Houston American Energy (HUSA) 10-K 16 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Mar. 13, 2017	Jun. 30, 2016
Document And Entity Information
Entity Registrant Name	HOUSTON AMERICAN ENERGY CORP
Entity Central Index Key	1,156,041
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filer	No
Entity Current Reporting Status	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float			$ 9,000,000
Entity Common Stock, Shares Outstanding		51,277,388
Trading Symbol	HUSA
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2,016

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Dec. 31, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash	$ 481,172	$ 2,123,520
Escrow receivable		262,016
Prepaid expenses and other current assets	3,750	38,257
TOTAL CURRENT ASSETS	484,922	2,423,793
Oil and gas properties, full cost method
Costs subject to amortization	55,639,333	54,840,599
Costs not being amortized	2,291,181	2,879,063
Office equipment	90,004	90,004
Total	58,020,518	57,809,666
Accumulated depletion, depreciation, amortization, and impairment	(55,563,591)	(54,676,723)
PROPERTY AND EQUIPMENT, NET	2,456,927	3,132,943
Other assets	3,167	3,167
TOTAL ASSETS	2,945,016	5,559,903
CURRENT LIABILITIES
Accounts payable	50,122	23,195
Accrued expenses	11,005	16,315
TOTAL CURRENT LIABILITIES	61,127	39,510
LONG-TERM LIABILITIES
Reserve for plugging and abandonment costs	27,444	25,262
TOTAL LIABILITIES	88,571	64,772
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY
Preferred stock, par value $0.001; 10,000,000 shares authorized, 0 shares issued and outstanding
Common stock, par value $0.001; 150,000,000 shares authorized 52,169,945 shares issued	52,170	52,170
Additional paid-in capital	66,158,593	66,019,681
Treasury shares, at cost; 892,557 and 190,000 shares, respectively	(174,125)	(38,152)
Accumulated deficit	(63,180,193)	(60,538,568)
TOTAL SHAREHOLDERS' EQUITY	2,856,445	5,495,131
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$ 2,945,016	$ 5,559,903

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	52,169,945	52,169,945
Treasury stock, at cost	892,557	190,000

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Income Statement [Abstract]
OIL AND GAS REVENUE	$ 165,910	$ 429,435
EXPENSES OF OPERATIONS
Lease operating expense and severance tax	97,203	148,067
Depreciation and depletion	302,782	756,757
Impairment of oil and gas properties	584,086	1,718,088
General and administrative expense	1,830,670	1,541,294
Total operating expenses	2,814,741	4,164,206
Loss from operations	(2,648,831)	(3,734,771)
OTHER INCOME (EXPENSE)
Interest income	7,206	20,533
Currency valuation loss		(97,103)
Total other income (expense)	7,206	(392,654)
Loss before taxes	(2,641,625)	(3,811,341)
Income tax expense (benefit)		18,865
Net loss	$ (2,641,625)	$ (3,830,206)
Basic and diluted net loss per common share outstanding	$ (0.05)	$ (0.07)
Basic and diluted weighted average number of common shares outstanding	51,472,124	52,159,726

Consolidated Statements of Chan

Consolidated Statements of Changes in Shareholders' Equity - USD ($)	Common Stock [Member]	Additional Paid-In Capital [Member]	Treasury Stock [Member]	Retained Earnings (Deficit) [Member]	Total
Balance at Dec. 31, 2014	$ 52,170	$ 65,928,056		$ (56,708,362)	$ 9,271,864
Balance, shares at Dec. 31, 2014	52,169,945
Stock-based compensation		91,625			91,625
Acquisition of treasury stock			$ (38,152)		(38,152)
Acquisition of treasury stock, shares			190,000
Net loss				(3,830,206)	(3,830,206)
Balance at Dec. 31, 2015	$ 52,170	66,019,681	$ (38,152)	(60,538,568)	5,495,131
Balance, shares at Dec. 31, 2015	52,169,945		190,000
Stock-based compensation		138,912			138,912
Acquisition of treasury stock			$ (135,973)		(135,973)
Acquisition of treasury stock, shares			702,557
Net loss				(2,641,625)	(2,641,625)
Balance at Dec. 31, 2016	$ 52,170	$ 66,158,593	$ (174,125)	$ (63,180,193)	$ 2,856,445
Balance, shares at Dec. 31, 2016	52,169,945		892,557

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
CASH FLOW FROM OPERATING ACTIVITIES
Net loss	$ (2,641,625)	$ (3,830,206)
Adjustments to reconcile net loss to net cash provided by (used in) operations
Depreciation and depletion	302,782	756,757
Impairment of oil and gas properties	584,086	1,718,088
Stock-based compensation	138,912	91,625
Accretion of asset retirement obligation	552	1,329
Bad debt expense	262,016
Change in operating assets and liabilities:
Increase (decrease) in insurance receivable		8,612,681
Decrease in prepaid expense and other current assets	34,507	86,703
Decrease in accounts payable and accrued expenses	21,617	(552,273)
Increase (decrease) in settlement payable		(7,000,000)
Increase (decrease) in accrued legal fees		(1,722,681)
Net cash used in operations	(1,297,153)	(1,837,977)
CASH FLOW FROM INVESTING ACTIVITIES
Payments for acquisition and development of oil and gas properties and assets	(209,222)	(168,680)
Proceeds from sale of mineral interest		56,705
Proceeds from escrow receivable, net		59,412
Net cash used in investing activities	(209,222)	(52,563)
CASH FLOW FROM FINANCING ACTIVITIES
Payment for acquisition of treasury shares	(135,973)	(38,512)
Net cash used in financing activities	(135,973)	(38,512)
INCREASE (DECREASE) IN CASH	(1,642,348)	(1,928,692)
Cash, beginning of year	2,123,520	4,052,212
Cash, end of year	481,172	2,123,520
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid
Taxes paid		18,865
SUPPLEMENTAL NON-CASH INVESTING AND FINANCING ACTIVITIES
Net change in estimate of asset retirement obligation	$ 1,630	$ 4,214

