various obligations relating to prospects, we may be required to pay a proportionately higher share of development costs on those prospects or the prospect may be inadequately capitalized to achieve optimal results.

 

We may be exposed to substantial fines and penalties if we or our partners fail to comply with laws and regulations associated with our activities in foreign countries, including Colombia, regarding U.S. laws such as the Foreign Corrupt Practices Act and local laws prohibiting corrupt payments to governmental officials and other corrupt practices.

 

Third parties act as the operator of each of our oil and gas wells and control all drilling and operating activities conducted with respect to our Colombian properties. Therefore, we have limited control over decisions related to activities on our properties, and we cannot provide assurance that our partners or their employees, contractors or agents will not take actions in violation of applicable anti-corruption laws and regulations. In the course of conducting business in Colombia, we have relied primarily on the representations and warranties made by our operating and non-operating partners in the farmout and joint operating agreements which govern our respective project interests to the effect that:

 

  each party has not and will not offer or make payments to any person, including a government official, that would violate the laws of the country of operations, the country of formation of any of the partners or the principals described in the Convention on Combating Bribery of Foreign Public Officials in International Business Transactions; and
     
  each party will maintain adequate internal controls, properly record and report all transactions and comply with the laws applicable to the transaction.

 

While we periodically inquire as to the continuing accuracy of these representations, as a minority non-operator, we are limited in our ability to assure compliance. Consequently, we cannot provide assurance that the procedural safeguards, if any, adopted by our partners or the representations and warranties contained in these agreements and our reliance on them will protect us from liability should a violation occur. Any violations of the anti-bribery, accounting controls or books and records provisions of the Foreign Corrupt Practices Act by us or our partners could subject us and, where deemed appropriate, individuals, in certain cases, to a broad range of civil and criminal penalties, including but not limited to, imprisonment, injunctive relief, disgorgement, substantial fines or penalties, prohibitions on our ability to offer our products in one or more countries, imposed modifications to business practices and compliance programs, including retention of an independent monitor to oversee compliance, and could also materially damage our reputation, our business and our operating results.

 

24
 

 

Stock Related Risks

 

The price of our common stock may fluctuate significantly, and this may make it difficult to resell common stock when, or at prices, desired.

 

The price of our common stock constantly changes. We expect that the market price of our common stock will continue to fluctuate.

 

Our stock price may fluctuate as a result of a variety of factors, many of which are beyond our control. These factors include:

 

  quarterly variations in our operating results;

 

  operating results that vary from the expectations of management, securities analysts and investors;

 

  changes in expectations as to our future financial performance;

 

  announcements by us, our partners or our competitors of leasing and drilling activities;

 

  the operating and securities price performance of other companies that investors believe are comparable to us;

 

  future sales of our equity or equity-related securities;

 

  changes in general conditions in our industry and in the economy, the financial markets and the domestic or international political situation;

 

  fluctuations in oil and gas prices;

 

  departures of key personnel; and

 

  regulatory considerations.

 

The stock market periodically experiences extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons often unrelated to their operating performance. These broad market fluctuations may adversely affect our stock price, regardless of our operating results.

 

The sale of a substantial number of shares of our common stock may affect our stock price.

 

We may require additional capital to support our future drilling plans and may issue additional shares of our common stock or equity-related securities to secure such capital. Future sales of substantial amounts of our common stock or equity-related securities in the public market or privately, or the perception that such sales could occur, could adversely affect prevailing trading prices of our common stock and could impair our ability to raise capital through future offerings of equity or equity-related securities. No prediction can be made as to the effect, if any, that future sales of shares of common stock or the availability of shares of common stock for future sale will have on the trading price of our common stock.

 

Item 1B. Unresolved Staff Comments

 

Not applicable.

 

Item 2. Properties

 

We currently lease approximately 4,739 square feet of office space in Houston, Texas as our executive offices. Management anticipates that our space will be sufficient for the foreseeable future. The average monthly rental under the lease, which expires on October 31, 2022, is approximately $11,000. A description of our interests in oil and gas properties is included in “Item 1. Business.”

 

Item 3. Legal Proceedings

 

We may from time to time be a party to lawsuits incidental to our business. As of March 29, 2021, we were not aware of any current, pending or threatened litigation or proceedings that could have a material adverse effect on our results of operations, cash flows or financial condition.

 

Item 4. Mine Safety Disclosures

 

Not applicable.

 

25
 

 

PART II

 

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

 

Market Information

 

Our common stock is listed on the NYSE American under the symbol “HUSA.”

 

Holders

 

As of March 29, 2021, there were approximately 876 shareholders of record of our common stock.

 

Securities Authorized for Issuance Under Equity Compensation Plans

 

The following table provides information as of December 31, 2020 with respect to the shares of our common stock that may be issued under our existing equity compensation plans.

 

Plan Category

 

Number of securities to be
issued upon exercise of outstanding
options, warrants and rights (a)

  

Weighted-average
exercise price of outstanding options,
warrants and rights (b)

  

Number of securities
remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))

 
Equity compensation plans approved by security holders (1)   730,973   $  5.07    533 
Equity compensation plans not approved by security holders (2)   54,000    1.45    446,000 
                
    784,973   $4.82    446,533 

 

 

(1) Consists of shares (a) reserved for issuance pursuant to outstanding options granted and (b) shares remaining available for future issuance; under the Houston American Energy Corp. 2017 Equity Incentive Plan.
(2) Consists of shares reserved for issuance and shares remaining available for grant under the Houston American Energy Corp. 2021 Equity Incentive Plan, all of which issuances are subject to approval of such plan by shareholders of Houston American Energy.

 

Item 6. Selected Financial Data

 

Not applicable.

 

26
 

 

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

 

General

 

We are an independent energy company focused on the development, exploration, exploitation, acquisition, and production of natural gas and crude oil properties with principal holdings in the U.S. Permian Basin and additional holdings in the U.S. Gulf Coast region and in the South American country of Colombia.

 

Our mission is to deliver outstanding net asset value per share growth to our investors via attractive oil and gas investments. Our strategy is to focus on early identification of, and opportunistic entrance into, existing and emerging resource plays. We do not operate wells but typically seek to partner with larger operators in development of resources or retain interests, with or without contribution on our part, in prospects identified, packaged and promoted to larger operators. By entering these plays earlier, identifying stranded blocks and partnering with, or promoting to, larger operators, we believe we can capture larger resource potential at lower cost and minimize our exposure to drilling risks and costs and ongoing operating costs.

 

We, along with our partners, actively manage our resources through opportunistic acquisitions and divestitures where reserves can be identified, developed, monetized and financial resources redeployed with the objective of growing reserves, production and shareholder value.

 

Generally, we generate nearly all our revenues and cash flows from the sale of produced natural gas and crude oil, whether through royalty interests, working interests or other arrangements. We may also realize gains and additional cash flows from the periodic divestiture of assets.

 

Recent Developments

 

Lease Activity

 

Permian Basin. In 2018, we acquired a 12.5% working interest, subject to a proportionate 10% back-in after payout, in an approximately 650-acre lease block in Yoakum County, Texas. The acreage lay in the Midland Basin region of the larger Permian Basin. During 2020, we acquired a 100% working interest in 46.1 acres adjoining our Yoakum County acreage. Pursuant to an area of mutual interest agreement among the partners in our Yoakum County acreage, we will offer to our partners the right to participate in the 46.1-acre block.