Nature of Company and Summary o

Nature of Company and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Company and Summary of Significant Accounting Policies	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 on April 2, 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 located principally in the Texas Permian Basin and Gulf Coast areas of the United States and international locations with proven production, which to date has focused on Colombia, South America. Going Concern 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 date of these consolidated financial statements. The Company has incurred continuing losses, negative operating cash flow and declining cash balances since 2011, including negative operating cash flow of $1,297,153 for the year ended December 31, 2016. These conditions, together with continued low oil and natural gas prices and financial commitments the Company has made relative to its Permian Basin and Colombian properties, raise substantial doubt as to the Company’s ability to continue as a going concern for the next twelve months following the filing date of these financial statements. These financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern. To address these concerns, the Company may seek additional financing or may consider divestiture of certain assets. There can be no assurance that the Company will be successful in its efforts. 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. 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. Reclassification Certain amounts for prior periods have been reclassified to conform to the current presentation. Cash and Cash Equivalents Cash and cash equivalents consist of demand deposits and cash investments with initial maturity dates of less than three months. Concentration of Credit Risk Financial instruments that potentially subject the Company to a concentration of credit risk include cash and cash equivalents. The Company had cash deposits of approximately $158,000 in excess of the FDIC’s current insured limit of $250,000 at December 31, 2016 for interest bearing accounts. The Company has not experienced any losses on its deposits of cash and cash equivalents. 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, 2016, the Company evaluated their receivables and determined an allowance of $262,016 related to its escrow receivable was necessary. Oil and Gas Revenues The Company recognizes sales revenues, net of royalties and net profits interests, based on the amount of gas, oil, and condensate sold to purchasers when delivery to the purchaser has occurred and title has transferred. This occurs when production has been delivered to a pipeline. The Company follows the sales method to account for natural gas imbalances. Sales may result in more or less of the Company’s share of pro-rata production from certain wells. When natural gas sales volumes exceeds the Company’s entitled share and the accumulated overproduced balance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company will record a liability. Historically, sales volumes have not materially differed from the Company’s entitled share of natural gas production and the Company did not have a material imbalance position in terms of volumes or values at December 31, 2016 or 2015. 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. 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 $301,786 and $754,892 for the years ended December 31, 2016 and 2015, respectively and accumulated amortization, depreciation and impairment was $55,473,698 and $54,587,826 at December 31, 2016 and 2015, 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”) Furniture and Equipment Office equipment is stated at original cost and is depreciated on the straight-line basis over the useful life of the assets, which ranges from three to five years. Depreciation expense for office equipment was $996 and $1,865 for 2016 and 2015, respectively, and accumulated depreciation was $89,893 and $88,897 at December 31, 2016 and 2015, respectively. Asset Retirement Obligations For the Company, asset retirement obligations (“ARO”) represent the systematic, monthly accretion and depreciation of future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, an adjustment is made to the full cost pool, with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. Although the Company’s domestic policy with respect to ARO is to assign depleted wells to a salvager for the assumption of abandonment obligations before the wells have reached their economic limits, the Company has estimated its future ARO obligation with respect to its domestic operations. The ARO assets, which are carried on the balance sheet as part of the full cost pool, have been included in our amortization base for the purposes of calculating depreciation, depletion and amortization expense. For the purposes of calculating the ceiling test, the future cash outflows associated with settling the ARO liability have been included in the computation of the discounted present value of estimated future net revenues. Joint Venture Expense Joint venture expense reflects the indirect field operating and regional administrative expenses billed by the operator of the Colombian concessions. Income Taxes Deferred income taxes are provided on a liability method whereby deferred tax assets and liabilities are established for the difference between the financial reporting and income tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. Stock-Based Compensation The Company measures the cost of employee services received in exchange for stock and stock options based on the grant date fair value of the awards. The Company determines the fair value of stock option grants using the Black-Scholes option pricing model. The Company determines the fair value of shares of non-vested stock based on the last quoted price of our stock on the date of the share grant. The fair value determined represents the cost for the award and is recognized over the vesting period during which an employee is required to provide service in exchange for the award. As share-based compensation expense is recognized based on awards ultimately expected to vest, the Company reduces the expense for estimated forfeitures based on historical forfeiture rates. Previously recognized compensation costs may be adjusted to reflect the actual forfeiture rate for the entire award at the end of the vesting period. Excess tax benefits, if any, are recognized as an addition to paid-in capital. Preferred Stock The Company has authorized 10,000,000 shares of preferred stock with a par value of $0.001. The Board of Directors shall determine the designations, rights, preferences, privileges and voting rights of the preferred stock as well as any restrictions and qualifications thereon. No shares of preferred stock had been issued as of December 31, 2016. Net Loss Per Share Basic net loss per share is computed by dividing the net loss attributable to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted net loss per share is computed by dividing the net loss attributable to common shareholders by the weighted-average number of common and common equivalent shares outstanding during the period. Common share equivalents included in the diluted computation represent shares issuable upon assumed exercise of stock options and warrants using the treasury stock and “if converted” method. For periods in which net losses are incurred, weighted average shares outstanding is the same for basic and diluted loss per share calculations, as the inclusion of common share equivalents would have an anti-dilutive effect. For the years ended December 31, 2016 and 2015, outstanding options to purchase 5,232,165 shares of common stock and 4,432,165 shares of common stock, respectively, were excluded from the calculation of diluted net loss per share because they were anti-dilutive. Concentration of Risk As a non-operator oil and gas exploration and production company, and through its interest in a limited liability company (“Hupecol”) and concessions operated by Hupecol in the South American country of Colombia, the Company is dependent on the personnel, management and resources of the operators of its various properties to operate efficiently and effectively. As a non-operating joint interest owner, the Company has a right of investment refusal on specific projects and the right to examine and contest its division of costs and revenues determined by the operator. The Company currently has interests in concessions in Colombia and expects to be active in Colombia for the foreseeable future. The political climate in Colombia is unstable and could be subject to radical change over a very short period of time. In the event of a significant negative change in political and economic stability in the vicinity of the Company’s Colombian operations, the Company may be forced to abandon or suspend its efforts. Either of such events could be harmful to the Company’s expected business prospects. At December 31, 2016, 89% of the Company’s net oil and gas property investment, and 0% of its revenue for the year ended December 31, 2016, was with or derived from interests operated in Colombia. For 2016, our oil production from the Company’s mineral interests was sold to U.S. oil marketing companies based on the highest bid. The gas production is sold to U.S. natural gas marketing companies based on the highest bid. No purchaser accounted for more than 10% of our oil and gas sales. The Company reviews accounts receivable balances when circumstances indicate a balance may not be collectible. Based upon the Company’s review, no allowance for uncollectible accounts was deemed necessary at December 31, 2016 and 2015, respectively. Subsequent Events The Company evaluated subsequent events for disclosure from December 31, 2016 through the date the consolidated financial statements were issued. Recent Accounting Developments No accounting standards or interpretations issued recently are expected to a have a material impact on our consolidated financial position, operations or cash flows.

Escrow Receivable

Escrow Receivable	12 Months Ended
	Dec. 31, 2016
ESCROW RECEIVABLE [Abstract]
Escrow Receivable	NOTE 2—ESCROW RECEIVABLE At December 31, 2016 and December 31, 2015, the Company’s balance sheet reflected the following escrow receivables relating to various oil and gas properties previously sold by the Company: December 31, 2016 December 31, 2015 HDC LLC and HL LLC 15% Escrow $ — $ 251,125 HDC LLC and HL LLC 5% Contingency — 10,891 Total $ — $ 262,016 During 2016, the Company evaluated its outstanding escrow receivable and determined that an allowance for accounts receivable of $262,016 was necessary.

Oil and Gas Properties

Oil and Gas Properties	12 Months Ended
	Dec. 31, 2016
Oil and Gas Property [Abstract]
Oil and Gas Properties	NOTE 3—OIL AND GAS PROPERTIES Evaluated Oil and Gas Properties Evaluated oil and gas properties subject to amortization at December 31, 2016 included the following: United States South America Total Evaluated properties being amortized $ 6,184,631 $ 49,454,702 $ 55,639,333 Accumulated depreciation, depletion, amortization and impairment (6,018,996 ) (49,454,702 ) (55,473,698 ) Net capitalized costs $ 165,635 $ — $ 165,635 Evaluated oil and gas properties subject to amortization at December 31, 2015 included the following: United States South America Total Evaluated properties being amortized $ 5,385,898 $ 49,454,702 $ 54,840,600 Accumulated depreciation, depletion, amortization and impairment (5,133,124 ) (49,454,702 ) (54,587,826 ) Net capitalized costs $ 252,774 $ — $ 252,774 Unevaluated Oil and Gas Properties Unevaluated oil and gas properties not subject to amortization at December 31, 2016 included the following: United States South America Total Leasehold acquisition costs $ — $ 141,318 $ 141,318 Geological, geophysical, screening and evaluation costs 6,994 2,142,869 2,149,863 Total $ 6,994 $ 2,284,187 $ 2,291,181 Unevaluated oil and gas properties not subject to amortization at December 31, 2015 included the following: United States South America Total Leasehold acquisition costs $ 761,545 $ 141,319 $ 902,864 Geological, geophysical, screening and evaluation costs 4,143 1,972,056 1,976,199 Total $ 765,688 $ 2,133,375 $ 2,876,199

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	NOTE 4—Asset Retirement Obligations The following table describes changes in our asset retirement liability during each of the years ended December 31, 2016 and 2015. 2016 2015 ARO liability at January 1 $ 25,262 $ 28,147 Accretion expense 552 1,329 Changes in estimates 1,630 (4,214 ) ARO liability at December 31 $ 27,444 $ 25,262

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation	NOTE 5—STOCK-BASED COMPENSATION On August 12, 2005, the Company’s Board of Directors adopted the Houston American Energy Corp. 2005 Stock Option Plan (the “2005 Plan”). The terms of the 2005 Plan allow for the issuance of up to 500,000 options to purchase 500,000 shares of the Company’s common stock. In 2008, the Company’s Board of Directors adopted the Houston American Energy Corp. 2008 Equity Incentive Plan (the “2008 Plan” and, together with the 2005 Plan, the “Plans”). The terms of the 2008 Plan, as amended in 2012 and 2013, allow for the issuance of up to 6,000,000 shares of the Company’s common stock pursuant to the grant of stock options and restricted stock. Persons eligible to participate in the Plans are key employees, consultants and directors of the Company. Stock Option Activity In 2015, options to purchase an aggregate of 8,333 shares were granted to a new non-employee director, options to purchase an aggregate of 900,000 shares were granted to a new officer and options to purchase an aggregate of 200,000 shares were granted to non-employee directors. The 8,333 options granted to a new non-employee director vested 20% on the grant date and vest as to the remaining 80% nine months from the grant date, have a ten-year life and have an exercise price of $0.2158 per share. The option grant to the non-employee director was valued on the date of grant at $805 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 1.36%, (2) expected life in years of 4.98, and (3) expected stock volatility of 106%. The Company determined the option qualifies as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life. The 900,000 options granted to an employee have a ten year life and an exercise price of $0.2158 per share and vest 1/3 on each of the first three anniversaries of the grant date, subject to acceleration of vesting in the event of certain changes in control or (i) the receipt of $10 million or more in aggregate gross proceeds from the sale of equity securities or securities convertible into equity securities, or (ii) the acquisition by the Company of $10 million or more in aggregate purchase price of oil and gas properties. The option grant to the employee was valued on the date of grant at $82,000 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of1.36%, (2) expected life in years of 4.98, and (3) expected stock volatility of 106%. The Company determined the option qualifies as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life. The 200,000 options granted to non-employee directors vested 20% on the grant date and vest as to the remaining 80% nine months from the grant date, have a ten-year life and have an exercise price of $0.2028 per share. The option grants to non-employee directors were valued on the date of grant at $17,370 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 1.73% (2) expected life in years of 5.01, and (3) expected stock volatility of 105%. The Company determined the options qualify as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life. In March 2016, options to purchase an aggregate of 20,000 shares were granted to non-employee directors. The options were granted in connection with service on an ad hoc board committee and vest on the earlier of August 15, 2016, the termination of the committee or termination of service on the committee due to death or disability. The options have a five-year life and an exercise price of $0.1982 per share. The options were valued on the date of grant at $2,896 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 1.49%; (2) expected life in years of 4.99; (3) expected stock volatility of 106.95%; (4) expected dividend yield of 0%; and (5) forfeiture rate of 15.22%. The Company determined the options qualify as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life. In June 2016, options to purchase an aggregate of 800,000 shares were granted to non-employee directors. The options, which included a one-time supplemental grant to purchase an aggregate of 600,000 shares, were granted in connection with service on the board of directors. 200,000 of the options granted to non-employee directors vested 20% on the grant date and vest as to the remaining 80% nine months from the grant date, have a ten-year life and have an exercise price of $0.2201 per share. Those option grants were valued on the date of grant at $32,640 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 1.26%; (2) expected life in years of 5.28; (3) expected stock volatility of 108.5%; (4) expected dividend yield of 0%; and (5) forfeiture rate of 15.01%. 600,000 of the options granted to non-employee directors vest (i) 50% on the earlier of June 7, 2017 or the day preceding the next annual shareholders meeting at which directors are elected, (ii) 50% on the earlier of June 7, 2018 or the day preceding the second annual shareholders meeting (after the grant date) at which directors are to be elected, and (iii) in the event that the Company consummates a transaction(s) (after the option grant date) in the nature of a sale of shares of equity securities for cash or assets resulting in a net addition(s) to the Company’s stockholders’ equity of not less than $2 million, all unvested options vest in full. Those options have a ten-year life and have an exercise price of $0.2201 per share. Those option grants were valued on the date of grant at $83,421 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 1.26% (2) expected life in years of 5.28, and (3) expected stock volatility of 108.5%. The Company determined the option qualifies as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life. Option activity during 2016 and 2015 was as follows: Options Weighted Average Exercise Price Weighted Average Remaining Contractual Term (in Years) Aggregate Intrinsic Value Outstanding at December 31, 2014 3,392,832 $ 3.21 Granted 1,108,333 $ 0.21 Exercised — $ — Forfeited (69,000 ) $ 2.55 Outstanding at December 31, 2015 4,432,165 $ 2.47 Granted 820,000 $ 0.22 Exercised — $ — Forfeited (20,000 ) $ 4.10 Outstanding at December 31, 2016 5,232,165 $ 2.11 6.35 $ — During 2016 and 2015, the Company recognized $138,912 and $91,625, respectively, of stock-based compensation expense attributable to outstanding stock option grants, including current period grants and unamortized expense associated with prior period grants. As of December 31, 2016, non-vested options totaled 1,310,000 and total unrecognized stock-based compensation expense related to non-vested stock options was $120,687. The unrecognized expense is expected to be recognized over a weighted average period of 1.23 years. The weighted average remaining contractual term of the outstanding options and exercisable options at December 31, 2016 is 6.35 years and 5.50 years, respectively. As of December 31, 2016, there were 767,835 shares of common stock available for issuance pursuant to future stock or option grants under the Plans. Share-Based Compensation Expense The following table reflects share-based compensation recorded by the Company for 2016 and 2015: 2016 2015 Share-based compensation expense included in general and administrative expense $ 138,911 $ 91,625 Earnings per share effect of share-based compensation expense $ (0.00 ) $ (0.00 ) Treasury Stock We account for repurchases of common stock using the cost method with common stock in treasury classified in the consolidated balance sheets as a reduction of shareholders’ equity. During the years ending December 31, 2016 and 2015, the Company acquired 702,557 and 190,000 shares of common stock, respectively, for $135,973 and $38,152, respectively.