 

In 2019, we acquired, for $587,100, a 20% working interest in an approximately 5,871-acre lease block in the Northern Shelf of the Permian Basin in Texas. We were required to pay 26.667% of costs on the initial well on the block through the point at which the well is drilled, completed, equipped and ready for operation, production or disposal. Pursuant to the agreement to acquire such interest, we also secured the right to participate, at cost and for a period of five years, in a 20,367-acre area of mutual interest (the “Hockley County AMI”), including the acquired lease block. During 2020, pursuant to our rights with respect to the Hockley County AMI, we acquired a 20% working interest in two blocks totaling 820 gross acres. After giving effect to such acquisitions and various lease expirations within the block, our acreage position in the Northern Shelf of the Permian Basin covered approximately 5,080 gross acres at December 31, 2020.

 

In 2020, we experienced a lease expiration with respect to undeveloped acreage in Reeves County, Texas, reducing our acreage holdings to 480 gross acres at December 31, 2020.

 

Louisiana. In 2020, we sold our interest in two marginal wells and associated acreage in Louisiana for nominal consideration and relief from plugging and abandonment liability. Also during 2020, the lease pertaining to acreage associated with our Crown Paper #01 well in East Baton Rouge Parish, Louisiana was amended reducing our royalty interest with respect to the acreage to 20%.

 

Colombia. In 2019, we acquired a 2% interest in Hupecol Meta, LLC (“Hupecol Meta”) (the “Hupecol Meta Acquisition”). Pursuant to the terms of the Hupecol Meta Acquisition, we paid total consideration of approximately $197,000. During 2020, we invested an additional $63,405 in Hupecol Meta. In early 2021, we agreed to contribute an additional $99,716 to Hupecol Meta, increasing our ownership interest to 7.85%.

 

Hupecol Meta holds a working interest in the 639,405 gross acre CPO-11 block in the Llanos Basin in Colombia, comprised of the 69,128 acre Venus Exploration Area and 570,277 acres, which was 50% farmed out by Hupecol Meta. As a result of Hupecol Meta’s 2021 purchase of additional interest in the CPO-11 block and our agreement to increase our ownership interest in Hupecol Meta, through our membership interest in Hupecol Meta, we will hold a 6.99% interest in the Venus Exploration Area and a 3.495% interest in the remainder of the block.

 

27
 

 

Drilling Activity and Well Operations

 

During 2020, we drilled the Frost #2H well in Yoakum County, Texas, reaching total depth of approximately 10,230 feet, including an approximately 5,363-foot horizontal leg. The well was fractured, production facilities constructed and the well came on production in September 2020 at which time oil production commenced while the well commenced unloading of frac fluid.

 

During 2020, we drilled the Lou Brock #1-H well in Hockley County, Texas, reaching total depth of approximately 10,750 feet, including an approximately 5,950-foot horizontal leg. As a result of hydraulic fracturing, the well has been shut-in pending evaluation of options to remedy those issues.

 

During 2020, Hupecol Meta drilled the 5,658-foot Montuno-1 vertical well on the CPO-11 block in Colombia. The drilling operation resulted in a dry hole.

 

During 2020, the O’Brien #3-H well in Reeves County, Texas was shut-in for repairs for approximately five months and was shut-in at year-end.

 

During 2020, the Crown Paper #01 well, in East Baton Rouge Parish, Louisiana, underwent a failed rework. The well operator has proposed to recomplete the well in a different zone. We hold a royalty interest in the subject acreage.

 

Capital Investments

 

During 2020, our capital investment expenditures for acreage acquisitions, drilling, completion and related operations, as well as investments in Hupecol Meta, totaled $1,573,272, principally relating to acreage in the Permian Basin.

 

Reverse Stock Split

 

In July 2020, we amended our Certificate of Incorporation to effect a 1-for-12.5 reverse split (the “Reverse Split”) of our common stock. All references to shares of common stock and per share data for all periods in this Management Discussion and Analysis of Financial Condition and Results of Operations have been adjusted to reflect the Reverse Split on a retroactive basis for all periods presented in the financial statements.

 

Financing Activities

 

During 2019, 2020 and early 2021, we undertook the following financing activities to support our acquisitions of additional acreage positions and to support drilling operations:

 

2019 At-the-Market Offering. In May 2019, we entered into an At-the-Market Issuance Sales Agreement (the “Sales Agreement”) with WestPark Capital pursuant to which we could sell, at our option, up to an aggregate of $5.2 million in shares of common stock through WestPark Capital, as sales agent. Sales of shares under the Sales Agreement (the “2019 ATM Offering”) were made, in accordance with placement notices delivered to WestPark Capital, which notices set parameters under which shares could be sold. The 2019 ATM Offering was made pursuant to a shelf registration statement by methods deemed to be “at the market,” as defined in Rule 415 promulgated under the Securities Act of 1933. We paid WestPark a commission in cash equal to 3% of the gross proceeds from the sale of shares in the 2019 ATM Offering. Additionally, we reimbursed WestPark Capital for $18,000 of expenses incurred in connection with the 2019 ATM Offering.

 

During 2019, we sold an aggregate of 277,800 shares in the 2019 ATM Offering and received proceeds, net of commissions, of $606,960. During 2020, we sold an aggregate of 1,684,760 shares in the 2019 ATM Offering and received proceeds, net of commissions and expenses, of $4,375,594 and collected $58,575 of subscriptions receivable attributable to shares sold under the 2019 ATM Offering during 2019.

 

2021 At-the-Market Offering. In January 2021, we entered into a Sales Agreement with Univest Securities, LLC (“Univest”) pursuant to which we could sell, at our option, up to an aggregate of $4,768,428 in shares of common stock through Univest, as sales agent. Sales of shares under the Sales Agreement (the “2021 ATM Offering”) were made, in accordance with placement notices delivered to Univest, which notices set parameters under which shares could be sold. The 2021 ATM Offering was made pursuant to a shelf registration statement by methods deemed to be “at the market,” as defined in Rule 415 promulgated under the Securities Act of 1933. We paid Univest a commission in cash equal to 3% of the gross proceeds from the sale of shares in the 2021 ATM Offering. Additionally, we reimbursed Univest for $18,000 of expenses incurred in connection with the 2021 ATM Offering.

 

28
 

 

During January 2021, we sold an aggregate of 2,108,520 shares in the 2021 ATM Offering and received proceeds, net of commissions, of $4,625,361.

 

2021 Supplemental At-the-Market Offering. In February 2021, we entered into a second Sales Agreement with Univest pursuant to which we could sell, at our option, up to an aggregate of $2,030,000 in shares of common stock through Univest, as sales agent. Sales of shares under the Sales Agreement (the “2021 Supplemental ATM Offering”) were made, in accordance with placement notices delivered to Univest, which notices set parameters under which shares could be sold. The 2021 Supplemental ATM Offering was made pursuant to a shelf registration statement by methods deemed to be “at the market,” as defined in Rule 415 promulgated under the Securities Act of 1933. We paid Univest a commission in cash equal to 3% of the gross proceeds from the sale of shares in the 2021 Supplemental ATM Offering. Additionally, we reimbursed Univest for $18,000 of expenses incurred in connection with the 2021 Supplemental ATM Offering.

 

During February 2021, we sold an aggregate of 813,100 shares in the 2021 Supplemental ATM Offering and received proceeds, net of commissions, of $1,969,092.

 

Conversion and Redemption of Preferred Stock. In February 2021, 60 shares of 12% Series A Convertible Preferred Stock were converted into 24,000 shares of our common stock and we redeemed all remaining outstanding shares of our 12% Series A Convertible Preferred Stock and 12% Series B Convertible Preferred Stock for $1.97 million plus accrued dividends totaling $32,700.