Taxes

Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Taxes	NOTE 6—TAXES The following table sets forth a reconciliation of the statutory federal income tax for the years ending December 31, 2016 and 2015. 2016 2015 Income (loss) before income taxes $ (2,641,625 ) $ (3,811,341 ) Income tax expense (benefit) computed at statutory rates $ (924,569 ) $ (1,333,969 ) Permanent differences, nondeductible expenses 514 501 Increase (decrease) in valuation allowance 874,987 635,888 Return to accrual items — (764 ) Other adjustment 49,068 717,209 NOL adjustment — — Tax provision $ — $ 18,865 Total provision Foreign $ — $ 18,865 Total provision (benefit) $ — $ 18,865 At December 31, 2016 the Company has a federal tax loss carry forward of $48,205,895 and a foreign tax credit carry forward of $505,745, both of which have been fully reserved. The tax effects of the temporary differences between financial statement income and taxable income are recognized as a deferred tax asset and liabilities. Significant components of the deferred tax asset and liability as of December 31, 2016 and 2015 are set out below. 2016 2015 Non-Current Deferred tax assets: Net operating loss carry forward $ 16,872,064 $ 16,255,870 Foreign tax credit carry forward 505,745 505,745 Deferred state tax 23,277 23,277 Stock compensation 3,090,907 3,091,356 Book in excess of tax depreciation, depletion and capitalization methods on oil and gas properties (454,590 ) (713,832 ) Other (327,600 ) (327,600 ) Colombia future tax obligations — — Total Non-Current Deferred tax assets 19,709,803 18,834,816 Valuation Allowance (19,709,803 ) (18,834,816 ) Net deferred tax asset $ — $ — Foreign Income Taxes The Company owns direct ownership in several properties in Colombia operated by Hupecol. Colombia’s current income tax rate is 25%. During 2016 and 2015, we recorded foreign tax expense of $0 and $18,865, respectively.

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Parties	NOTE 7—RELATED PARTIES In conjunction with the Company’s efforts to secure oil and gas prospects, financing and services, in lieu of salary or other forms of compensation, during 2005, the Company granted to John F. Terwilliger, a principal shareholder and then Chief Executive Officer, and Orrie L. Tawes, a principal shareholder and Director, overriding royalty interests (ORRI) in select mineral properties of the Company, including all current and future properties in Colombia in which Messrs. Terwilliger and Tawes each hold a 1.5% ORRI. During 2016 and 2015, Mr. Terwilliger received royalty payments relating to those properties totaling $0 and $919, respectively, and Mr. Tawes received royalty payments relating to those properties totaling $0 and $919, respectively.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	NOTE 8—COMMITMENTS AND CONTINGENCIES Lease Commitment The Company leases office facilities under an operating lease agreement that expires May 31, 2017. The lease agreement requires future payments as follows: Year Amount 2017 $ 40,479 Total $ 40,479 Total rental expense was $107,620 and $95,711 in 2016 and 2015, respectively. The Company does not have any capital leases or other operating lease commitments. Legal Contingencies The Company is subject to legal proceedings, claims and liabilities that arise in the ordinary course of its business. The Company accrues for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as further information develops or circumstances change. Environmental Contingencies The Company’s oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may 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, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or 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 the Company to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on its results of operations, competitive position or financial condition as well as the industry in general. Under these environmental laws and regulations, the Company could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether the Company was responsible for the release or if its operations were standard in the industry at the time they were performed. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. Development Commitments During the ordinary course of oil and gas prospect development, the Company commits to a proportionate share for the cost of acquiring mineral interests, drilling exploratory or development wells and acquiring seismic and geological information. Production Incentive Compensation Plan In August 2013, the Company’s compensation committee adopted a Production Incentive Compensation Plan. The purpose of the Plan is to encourage employees and consultants participating in the Plan to identify and secure for the Company participation in attractive oil and gas opportunities. Under that Plan, the committee may establish one or more Pools and designate employees and consultants to participate in those Pools and designate prospects and wells, and a defined percentage of the Company’s revenues from those wells, to fund those Pools. Only prospects acquired on or after establishment of the Plan, and excluding all prospects in Colombia, may be designated to fund a Pool. The maximum percentage of the Company’s share of revenues from a well that may be designated to fund a Pool is 2% (the “Pool Cap”); provided, however, that with respect to wells with a net revenue interest to the 8/8 of less than 73%, the Pool Cap with respect to such wells shall be reduced on a 1-for-1 basis such that no portion of the Company’s revenues from a well may be designated to fund a Pool if the NRI is 71% or less. Designated participants in a Pool will be assigned a specific percentage out of the Company’s revenues assigned to the Pool and will be paid that percentage of such revenues from all wells designated to such Pool and spud during that participant’s employment or services with the Company. In no event may the percentage assigned to the Company’s chief executive officer relative to any well within a Pool exceed one-half of the applicable Pool Cap for that well. Payouts of revenues funded into Pools shall be made to participants not later than 60 days following year end, subject to the committee’s right to make partial interim payouts. Participants will continue to receive their percentage share of revenues from wells included in a Pool and spud during the term of their employment or service so long as revenues continue to be derived by the Company from those wells even after termination of employment or services of the Participant; provided, however, that a participant’s interest in all Pools shall terminate on the date of termination of employment or services where such termination is for cause. In the event of certain changes in control of the Company, the acquirer or survivor of such transaction must assume all obligations under the Plan; provided, however, that in lieu of such assumption obligation, the committee may, at its sole discretion, assign overriding royalty interests in wells to substantially mirror the rights of participants under the Plan. Similarly, the committee may, at any time, assign overriding royalty interests in wells in settlement of obligations under the Plan. The Plan is administered by the Company’s compensation committee which shall consult with the Company’s chief executive officer relative to Pool participants, prospects, wells and interests assign although the committee will have final and absolute authority to make all such determinations. During 2016, no grants were made under the plan. The Company records amounts payable under the plan as a reduction to revenue as revenues are recognized from prospects included in pools covered by the plan based on the participants’ interest in such prospect revenues and records the same as accounts payable until such time as such amounts are paid out. The obligation associated with the plan totaled $0 at December 31, 2016

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	NOTE 9—SUBSEQUENT EVENTS In January 2017, we executed an agreement to acquire a 25% working interest, subject to a proportionate 5% back-in after prospect payout, in two lease blocks in Reeves County, Texas. In February 2017, we completed the acquisition of a working interest in 717 acres in Reeves County, Texas at a price of $986,000. The acreage lay in the Delaware Basin region of the larger Permian Basin. Founders Oil & Gas, our operator anticipates drilling an initial well on the acreage commencing on or about the first week of May 2017 and drilling a second well before year-end 2017. Our share of drilling cost for the initial well is estimated at $1.7 million. The well is expected to target the Wolfcamp A shale formation. In order to fund our acquisition of the Reeves County, Texas acreage, in January 2017, we issued 1,200 shares of 12% Series A Convertible Preferred Stock for aggregate gross proceeds of $1.2 million. The Series A Convertible Preferred Stock (i) accrues a cumulative dividend, commencing July 1, 2017, at 12% payable, if and when declared, quarterly; (ii) is convertible at the option of the holder into shares of common stock at a conversion price of $0.20 per share, (iii) has a liquidation preference of $1,000 per share plus accrued and unpaid dividends; and (iv) is redeemable at our option, commencing on the second anniversary of the issue date, at a premium to issue price, which premium decreases from 12% to 0% following the fifth anniversary of the issue date, plus accrued and unpaid dividends.

Geographical Information

Geographical Information	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Geographical Information	NOTE 10—GEOGRAPHICAL INFORMATION The Company currently has operations in two geographical areas, the United States and Colombia. Revenues for the years ended December 31, 2016 and 2015 and long-lived assets as of December 31, 2016 and 2015 attributable to each geographical area are presented below: 2016 2015 Revenues Long Lived Assets, Net Revenues Long Lived Assets, Net North America $ 165,910 $ 260,110 $ 429,435 $ 1,019,569 South America — 2,284,187 — 2,113,374 Total $ 165,910 $ 2,544,297 $ 429,435 $ 3,132,943