 

Bridge Loan Financing. In September 2019, we issued promissory notes (the “Bridge Loan Notes”) with a total principal amount of $621,052, an original issue discount of 5%, warrants (the “Bridge Loan Warrants”) to purchase 1,180,000 shares of common stock, and a term of 120 days. Net proceeds received for the Bridge Loan Notes and Warrants totaled $590,000.

 

The Bridge Loan Notes were unsecured obligations bearing interest at 12.0% per annum and payable interest only on the last day of each calendar month with any unpaid principal and accrued interest being payable in full on January 16, 2020.

 

The Bridge Loan Notes were subject to mandatory prepayment from and to the extent of (i) 100% of net proceeds we receive from any sales, for cash, of equity or debt securities (other than Bridge Loan Notes), (ii) 100% of net proceeds we receive from the sale of assets (other than sales in the ordinary course of business); and (iii) 75% of net proceeds we receive from the sale of oil and gas produced from our Hockley County, Texas properties. Additionally, we had the option to prepay the Bridge Loan Notes, at our sole election, without penalty. The holders of the Bridge Loan Notes waived mandatory prepayment at the end of each month during 2019.

 

The Bridge Loan Notes were recorded net of debt discount that consists of (i) $31,052 of original issue discount on the Bridge Loan Notes and (ii) the relative fair value of the Bridge Loan Warrants of $144,948. The debt discount is amortized over the life of the Bridge Loan Notes as additional interest expense.

 

During 2019 and 2020, interest expense paid in cash totaled $21,439 and $3,350, respectively, and interest expense attributable to amortization of debt discount totaled $152,533 and $23,467, respectively. The Bridge Loan Notes were repaid in full in January 2020.

 

The holders of the Bridge Loan Notes were our Chief Executive Officer and a 10% shareholder.

 

OID Promissory Note. In October 2019, we issued a promissory note (the “OID Note”) with a principal amount of $100,000 and an original issue discount of 10%. Net proceeds received for the OID Note totaled $90,000.

 

The OID Note was an unsecured obligation bearing interest at 0% per annum and payable from any and all of our cash receipts with any unpaid principal and accrued interest being payable in full on October 31, 2019. The OID Note was repaid in full as of October 31, 2019.

 

The holder of the OID Note was a 10% shareholder of the Company.

 

Recovery of Escrow Account

 

In 2010, we, and our operator in Colombia, Hupecol, sold our interests in two entities in Colombia. Pursuant to the terms of those sales, a portion of the sales price was escrowed to secure certain representations of the selling parties. Our share of amounts escrowed was recorded as escrow receivables.

 

29
 

 

In 2016, we recorded an allowance in the amount of $262,016 relating to the undisbursed balance of escrow receivables.

 

In 2020, we received payments totaling $164,706, net, representing recoveries of escrowed funds relating to the previously written-off escrow receivables. As a result of the receipt of such funds, we recorded non-recurring other income in the amount of $164,706 in 2020.

 

COVID-19

 

In early 2020, global health care systems and economies began to experience strain from the spread of the COVID-19 Coronavirus. As the virus spread, global economic activity began to slow and future economic activity was forecast to slow with a resulting decline in oil and gas demand and prices. Such decline in prices adversely affected our revenues and profitability in 2020 and, if price declines persist, will adversely affect the economics of our existing wells and planned future wells, possibly resulting in impairment charges to existing properties and delaying or abandoning planned drilling operations as uneconomical.

 

In response to the COVID-19 pandemic, our staff has begun working remotely and many of our key vendors, service suppliers and partners have similarly begun to work remotely. As a result of such remote work arrangements, we anticipate that certain operational, reporting, accounting and other processes will slow which may result in longer time to execute critical business functions, higher operating costs and uncertainties regarding the quality of services and supplies, any of which could substantially adversely affect our operating results for as long as the current pandemic persists and potentially for some time after the pandemic subsides.

 

Critical Accounting Policies

 

The following describes the critical accounting policies used in reporting our financial condition and results of operations. In some cases, accounting standards allow more than one alternative accounting method for reporting. Such is the case with accounting for oil and gas activities described below. In those cases, our reported results of operations would be different should we employ an alternative accounting method.

 

Full Cost Method of Accounting for Oil and Gas Activities. We follow the full cost method of accounting for oil and gas property acquisition, exploration and development activities. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisition, geological and geophysical work, delay rentals, costs of drilling, completing and equipping successful and unsuccessful oil and gas wells and related internal costs that can be directly identified with acquisition, exploration and development activities, but does not include any cost related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized unless significant amounts of oil and gas reserves are involved. No corporate overhead has been capitalized as of December 31, 2020. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves, are amortized on a units-of-production method over the estimated productive life of the reserves. Unevaluated oil and gas properties are excluded from this calculation. The capitalized oil and gas property costs, less accumulated amortization, are limited to an amount (the ceiling limitation) equal to the sum of: (a) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, calculated using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (b) the cost of unproved and unevaluated properties excluded from the costs being amortized; (c) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (d) related income tax effects. Costs in excess of this ceiling are charged to proved properties impairment expense.

 

Revenue recognition. On January 1, 2018, we adopted the new revenue guidance using the modified retrospective method for contracts that were not complete at December 31, 2017. ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)”, supersedes the revenue recognition requirements and industry-specific guidance under Revenue Recognition (Topic 605). Topic 606 requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. We adopted Topic 606 on January 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. Under the modified retrospective method, prior period financial positions and results are not adjusted. The cumulative effect adjustment recognized in the opening balances included no significant changes as a result of this adoption. While our 2018 net earnings were not materially impacted by revenue recognition timing changes, Topic 606 requires certain changes to the presentation of revenues and related expenses beginning January 1, 2018.

 

30
 

 

Our revenue is comprised principally of revenue from exploration and production activities. Our oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery.

 

Contracts with customers have varying terms, including spot sales or month-to-month contracts, contracts with a finite term, and life-of-field contracts where all production from a well or group of wells is sold to one or more customers. We recognize sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs.

 

Revenues are recognized for the sale of our net share of production volumes.

 

Unevaluated Oil and Gas Properties. Unevaluated oil and gas properties consist principally of our cost of acquiring and evaluating undeveloped leases, net of an allowance for impairment and transfers to depletable oil and gas properties. When leases are developed, expire or are abandoned, the related costs are transferred from unevaluated oil and gas properties to oil and gas properties subject to amortization. Additionally, we review the carrying costs of unevaluated oil and gas properties for the purpose of determining probable future lease expirations and abandonments, and prospective discounted future economic benefit attributable to the leases.

 

Unevaluated oil and gas properties not subject to amortization include the following at December 31, 2019 and 2020:

 

  

At
December 31,
2019

  

At
December 31,
2020

 
Acquisition costs  $279,177   $1,647,196 
Evaluation costs   2,199,279    2,334,609 
           
Total  $2,478,456   $3,981,805 

 

The carrying value of unevaluated oil and gas prospects includes $2,343,126 and $2,343,126 expended for properties in South America at December 31, 2019 and 2020, respectively. We are maintaining our interest in these properties.

 

Stock-Based Compensation. We use the Black-Scholes option-pricing model, which requires the input of highly subjective assumptions. These assumptions include estimating the volatility of our common stock price over the expected life of the options, dividend yield, an appropriate risk-free interest rate and the number of options that will ultimately not complete their vesting requirements. Changes in the subjective assumptions can materially affect the estimated fair value of stock-based compensation and consequently, the related amount recognized on the Statements of Operations.