Supplemental Information On Oil

Supplemental Information On Oil and Gas Exploration, Development and Production Activities (Unaudited)	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Supplemental Information On Oil and Gas Exploration, Development and Production Activities (Unaudited)	NOTE 11—SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) This footnote provides unaudited information required by FASB ASC Topic 932, Extractive Activities—Oil and Gas Geographical Data The following table shows the Company’s oil and gas revenues and lease operating expenses, which excludes the joint venture expenses incurred in South America, by geographic area: 2016 2015 Revenues North America $ 165,910 $ 429,435 South America — — $ 165,910 $ 429,435 Production Cost North America $ 97,203 $ 148,067 South America — — $ 97,203 $ 148,067 Capital Costs Capitalized costs and accumulated depletion relating to the Company’s oil and gas producing activities as of December 31, 2016, all of which are onshore properties located in the United States and Colombia, South America are summarized below: United States South America Total Unproved properties not being amortized $ 6,994 $ 2,284,187 $ 2,291,181 Proved properties being amortized 6,184,631 49,454,702 55,639,333 Accumulated depreciation, depletion, amortization and impairment (6,018,996 ) (49,454,702 ) (55,473,698 ) Net capitalized costs $ 172,629 $ 2,284,187 $ 2,456,816 Amortization Rate The amortization rate per unit based on barrel of oil equivalents was $48.57 for the United States and $0 for South America for the year ended December 31, 2016. Acquisition, Exploration and Development Costs Incurred Costs incurred in oil and gas property acquisition, exploration and development activities as of December 31, 2016 and 2015 are summarized below: 2016 United States South America Property acquisition costs: Proved $ — $ — Unproved 6,994 — Exploration costs 31,415 170,812 Development costs — — Total costs incurred $ 38,409 $ 170,812 2015 United States South America Property acquisition costs: Proved $ 16,669 $ — Unproved — — Exploration costs 72,500 79,511 Development costs — — Total costs incurred $ 89,169 $ 79,511 Reserve Information and Related Standardized Measure of Discounted Future Net Cash Flows In December 2009, the Company adopted revised oil and gas reserve estimation and disclosure requirements. The primary impact of the new disclosures is to conform the definition of proved reserves with the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The accounting standards update revised the definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period before the end of the year rather than the year-end price, must be used when estimating whether reserve quantities are economical to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The rules also allow for the use of reliable technology to estimate proved oil and gas reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. The unaudited supplemental information on oil and gas exploration and production activities has been presented in accordance with the new reserve estimation and disclosure rules. Disclosures by geographic area include the United States and South America, which consists of our interests in Colombia. The supplemental unaudited presentation of proved reserve quantities and related standardized measure of discounted future net cash flows provides estimates only and does not purport to reflect realizable values or fair market values of the Company’s reserves. Volumes reported for proved reserves are based on reasonable estimates. These estimates are consistent with current knowledge of the characteristics and production history of the reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, significant changes to these estimates can be expected as future information becomes available. Proved reserves are those estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment, and operating methods. The reserve estimates set forth below were prepared by Lonquist & Co., LLC (“Lonquist”), utilizing reserve definitions and pricing requirements prescribed by the SEC. Lonquist is an independent professional engineering firm specializing in the technical and financial evaluation of oil and gas assets. Lonquist’s report was conducted under the direction of Don E. Charbula, P.E., Vice President of Lonquist. Mr. Charbula holds a BS in Petroleum Engineering from The University of Texas at Austin and is a registered professional engineer with more than 30 years of experience in production engineering, reservoir engineering, acquisitions and divestments, field operations and management. Lonquist and its employees have no interest in the Company, and were objective in determining the results of the Company’s reserves. Lonquist used a combination of production performance, offset analogies, seismic data and their interpretation, subsurface geologic data and core data, along with estimated future operating and development costs as provided by the Company and based upon historical costs adjusted for known future changes in operations or development plans, to estimate our reserves. The Company does not operate any of its oil and gas properties. Total estimated proved developed and undeveloped reserves by product type and the changes therein are set forth below for the years indicated. United States South America Total Gas (mcf) Oil (bbls) Gas (mcf) Oil (bbls) Gas (mcf) Oil (bbls) Total proved reserves Balance December 31, 2014 72,710 34,130 — — 72,710 34,130 Revisions of prior estimates 17,136 (19,212 ) — — 17,136 (19,212 ) Production (32,146 ) (6,068 ) — — (32,146 ) (6,068 ) Balance December 31, 2015 57,700 8,850 — — 57,700 8,850 Revisions to prior estimates 2,524 2,763 — — 2,524 2,763 Production (20,204 ) (2,933 ) — — (20,204 ) (2,933 ) Balance December 31, 2016 40,020 8,680 — — 40,020 8,680 Proved developed reserves at December 31, 2015 57,700 8,850 — — 57,700 8,850 at December 31, 2016 40,020 8,680 — — 40,020 8,680 Proved undeveloped reserves at December 31, 2015 — — — — — — at December 31, 2016 — — — — — — As of December 31, 2016 and December 31, 2015, the Company had no proved undeveloped (“PUD”) reserves. No PUD reserves were converted to proved developed producing reserves in 2016 or 2015. The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is computed using average first-day-of the-month prices for oil and gas during the preceding 12 month period (with consideration of price changes only to the extent provided by contractual arrangements), applied to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated related future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated), and assuming continuation of existing economic conditions. Future income tax expenses give effect to permanent differences and tax credits but do not reflect the impact of continuing operations including property acquisitions and exploration. The estimated future cash flows are then discounted using a rate of ten percent a year to reflect the estimated timing of the future cash flows. Standardized measure of discounted future net cash flows at December 31, 2016: United States South America Total Future cash flows from sales of oil and gas $ 460,760 $ — $ 460,760 Future production cost (264,730 ) — (264,730 ) Future net cash flows 196,030 — 196,030 10% annual discount for timing of cash flow (31,900 ) — (31,900 ) Standardized measure of discounted future net cash flow relating to proved oil and gas reserves $ 164,130 $ — $ 164,130 Changes in standardized measure: Change due to current year operations Sales, net of production costs (68,707 ) — (68,707 ) Change due to revisions in standardized variables: Accretion of discount 25,438 — 25,438 Net change in sales and transfer price, net of production costs (147,362 ) — (147,362 ) Revision and others (43,109 ) — (43,109 ) Changes in production rates and other 143,490 — 143,490 Net (90,250 ) — (90,250 ) Beginning of year 254,380 — 254,380 End of year $ 164,130 $ — $ 164,130 Standardized measure of discounted future net cash flows at December 31, 2015: United States South America Total Future cash flows from sales of oil and gas $ 611,520 $ — $ 611,520 Future production cost (308,020 ) — (308,020 ) Future net cash flows 303,500 — 303,500 10% annual discount for timing of cash flow (49,120 ) — (49,120 ) Standardized measure of discounted future net cash flow relating to proved oil and gas reserves $ 254,380 $ — $ 254,380 Changes in standardized measure: Change due to current year operations Sales, net of production costs (281,368 ) — (285,582 ) Change due to revisions in standardized variables: Accretion of discount 183,828 — 183,828 Net change in sales and transfer price, net of production costs (405,129 ) — (405,129 ) Revision and others (176,014 ) — (176,014 ) Changes in production rates and other (617,498 ) — (613,285 ) Net (1,296,181 ) — (1,296,181 ) Beginning of year 1,550,561 — 1,550,561 End of year $ 254,380 $ — $ 254,380

Summarized Quarterly Financial

Summarized Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Summarized Quarterly Financial Information (Unaudited)	NOTE 12—SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Three Months Ended March 31, June 30, Sept. 30, Dec. 31, 2016 Operating revenue $ 48,260 $ 33,887 $ 39,738 $ 44,025 Loss from operations (343,411 ) (492,202 ) (371,192 ) (1,442,026 ) Net loss (339,451 ) (490,406 ) (370,343 ) (1,441,425 ) Loss per common share – basic $ (0.01 ) $ (0.01 ) $ (0.01 ) $ (0.03 ) Loss per common share – diluted $ (0.01 ) $ (0.01 ) $ (0.01 ) $ (0.03 ) 2015 Operating revenue $ 101,971 $ 114,122 $ 124,448 $ 88,894 Loss from operations (1,191,769 ) (339,488 ) (468,332 ) (1,735,182 ) Net loss (1,187,064 ) (351,808 ) (463,566 ) (1,827,768 ) Loss per common share – basic $ (0.02 ) $ (0.01 ) $ (0.01 ) $ (0.04 ) Loss per common share – diluted $ (0.02 ) $ (0.01 ) $ (0.01 ) $ (0.04 )

Nature of Company and Summary19

Nature of Company and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General	General Houston American Energy Corp. (a Delaware Corporation) (“the Company” or “HUSA”) was incorporated on April 2, 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 located principally in the Texas Permian Basin and Gulf Coast areas of the United States and international locations with proven production, which to date has focused on Colombia, South America.
Going Concern	Going Concern 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 date of these consolidated financial statements. The Company has incurred continuing losses, negative operating cash flow and declining cash balances since 2011, including negative operating cash flow of $1,297,153 for the year ended December 31, 2016. These conditions, together with continued low oil and natural gas prices and financial commitments the Company has made relative to its Permian Basin and Colombian properties, raise substantial doubt as to the Company’s ability to continue as a going concern for the next twelve months following the filing date of these financial statements. These financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern. To address these concerns, the Company may seek additional financing or may consider divestiture of certain assets. There can be no assurance that the Company will be successful in its efforts.
Consolidation	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.
General Principles and Use of Estimates	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.
Reclassification	Reclassification Certain amounts for prior periods have been reclassified to conform to the current presentation.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents consist of demand deposits and cash investments with initial maturity dates of less than three months.
Concentration of Credit Risk	Concentration of Credit Risk Financial instruments that potentially subject the Company to a concentration of credit risk include cash and cash equivalents. The Company had cash deposits of approximately $158,000 in excess of the FDIC’s current insured limit of $250,000 at December 31, 2016 for interest bearing accounts. The Company has not experienced any losses on its deposits of cash and cash equivalents.
Accounts Receivable	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	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, 2016, the Company evaluated their receivables and determined an allowance of $262,016 related to its escrow receivable was necessary.
Oil and Gas Revenues	Oil and Gas Revenues The Company recognizes sales revenues, net of royalties and net profits interests, based on the amount of gas, oil, and condensate sold to purchasers when delivery to the purchaser has occurred and title has transferred. This occurs when production has been delivered to a pipeline. The Company follows the sales method to account for natural gas imbalances. Sales may result in more or less of the Company’s share of pro-rata production from certain wells. When natural gas sales volumes exceeds the Company’s entitled share and the accumulated overproduced balance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company will record a liability. Historically, sales volumes have not materially differed from the Company’s entitled share of natural gas production and the Company did not have a material imbalance position in terms of volumes or values at December 31, 2016 or 2015.
Oil and Gas Properties	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. 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 $301,786 and $754,892 for the years ended December 31, 2016 and 2015, respectively and accumulated amortization, depreciation and impairment was $55,473,698 and $54,587,826 at December 31, 2016 and 2015, respectively.
Costs Excluded	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	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”)
Furniture and Equipment	Furniture and Equipment Office equipment is stated at original cost and is depreciated on the straight-line basis over the useful life of the assets, which ranges from three to five years. Depreciation expense for office equipment was $996 and $1,865 for 2016 and 2015, respectively, and accumulated depreciation was $89,893 and $88,897 at December 31, 2016 and 2015, respectively.
Asset Retirement Obligations	Asset Retirement Obligations For the Company, asset retirement obligations (“ARO”) represent the systematic, monthly accretion and depreciation of future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, an adjustment is made to the full cost pool, with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. Although the Company’s domestic policy with respect to ARO is to assign depleted wells to a salvager for the assumption of abandonment obligations before the wells have reached their economic limits, the Company has estimated its future ARO obligation with respect to its domestic operations. The ARO assets, which are carried on the balance sheet as part of the full cost pool, have been included in our amortization base for the purposes of calculating depreciation, depletion and amortization expense. For the purposes of calculating the ceiling test, the future cash outflows associated with settling the ARO liability have been included in the computation of the discounted present value of estimated future net revenues.
Joint Venture Expense	Joint Venture Expense Joint venture expense reflects the indirect field operating and regional administrative expenses billed by the operator of the Colombian concessions.
Income Taxes	Income Taxes Deferred income taxes are provided on a liability method whereby deferred tax assets and liabilities are established for the difference between the financial reporting and income tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.
Stock-Based Compensation	Stock-Based Compensation The Company measures the cost of employee services received in exchange for stock and stock options based on the grant date fair value of the awards. The Company determines the fair value of stock option grants using the Black-Scholes option pricing model. The Company determines the fair value of shares of non-vested stock based on the last quoted price of our stock on the date of the share grant. The fair value determined represents the cost for the award and is recognized over the vesting period during which an employee is required to provide service in exchange for the award. As share-based compensation expense is recognized based on awards ultimately expected to vest, the Company reduces the expense for estimated forfeitures based on historical forfeiture rates. Previously recognized compensation costs may be adjusted to reflect the actual forfeiture rate for the entire award at the end of the vesting period. Excess tax benefits, if any, are recognized as an addition to paid-in capital.
Preferred Stock	Preferred Stock The Company has authorized 10,000,000 shares of preferred stock with a par value of $0.001. The Board of Directors shall determine the designations, rights, preferences, privileges and voting rights of the preferred stock as well as any restrictions and qualifications thereon. No shares of preferred stock had been issued as of December 31, 2016.
Net Loss Per Share	Net Loss Per Share Basic net loss per share is computed by dividing the net loss attributable to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted net loss per share is computed by dividing the net loss attributable to common shareholders by the weighted-average number of common and common equivalent shares outstanding during the period. Common share equivalents included in the diluted computation represent shares issuable upon assumed exercise of stock options and warrants using the treasury stock and “if converted” method. For periods in which net losses are incurred, weighted average shares outstanding is the same for basic and diluted loss per share calculations, as the inclusion of common share equivalents would have an anti-dilutive effect. For the years ended December 31, 2016 and 2015, outstanding options to purchase 5,232,165 shares of common stock and 4,432,165 shares of common stock, respectively, were excluded from the calculation of diluted net loss per share because they were anti-dilutive.
Concentration of Risk	Concentration of Risk As a non-operator oil and gas exploration and production company, and through its interest in a limited liability company (“Hupecol”) and concessions operated by Hupecol in the South American country of Colombia, the Company is dependent on the personnel, management and resources of the operators of its various properties to operate efficiently and effectively. As a non-operating joint interest owner, the Company has a right of investment refusal on specific projects and the right to examine and contest its division of costs and revenues determined by the operator. The Company currently has interests in concessions in Colombia and expects to be active in Colombia for the foreseeable future. The political climate in Colombia is unstable and could be subject to radical change over a very short period of time. In the event of a significant negative change in political and economic stability in the vicinity of the Company’s Colombian operations, the Company may be forced to abandon or suspend its efforts. Either of such events could be harmful to the Company’s expected business prospects. At December 31, 2016, 89% of the Company’s net oil and gas property investment, and 0% of its revenue for the year ended December 31, 2016, was with or derived from interests operated in Colombia. For 2016, our oil production from the Company’s mineral interests was sold to U.S. oil marketing companies based on the highest bid. The gas production is sold to U.S. natural gas marketing companies based on the highest bid. No purchaser accounted for more than 10% of our oil and gas sales. The Company reviews accounts receivable balances when circumstances indicate a balance may not be collectible. Based upon the Company’s review, no allowance for uncollectible accounts was deemed necessary at December 31, 2016 and 2015, respectively.
Subsequent Events	Subsequent Events The Company evaluated subsequent events for disclosure from December 31, 2016 through the date the consolidated financial statements were issued.
Recent Accounting Developments	Recent Accounting Developments No accounting standards or interpretations issued recently are expected to a have a material impact on our consolidated financial position, operations or cash flows.