 

31
 

 

Results of Operations

 

Year Ended December 31, 2020 Compared to Year Ended December 31, 2019

 

Oil and Gas Revenues. Total oil and gas revenues decreased 45% to $552,345 in 2020 from $997,992 in 2019. The decrease in revenues was attributable to a combination of lower production, lower average prices realized from oil and gas sales and decreased royalties from our Crown Paper well.

 

The following table sets forth the gross and net producing wells, net oil and gas production volumes and average hydrocarbon sales prices for 2019 and 2020:

 

   2019   2020 
Gross producing wells   4    4 
Net producing wells   0.49    0.68 
Net oil production (Bbls)   13,674    11,385 
Net gas production (Mcf)   116,629    69,433 
Oil—Average sales price per barrel  $55.73   $35.63 
Gas—Average sales price per mcf  $2.02   $1.14 

 

The change in gross/net producing wells resulted from cessation of operation, and the ultimate sale, of two uneconomical wells in Louisiana, offset by the commencement of operations of two wells in Yoakum County, Texas. The decrease in production was principally attributable to the shut-in of our O’Brien #3-H well for repair and natural decline in production from our Reeves County, Texas wells, partially offset by production from two Yoakum County wells commencing in mid-2019 and the last week of the 2020 third quarter.

 

The change in average sales prices realized reflects the steep decline, and partial recovery, in global commodity prices associated with a decline in energy demand associated with the COVID-19 pandemic.

 

Royalties from our Crown Paper well decreased from approximately $28,558 in 2019 to $13,875 in 2020. The Crown Paper well underwent an unsuccessful rework in October 2020. No future royalties are expected from the Crown Paper well unless and until the well is successfully recompleted by the operator.

 

All oil and gas sales and royalty revenues are attributable to U.S. operations.

 

Lease Operating Expenses. Lease operating expenses decreased 49% to $403,974 in 2020 from $789,708 in 2019.

 

The decrease in lease operating expenses was attributable to reduced production and reduced severance taxes due to lower sales.

 

All lease operating expenses during 2019 and 2020 were attributable to U.S. operations.

 

Depreciation and Depletion Expense. Depreciation and depletion expense decreased by 17% to $364,810 in 2020 from $438,553 in 2019. The decrease in depreciation and depletion during 2020 was due to a decline in production volumes partially offset by an increase in capitalized costs subject to amortization and commencement of production from our Yoakum County, Texas wells.

 

Impairment Expense. Impairment expense totaled $2,519,032 in 2020 compared to $745,691 in 2019. The impairment expense for both periods was due to a decrease in the market price of oil and gas as well as downward adjustments to the projected future production from our wells.

 

General and Administrative Expenses (Excluding Stock-Based Compensation). General and administrative expense decreased by 25% to $1,012,717 in 2020 from $1,357,723 in 2019. The change in general and administrative expense was primarily attributable to a decrease in insurance expense, partially offset by increased exchange listing fees and professional fees.

 

Stock-Based Compensation. Stock-based compensation increased to $434,581 in 2020 from $156,091 in 2019. The change was attributable to the issuance of fully vested stock options during 2020.

 

32
 

 

Other Income (Expense). Other income/expense, net, totaled $145,695 of income during 2020, compared to $182,011 of expense during 2019. Other income during 2020 consisted of $12,748 of interest earned on cash balances and $164,706 of other income arising from the recovery of escrowed funds previously written-off, partially offset by interest expense of $31,759 relating to the Bridge Loan Notes. Other expense during 2019 consisted of $1,961 of interest income, offset by interest expense of $183,972 relating to the Bridge Loan Notes and the OID Note.

 

Financial Condition

 

Liquidity and Capital Resources. At December 31, 2020, we had a cash balance of $1,242,560 and working capital of $1,142,512, compared to a cash balance of $97,915 and a deficit in working capital of $748,426 at December 31, 2019.

 

Cash Flows. Operating activities used cash of $864,787 during 2020, compared to $725,019 used during 2019. The change in cash flows from operating activities was attributable to changes in net operating assets and liabilities partially offset by a reduction in cash expenses that exceeded the decline in revenues.

 

Investing activities used cash of $1,571,785 during 2020, compared to $889,328 used during 2019. The increase in cash used in investing activities reflects increased development and acquisition costs, which, during 2020, included the cost of acquisition, evaluation, and development of U.S. properties ($1,503,349), attributable to acreage acquired in the Northern Shelf of the Permian Basin in Texas, (2) drilling and development operations in the U.S. Permian Basin ($6,527), and (3) investments in Hupecol Meta relating to drilling operations in Colombia ($63,396), partially offset by cash proceeds from the sale of certain oil and gas properties ($1,487). During 2019, our development and acquisition costs totaled $692,319 and the acquisition of our interest in the Hupecol Meta LLC cost $197,009.

 

Financing activities provided cash of $3,581,217 during 2020, compared to $956,560 provided during 2019. During 2020, cash provided by financing activities was attributable to funds received from the sale of common stock under our 2019 ATM Offering, totaling $4,434,169, partially offset by repayment of Bridge Loan Notes in the amount of $621,052 and payment of dividends on our preferred stock of $231,900. During 2019, cash provided by financing activities consisted of sales of common stock in our 2019 ATM Offering of $606,960, sales of Bridge Loan Notes of $590,000 and sales of the OID Note of $90,000, partially offset by distributions with respect to outstanding preferred stock of $230,400 and repayment of the OID Note of $100,000.

 

Long-Term Liabilities. At December 31, 2020, we had long-term liabilities of $171,791, compared to $263,596 at December 31, 2019. Long-term liabilities, as of December 31, 2020, consisted of a reserve for plugging costs of $63,929 and a lease liability of $107,862.

 

Capital and Exploration Expenditures and Commitments. Our principal capital and exploration expenditures relate to ongoing efforts to acquire, drill and complete prospects, in particular our Permian Basin acreage and our newly acquired Colombian acreage. Given the current economic environment and the current COVID-19 pandemic, all planned additional acquisition, drilling and development operations were deferred from March 2020 through June 30, 2020 pending improved conditions. We selectively resumed acquisition, drilling and development operations during the third quarter of 2020 with the acquisition in July 2020, for $33,228, of a 20% working interest in additional acreage in Hockley County, fracking operations on our Frost #2H well, the commencement of drilling operations on our San Andres acreage, and the acquisition in October 2020, for $25,194, of a 20% interest in further additional acreage in Hockley County. The actual timing and number of well operations undertaken during 2021 will be principally controlled by the operators of our acreage, based on a number of factors, including but not limited to availability of financing, performance of existing wells on the subject acreage, energy prices and industry condition and outlook, costs of drilling and completion services and equipment and other factors beyond our control or that of our operators.

 

During 2020, we invested $1,573,272 for the acquisition and development of oil and gas properties, consisting of (1) cost of acquisition, evaluation, and development of U.S. properties ($1,503,349), attributable to acreage acquired in the Northern Shelf of the Permian Basin in Texas, (2) drilling and development operations in the U.S. Permian Basin ($6,527), and (3) investments in Hupecol Meta relating to drilling operations in Colombia ($63,396). Of the amount invested, we capitalized $1,503,349 to oil and gas properties not subject to amortization, capitalized $6,527 to oil and gas properties subject to amortization and capitalized $63,396 as additional investment in Hupecol Meta.

 

As our allocable share of well costs will vary depending on the timing and number of wells drilled as well as our working interest in each such well and the level of participation of other interest owners, we have not established a drilling budget but will budget on a well-by-well basis as our operators propose wells.

 

With our receipt, during 2020, of $4.4 million from sales of common stock under our 2019 ATM Offering and our receipt in early 2021 of $6.5 million from sales of common stock under our 2021 ATM Offering and 2021 Supplemental ATM Offering, we believe that we have the ability, through our cash on-hand, to fund operations and our cost for all planned wells expected to be drilled during 2021. We used a portion of those funds in early 2021 to fund redemption of our 12% Series A Convertible Preferred Stock and 12% Series B Convertible Preferred Stock at an approximate cost of $1.97 million.

 

33
 

 

In the event that we pursue additional acreage acquisitions or expand our drilling plans, we may be required to secure additional funding beyond our resources on hand. While we may, among other efforts, seek additional funding from “at-the-market” sales of common stock, and private sales of equity and debt securities, we presently have no commitments to provide additional funding, and there can be no assurance that we can secure the necessary capital to fund our share of drilling, acquisition or other costs on acceptable terms or at all. If, for any reason, we are unable to fund our share of drilling and completion costs and fail to satisfy commitments relative to our interest in our acreage, we may be subject to penalties or to the possible loss of some of our rights and interests in prospects with respect to which we fail to satisfy funding commitments and we may be required to curtail operations and forego opportunities. Unless and until the depressing economic effects of the coronavirus recede, we expect that new capital to fund projects will be difficult, if not impossible, to secure.

 

Contractual Obligations. At December 31, 2020, our only material contractual obligation requiring determinable future payments on our part was our lease relating to our executive offices.

 

The following table details our contractual obligations as of December 31, 2020:

 

  

Payments due by period

 
  

Total

  

<1 year

  

1-3 years

  

3-5 years

  

>5 years

 
Operating leases  $245,638   $133,087   $112,551   $   $ 
Total  $245,638   $133,087   $112,551   $   $ 

 

In addition to the contractual obligations requiring that we make fixed payments, in conjunction with our efforts to secure oil and gas prospects, financing and services, we have, from time to time, granted overriding royalty interests (“ORRI”) in various properties, and may grant ORRIs in the future, pursuant to which we will be obligated to pay a portion of our interest in revenues from various prospects to third parties. Our Permian Basin acreage is subject to a ORRI’s ranging from 1% to 2%, in aggregate, in favor of current and former employees and officers. All present and future prospects in Colombia are subject to a 1.5% ORRI in favor of each of a current employee and a former director.

 

Off-Balance Sheet Arrangements

 

We had no off-balance sheet arrangements or guarantees of third party obligations at December 31, 2020.

 

Inflation

 

We believe that inflation has not had a significant impact on our operations since inception.

 

34
 

 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

 

Commodity Price Risk

 

The price we receive for our oil and gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Crude oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and gas have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for production depends on numerous factors beyond our control.

 

We have not historically entered into any hedges or other derivative commodity instruments or transactions designed to manage, or limit exposure to oil and gas price volatility.

 

Item 8. Financial Statements and Supplementary Data

 

Our financial statements appear immediately after the signature page of this report. See “Index to Financial Statements” on page F-1.

 

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

 

Not applicable.

 

Item 9A. Controls and Procedures

 

Disclosure Controls and Procedures

 

Under the supervision and with the participation of our management, including our principal executive who also serves as our principal financial officer, we conducted an evaluation as of December 31, 2020 of the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer concluded that our disclosure controls and procedures were not effective as of December 31, 2020.

 

Management’s Annual Report on Internal Control Over Financial Reporting

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of management, including our principal executive officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the 2013 framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this evaluation under the COSO Framework, management concluded that our internal control over financial reporting was not effective as of December 31, 2020. Such conclusion reflects our chief executive officer’s assumption of duties of the principal financial officer and the resulting lack of segregation of duties. Until we are able to remedy this material weakness, we are relying on third party consultants to assist with financial reporting.

 

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit smaller reporting companies to provide only management’s report in this annual report.

 

Changes in Internal Control Over Financial Reporting

 

There was no change in our internal control over financial reporting during the fourth quarter of 2020 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

Item 9B. Other Information

 

Not applicable

 

35
 

 

PART III

 

Item 10. Directors, Executive Officers and Corporate Governance

 

The information required by this Item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after the close of our fiscal year. Such information is incorporated herein by reference.

 

Executive Officers

 

Our executive officers as of December 31, 2020, and their ages and positions as of that date, are as follows:

 

Name

 

Age

 

Position

John Terwilliger   73   President and Chief Executive Officer

 

John Terwilliger has served as our President and CEO, and as a director, since December 2020. Mr. Terwilliger is the company’s founder and served as its President, Chief Executive Officer and Chairman of the Board from 2001 to 2015 and continued, in a non-executive role, to provide oil and gas prospect and operations services to the company from 2015 until his appointment as an officer in 2020. Mr. Terwilliger has more than 40 years’ experience in oil and gas management and operations.

 

There are no family relationships among the executive officers and directors. Except as otherwise provided in employment agreements, each of the executive officers serves at the discretion of the Board.

 

Item 11. Executive Compensation

 

The information required by this Item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after the close of our fiscal year. Such information is incorporated herein by reference.

 

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

 

The information required by this Item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after the close of our fiscal year. Such information is incorporated herein by reference.

 

Equity compensation plan information is set forth in Part II, Item 5 of this Form 10-K.

 

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

 

The information required by this Item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after the close of our fiscal year. Such information is incorporated herein by reference.

 

Item 14. Principal Accountant Fees and Services

 

The information required by this Item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after the close of our fiscal year. Such information is incorporated herein by reference.

 

 

36
 

 

PART IV

 

Item 15. Exhibits and Financial Statement Schedules

 

1. Financial statements. See “Index to Financial Statements” on page F-1.
   
2. Exhibits

 

Exhibit      

Incorporated by Reference

  Filed

Number

 

Exhibit Description

 

Form

 

Date

 

Number

 

Herewith

1.1   At-the-Market Issuance Sales Agreement, dated May 9, 2019, by and between Houston American Energy Corp. and WestPark Capital, Inc.   8-K   05/09/19   1.1    
                     
1.2   At-the-Market Issuance Sales Agreement, dated January 26, 2021, by and between Houston American Energy Corp. and Univest Securities, LLC   8-K   01/27/21   1.1    
                     
1.3   At-the-Market Issuance Sales Agreement, dated February 3, 2021, by and between Houston American Energy Corp. and Univest Securities, LLC   8-K   02/03/21   1.1    
                     
3.1   Certificate of Incorporation of Houston American Energy Corp. filed April 2, 2001   SB-2   08/03/01   3.1    
                     
3.2   Amended and Restated Bylaws of Houston American Energy Corp. adopted November 26, 2007   8-K   11/29/07   3.1    
                     
3.3   Certificate of Amendment to the Certificate of Incorporation of Houston American Energy Corp. filed September 25, 2001   SB-2   10/01/01   3.4    
                     
3.4   Certificate of Amendment to the Certificate of Incorporation of Houston American Energy Corp. filed July 21, 2020   8-K   07/17/20   3.1    
                     
4.1   Text of Common Stock Certificate of Houston American Energy Corp.   SB-2   08/03/01   4.1    
                     
4.2   Certificate of Designations of 12.0% Series A Convertible Preferred Stock   8-K   02/02/17   4.1    
                     
4.3   Certificate of Designations of 12.0% Series B Convertible Preferred Stock   8-K   05/08/17   4.1    
                     
10.1   Form of 2019 Bridge Loan Agreement   8-K   09/20/19   10.1    
                     
10.2   Form of 2019 Bridge Loan Note   8-K   09/20/19   10.2    
                     
10.3   Form of 2019 Warrant   8-K   09/20/19   10.3    
                     
10.4   Houston American Energy Corp. 2008 Equity Incentive Plan*   Sch 14A   04/28/08   Ex A    
                     
10.5   Houston American Energy Corp. 2017 Equity Incentive Plan*   Sch 14A   07/24/17   Ex A    
                     
10.6   Form of Change in Control Agreement, dated June 11, 2012*   8-K   06/14/12   10.1    
                     
10.7   Production Incentive Compensation Plan*   10-Q   08/14/13   10.1    
                     
14.1   Code of Ethics for CEO and Senior Financial Officers   10-KSB   03/26/04   14.1    
                     
23.1   Consent of Marcum, LLP               X
                     
23.2   Consent of Russell K. Hall & Associates, Inc.               X
                     
31.1   Section 302 Certification of CEO and CFO               X
                     
32.1   Section 906 Certification of CEO and CFO               X
                     
99.1   Code of Business Ethics   8-K   07/07/06   99.1    
                     
99.2   Report of Russell K. Hall & Associates, Inc.               X

 

 

* Compensatory plan or arrangement.

 

Item 16.Form 10-K Summary

 

Not applicable

 

37
 

 

SIGNATURES

 

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

 

    HOUSTON AMERICAN ENERGY CORP.
Dated: March 31, 2021  
    By: /s/ John Terwilliger
     

John Terwilliger

President

 

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

 

Signature   Title   Date
/s/ John Terwilliger   Chief Executive Officer, President and Director    
John Terwilliger   (Principal Executive Officer and Principal Financial Officer)   March 31, 2021
         
/s/ James Schoonover   Director   March 31, 2021
James Schoonover        
         
/s/ Stephen Hartzell   Director   March 31, 2021
Stephen Hartzell        
         
/s/ Keith Grimes   Director   March 31, 2021
Keith Grimes        

 

38
 

 

HOUSTON AMERICAN ENERGY CORP.

INDEX TO FINANCIAL STATEMENTS

 

Report of Independent Registered Public Accounting Firm F-2
   
Consolidated Balance Sheets as of December 31, 2020 and 2019 F-3
   
Consolidated Statements of Operations for the Years Ended December 31, 2020 and 2019 F-4
   
Consolidated Statement of Changes in Shareholders’ Equity for the Years Ended December 31, 2020 and 2019 F-5
   
Consolidated Statements of Cash Flows for the Years Ended December 31, 2020 and 2019 F-6
   
Notes to Consolidated Financial Statements F-7

 

F-1
 

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Stockholders and the Board of Directors of

Houston American Energy Corp.

 

Opinion on the Financial Statements

 

We have audited the accompanying consolidated balance sheets of Houston American Energy Corp. (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of operations, stockholders’ equity and cash flows for each of the years ended December 31, 2020 and 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the years ended December 31, 2020 and 2019, in conformity with accounting principles generally accepted in the United States of America.

 

Basis for Opinion

 

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

 

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

 

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

 

Critical Audit Matters

 

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

 

Depreciation, depletion and amortization and impairment of oil and gas properties

 

At December 31, 2020, the net carrying value of the Company’s oil and gas properties was $5.0 million, depreciation, depletion and amortization (“DD&A”) expense was $0.4 million, and impairment expense was $2.5 million for the year then ended. As described in Note 1, the Company follows the full cost method of accounting for its oil and gas properties. DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method based on proved oil and gas reserves, as estimated by the Company’s internal and external reservoir engineers. Under the full cost method, a ceiling test is performed each quarter. The ceiling test determines a limit, on a country-by-country basis, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated DD&A, impairment, and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves. If capitalized costs exceed this limit, the capitalized cost is reduced to fair value.

 

Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and natural gas liquids, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Additionally, the expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of future production volumes from estimated oil and gas reserves. Significant judgment is required by the Company’s internal and external reservoir engineers in evaluating geological and engineering data when estimating oil and gas reserves. Estimating reserves also requires the selection of inputs, including oil and gas price assumptions, future operating and capital costs assumptions, and tax rates by jurisdiction, among others. Because of the complexity involved in estimating oil and gas reserves, management engaged independent petroleum engineers to prepare the proved oil and gas reserve estimates for select properties as of December 31, 2020.

 

Auditing the Company’s DD&A and impairment calculations is complex because of the use of the work of the internal reservoir engineers and the independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating oil and gas reserves.

 

We obtained an understanding of the Company’s controls over its process to calculate DD&A and impairment, including management’s controls over the completeness and accuracy of the financial data provided to the engineers for use in estimating oil and gas reserves.

 

Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the independent petroleum engineers primarily responsible for the preparation of the reserve estimates for select properties. In addition, in assessing whether we can use the work of the engineers, we evaluated the completeness and accuracy of the financial data and inputs described above used by the engineers in estimating oil and gas reserves by agreeing them to source documentation, and we identified and evaluated corroborative and contrary evidence. For proved undeveloped reserves, we evaluated management’s development plan for compliance with the SEC rule that undrilled locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time, by assessing consistency of the development projections with the Company’s development plan and the availability of capital relative to the development plan. We also tested the mathematical accuracy of the DD&A and impairment calculations, including comparing the oil and gas reserve amounts used in the calculations to the Company’s reserve reports.

 

/s/ Marcum LLP  
   
Marcum LLP  
   
We have served as the Company’s auditor since 2010.  
   
Houston, Texas  
March 31, 2021  

 

F-2
 

 

HOUSTON AMERICAN ENERGY CORP.

CONSOLIDATED BALANCE SHEETS

 

   December 31, 
  

2019

  

2020

 
ASSETS        
CURRENT ASSETS          
Cash  $97,915   $1,242,560 
Accounts receivable – oil and gas sales   80,195    95,763 
Prepaid expenses and other current assets   39,505    35,845 
           
TOTAL CURRENT ASSETS   217,615    1,374,168 
           
PROPERTY AND EQUIPMENT          
Oil and gas properties, full cost method          
Costs subject to amortization   61,068,240    61,089,737 
Costs not being amortized   2,478,456    3,981,805 
Office equipment   90,004    90,004 
           
Total   63,633,534    65,161,546 
Accumulated depletion, depreciation, amortization, and impairment   (57,267,145)   (60,150,988)
           
PROPERTY AND EQUIPMENT, NET   6,369,555    5,010,558 
           
Cost method investment   197,009    260,405 
Right of use asset   281,489    194,123 
Other assets   3,167    3,167 
           
TOTAL ASSETS  $7,068,835   $6,842,421 
           
LIABILITIES AND SHAREHOLDERS’ EQUITY          
CURRENT LIABILITIES          
Accounts payable  $270,119   $120,140 
Accrued expenses   447    939 
Notes payable – related party, net of debt discount   597,585     
Short-term lease liability   97,890    110,577 
           
TOTAL CURRENT LIABILITIES   966,041    231,656 
           
LONG-TERM LIABILITIES          
Lease liability, net of current portion   219,410    107,862 
Reserve for plugging and abandonment costs   44,186    63,929 
           
TOTAL LONG-TERM LIABILITIES   263,596    171,791 
           
TOTAL LIABILITIES   1,229,637    403,447 
           
COMMITMENTS AND CONTINGENCIES          
           
SHAREHOLDERS’ EQUITY          
Preferred stock, par value $0.001; 10,000,000 shares authorized          
Series A Convertible Redeemable Preferred Stock, Par value $0.001; 2,000 shares authorized; 1,085 and 1,085 shares issued and outstanding, respectively; liquidation preference of $1,085,000   1    1 
Series B Convertible Redeemable Preferred Stock, Par value $0.001; 1,000 shares authorized; 835 and 835 shares issued and outstanding, respectively; liquidation preference of $835,000   1    1 
Common stock, par value $0.001; 12,000,000 shares authorized  5,275,816 and 6,977,718 shares issued and outstanding   5,276    6,977 
Additional paid-in capital   73,877,332    78,453,906 
Subscription receivable   (58,575)    
Accumulated deficit   (67,984,837)   (72,021,911)
           
TOTAL SHAREHOLDERS’ EQUITY   5,839,198    6,438,974 
           
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY  $7,068,835   $6,842,421 

 

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

 

F-3
 

 

HOUSTON AMERICAN ENERGY CORP.

 

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2019 AND 2020

 

 

  

2019

  

2020

 
REVENUES          
Oil and gas revenue  $997,992   $552,345 
           
Total operating revenue   997,992    552,345 
           
EXPENSES OF OPERATIONS          
Lease operating expense and severance tax   789,708    

403,974

 
General and administrative expense   1,357,723    1,447,298 
Depreciation and depletion   438,553    364,810 
Impairment expense   745,691    2,519,032 
           
Total operating expenses   3,331,675    4,735,114 
           
Loss from operations   (2,333,683)   (4,182,769)
           
OTHER INCOME (EXPENSE)          
Interest income   1,961    12,748 
Other income       164,706 
Interest expense   (183,972)   (31,759)
           
Total other income (expense), net   (182,011)   145,695 
           
Loss before taxes   (2,515,694)   (4,037,074)
           
Income tax expense (benefit)        
           
Net loss   (2,515,694)   (4,037,074)
           
Dividends to Series A and B Preferred shareholders   (230,400)   (231,900)
           
Net loss attributable to common shareholders  $(2,746,094)  $(4,268,974)
           
Basic and diluted net loss per common share outstanding  $(0.52)  $(0.62)
           
Basic and diluted weighted average number of common shares outstanding   5,275,812    6,939,305 

 

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

 

F-4
 

 

HOUSTON AMERICAN ENERGY CORP.

 

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2019 and 2020

 

                   Additional       Retained     
   Preferred Stock   Common Stock   Paid-in   Subscription   Earnings     
   Shares   Amount   Shares   Amount   Capital   Receivable   (Deficit)   Total 
                                 
Balance at December 31, 2018   1,920   $2    4,994,011   $

4,994

   $73,141,440   $   $(65,469,143)  $7,677,293 
                                         
Issuance of common stock for cash, net           277,800    278    665,257    (58,575)       606,960 
Stock-based compensation           4,000    4    156,087            156,091 
Series A and Series B Preferred Stock dividends paid                   (230,400)           (230,400)
Debt discount from issuance of warrants as debt inducement                   144,948              144,948 
Net loss                           (2,515,694)   (2,515,694)
                                         
Balance at December 31, 2019   1,920    2    5,275,811    5,276    73,877,332    (58,575)   (67,984,837)   5,839,198 
                                         
Issuance of common stock for cash, net           1,684,763    1,684    4,373,910    58,575        4,434,169 
Stock-based compensation           

    

    434,581            434,581 
Series A and Series B Preferred Stock dividends paid                   (231,900)           (231,900)
Rounding of common stock due to reverse split           

17,144

    

17

    (17)           

Net loss                           (4,037,074)   (4,037,074)
                                         
Balance at December 31, 2020   1,920   $2    6,977,718   $6,977   $78,453,906   $   $(72,021,911)  $6,438,974 

 

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

 

F-5
 

 

HOUSTON AMERICAN ENERGY CORP.

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2019 AND 2020

 

   2019   2020 
CASH FLOW FROM OPERATING ACTIVITIES          
Net loss  $(2,515,694)  $(4,037,074)
           
Adjustments to reconcile net loss to net cash (used in) provided by operations          
Depreciation and depletion   438,552    364,810 
Impairment of oil and gas properties   745,691    2,519,032 
Accretion of plugging and abandonment costs   5,432    3,286 
Stock-based compensation   156,091    434,581 
Amortization of right of use asset   76,495    87,366 
Amortization of debt discount   162,533    23,467 
Change in operating assets and liabilities:          
Decrease/(increase) in accounts receivable   55,847    (15,568)
Decrease in prepaid expense and other current assets   26,876    3,660 
Increase/(decrease) in accounts payable and accrued expenses   305,697    (136,799)
Decrease in operating lease liability   (182,539)   (111,548)
           
Net cash used in operating activities   (725,019)   (864,787)
           
CASH FLOW FROM INVESTING ACTIVITIES          
Payments for the acquisition and development of oil and gas properties   (692,319)   (1,509,876)
Proceeds from sale of mineral interest   

    

1,487

 
Payments for the acquisition of cost method investment   (197,009)   (63,396)
           
Net cash used in investing activities   (889,328)   (1,571,785)
           
CASH FLOW FROM FINANCING ACTIVITIES          
           
Proceeds from issuance of notes payable, net of debt discount   680,000     
Repayments of notes payable   (100,000)   (621,052)
Proceeds from issuance of common stock for cash, net of offering costs   606,960    4,434,169 
Payment of preferred stock dividends   (230,400)   (231,900)
Net cash provided by financing activities   966,560    3,581,217 
           
(DECREASE) INCREASE IN CASH   (657,787)   1,144,645 
Cash, beginning of year   755,702    97,915 
           
Cash, end of year  $97,915   $1,242,560 
           
SUPPLEMENTAL CASH FLOW INFORMATION:          
Interest paid  $21,439   $

3,350

 
Taxes paid  $   $ 
           
SUPPLEMENTAL NON-CASH INVESTING AND FINANCING ACTIVITIES          
Change in asset retirement obligations, net  $   $

17,082

 
Debt discount from issuance of warrants as debt inducement  $144,948   $ 

 

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

 

F-6
 

 

HOUSTON AMERICAN ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

NOTE 1—NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

General

 

Houston American Energy Corp. (a Delaware Corporation) (“the Company” or “HUSA”) was incorporated in 2001. The Company is engaged, as a non-operating joint owner, in the exploration, development, and production of natural gas, crude oil, and condensate from properties. The Company’s principal properties are in the Texas Permian Basin with additional holdings in Gulf Coast areas of the United States and international holdings in Colombia, South America.

 

Consolidation

 

The accompanying consolidated financial statements include all accounts of HUSA and its subsidiaries (HAEC Louisiana E&P, Inc., HAEC Oklahoma E&P, Inc. and HAEC Caddo Lake E&P, Inc.). All significant inter-company balances and transactions have been eliminated in consolidation.

 

Reverse Stock Split

 

In July 2020, the Company’s shareholders approved a reverse split of the Company’s common stock in a ratio to be determined, within a specified range, by the Company’s board of directors. The Company’s board of directors approved, and, effective at the close of business on July 31, 2020, the Company’s Certificate of Incorporation was amended to affect a 1-for-12.5 reverse split (the “Reverse Split”) of the Company’s common stock. Fractional shares otherwise issuable pursuant to the Reverse Split were rounded up to the next highest whole number of shares. As a result of the Reverse Split, the shares of common stock outstanding immediately prior to the Reverse Split decreased from 87,007,145 to 6,960,575 shares and the shares of common stock authorized for issuance decreased from 150,000,000 shares to 12,000,000 shares. Similarly, all shares of common stock issuable under outstanding options, warrants and shares of convertible preferred stock were adjusted, and applicable conversion or exercise prices were proportionately adjusted, to reflect the Reverse Split. The par value of the Company’s common stock remained unchanged at $0.001 per share.

 

All references to shares of common stock and per share data for all periods in the financial statements and notes thereto have been adjusted to reflect the Reverse Split on a retroactive basis.

 

Liquidity and Capital Requirements

 

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the issuance date of these consolidated financial statements. The Company has incurred continuing losses since 2011, including a loss of $4,037,074 for the year ended December 31, 2020. As a result of the steep global economic slowdown that began in March 2020 as the coronavirus pandemic (“COVID-19”) spread, oil and gas demand and prices realized from oil and gas sales declined sharply and have only partially recovered as of December 31, 2020, with such demand and price declines expected to persist until governments worldwide are confident that the pandemic is adequately contained to permit renewed economic activity. Depending upon the duration of the pandemic and the resulting global economic slowdown, the Company may incur continuing declines in revenues and increased losses, associated from lower demand for energy and resulting depressed oil and gas prices. However, during 2020, the Company raised a total, net of offering costs, of $4.3 million in its ATM offering and, during January and February 2021, the Company raised an additional $6.5 million, net of offering costs, in additional ATM offerings.

 

The Company believes that it has the ability to fund, from cash on hand, its operating costs and anticipated drilling operations, as well as mitigate the immediate impact of COVID-19, for at least the next twelve months following the issuance of these financial statements.

 

The actual timing and number of wells drilled during 2021 will be principally controlled by the operators of the Company’s acreage, based on a number of factors, including but not limited to availability of financing, performance of existing wells on the subject acreage, energy prices and industry condition and outlook, costs of drilling and completion services and equipment and other factors beyond the Company’s control or that of its operators.

 

F-7
 

 

In the event that the Company pursues additional acreage acquisitions or expands its drilling plans, the Company may be required to secure additional funding beyond our resources on hand. While the Company may, among other efforts, seek additional funding from “at-the-market” sales of common stock, and private sales of equity and debt securities, it presently does not have any commitments to provide additional funding, and there can be no assurance that the Company can secure the necessary capital to fund its share of drilling, acquisition or other costs on acceptable terms or at all. If, for any reason, the Company is unable to fund its share of drilling and completion costs, it would forego participation in one or more of such wells. In such event, the Company may be subject to penalties or to the possible loss of some of its rights and interests in prospects with respect to which it fails to satisfy funding obligations and it may be required to curtail operations and forego opportunities.

 

General Principles and Use of Estimates

 

The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America. In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including those related to such potential matters as litigation, environmental liabilities, income taxes, and determination of proved reserves of oil and gas and asset retirement obligations. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

 

Cash and Cash Equivalents

 

Cash and cash equivalents consist of demand deposits and cash investments with initial maturity dates of less than three months when purchased. As of December 31, 2019 and 2020, the Company had no cash equivalents outstanding.

 

Concentration of Credit Risk

 

Financial instruments that potentially subject the Company to a concentration of credit risk include cash, cash equivalents and marketable securities (if any). The Company had cash deposits of $908,997 in excess of the FDIC’s current insured limit of $250,000 at December 31, 2020 for interest bearing accounts. The Company also had cash deposits of $2,547 in Colombian banks at December 31, 2020 that are not insured by the FDIC. The Company has not experienced any losses on its deposits of cash and cash equivalents.

 

Revenue Recognition

 

ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)”, supersedes the revenue recognition requirements and industry-specific guidance under Revenue Recognition (Topic 605). Topic 606 requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Company adopted Topic 606 on January 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. Under the modified retrospective method, prior period financial positions and results are not adjusted. The cumulative effect adjustment recognized in the opening balances included no significant changes as a result of this adoption. While the Company’s 2018 net earnings were not materially impacted by revenue recognition timing changes, Topic 606 requires certain changes to the presentation of revenues and related expenses beginning January 1, 2018. Refer to Note 2 – Revenue from Contracts with Customers for additional information.

 

The Company’s revenue is comprised principally of revenue from exploration and production activities. The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery.

 

F-8
 

 

Contracts with customers have varying terms, including spot sales or month-to-month contracts, contracts with a finite term, and life-of-field contracts where all production from a well or group of wells is sold to one or more customers. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs.

 

Revenues are recognized for the sale of the Company’s net share of production volumes.

 

Loss per Share

 

Basic loss per share is computed by dividing net loss available to common shareholders by the weighted average common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted in common shares that then shared in the earnings of the Company. In periods in which the Company reports a net loss, dilutive securities are excluded from the calculation of diluted net loss per share amounts as the effect would be anti-dilutive.

 

For the years ended December 31, 2019 and 2020, the following convertible preferred stock and warrants and options to purchase shares of common stock were excluded from the computation of diluted net loss per share, as the inclusion of such shares would be anti-dilutive:

 

   Year Ended December 31,
   2019  2020
Series A Convertible Preferred Stock   434,000    434,000 
Series B Convertible Preferred Stock   185,644    185,644 
Stock warrants   98,400    98,400 
Stock options   480,973    784,977 
Totals   1,199,017    1,503,021 

 

Accounts Receivable

 

Accounts receivable – other and escrow receivables have been evaluated for collectability and are recorded at their net realizable values.

 

Allowance for Accounts Receivable

 

The Company regularly reviews outstanding receivables and provides for estimated losses through an allowance for doubtful accounts when necessary. In evaluating the need for an allowance, the Company makes judgments regarding its customers’ ability to make required payments, economic events and other factors. As the financial condition of these parties change, circumstances develop or additional information becomes available, an allowance for doubtful accounts may be required. When the Company determines that a customer may not be able to make required payments, the Company increases the allowance through a charge to income in the period in which that determination is made. As of December 31, 2019 and 2020, the Company evaluated their receivables and determined that no allowance was necessary.

 

Oil and Gas Properties

 

The Company uses the full cost method of accounting for exploration and development activities as defined by the SEC. Under this method of accounting, the costs for unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. Capitalized costs include lease acquisition, geological and geophysical work, delay rentals, costs of drilling, completing and equipping the wells and any internal costs that are directly related to acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Proceeds from the sale or other disposition of oil and gas properties are generally treated as a reduction in the capitalized costs of oil and gas properties, unless the impact of such a reduction would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.

 

F-9
 

 

The Company categorizes its full cost pools as costs subject to amortization and costs not being amortized. The sum of net capitalized costs subject to amortization, including estimated future development and abandonment costs, are amortized using the unit-of-production method. Depletion and amortization for oil and gas properties was $438,552 and $364,810 for the years ended December 31, 2019 and 2020, respectively, and accumulated amortization, depreciation and impairment was $57,177,141 and $60,060,984 at December 31, 2019 and 2020, respectively.

 

Costs Excluded

 

Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent costs of investments in unproved properties. The Company excludes these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the costs subject to amortization.

 

Ceiling Test

 

Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X. The ceiling test determines a limit, on a country-by-country basis, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment (“DD&A”) and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, calculated for 2020 using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such p