Escrow Receivable (Tables)

Escrow Receivable (Tables)	12 Months Ended
	Dec. 31, 2016
ESCROW RECEIVABLE [Abstract]
Schedule of Escrow Receivables Relating to Oil and Gas Properties	At December 31, 2016 and December 31, 2015, the Company’s balance sheet reflected the following escrow receivables relating to various oil and gas properties previously sold by the Company: December 31, 2016 December 31, 2015 HDC LLC and HL LLC 15% Escrow $ — $ 251,125 HDC LLC and HL LLC 5% Contingency — 10,891 Total $ — $ 262,016

Oil and Gas Properties (Tables)

Oil and Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2016
Oil and Gas Property [Abstract]
Schedule of Evaluated Oil and Gas Properties Subject to Amortization	Evaluated oil and gas properties subject to amortization at December 31, 2016 included the following: United States South America Total Evaluated properties being amortized $ 6,184,631 $ 49,454,702 $ 55,639,333 Accumulated depreciation, depletion, amortization and impairment (6,018,996 ) (49,454,702 ) (55,473,698 ) Net capitalized costs $ 165,635 $ — $ 165,635 Evaluated oil and gas properties subject to amortization at December 31, 2015 included the following: United States South America Total Evaluated properties being amortized $ 5,385,898 $ 49,454,702 $ 54,840,600 Accumulated depreciation, depletion, amortization and impairment (5,133,124 ) (49,454,702 ) (54,587,826 ) Net capitalized costs $ 252,774 $ — $ 252,774
Schedule of Unevaluated Oil and Gas Properties Not Subject to Amortization	Unevaluated oil and gas properties not subject to amortization at December 31, 2016 included the following: United States South America Total Leasehold acquisition costs $ — $ 141,318 $ 141,318 Geological, geophysical, screening and evaluation costs 6,994 2,142,869 2,149,863 Total $ 6,994 $ 2,284,187 $ 2,291,181 Unevaluated oil and gas properties not subject to amortization at December 31, 2015 included the following: United States South America Total Leasehold acquisition costs $ 761,545 $ 141,319 $ 902,864 Geological, geophysical, screening and evaluation costs 4,143 1,972,056 1,976,199 Total $ 765,688 $ 2,133,375 $ 2,876,199

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Changes in Our Asset Retirement Liability	The following table describes changes in our asset retirement liability during each of the years ended December 31, 2016 and 2015. 2016 2015 ARO liability at January 1 $ 25,262 $ 28,147 Accretion expense 552 1,329 Changes in estimates 1,630 (4,214 ) ARO liability at December 31 $ 27,444 $ 25,262

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of Stock Option Activity	Option activity during 2016 and 2015 was as follows: Options Weighted Average Exercise Price Weighted Average Remaining Contractual Term (in Years) Aggregate Intrinsic Value Outstanding at December 31, 2014 3,392,832 $ 3.21 Granted 1,108,333 $ 0.21 Exercised — $ — Forfeited (69,000 ) $ 2.55 Outstanding at December 31, 2015 4,432,165 $ 2.47 Granted 820,000 $ 0.22 Exercised — $ — Forfeited (20,000 ) $ 4.10 Outstanding at December 31, 2016 5,232,165 $ 2.11 6.35 $ —
Schedule of Share-based Compensation Expense	The following table reflects share-based compensation recorded by the Company for 2016 and 2015: 2016 2015 Share-based compensation expense included in general and administrative expense $ 138,911 $ 91,625 Earnings per share effect of share-based compensation expense $ (0.00 ) $ (0.00 )

Taxes (Tables)

Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Taxes Tables
Schedule of Reconciliation of the Statutory Federal Income Tax	The following table sets forth a reconciliation of the statutory federal income tax for the years ending December 31, 2016 and 2015. 2016 2015 Income (loss) before income taxes $ (2,641,625 ) $ (3,811,341 ) Income tax expense (benefit) computed at statutory rates $ (924,569 ) $ (1,333,969 ) Permanent differences, nondeductible expenses 514 501 Increase (decrease) in valuation allowance 874,987 635,888 Return to accrual items — (764 ) Other adjustment 49,068 717,209 NOL adjustment — — Tax provision $ — $ 18,865 Total provision Foreign $ — $ 18,865 Total provision (benefit) $ — $ 18,865
Significant Components of the Deferred Tax Asset and Liability	Significant components of the deferred tax asset and liability as of December 31, 2016 and 2015 are set out below. 2016 2015 Non-Current Deferred tax assets: Net operating loss carry forward $ 16,872,064 $ 16,255,870 Foreign tax credit carry forward 505,745 505,745 Deferred state tax 23,277 23,277 Stock compensation 3,090,907 3,091,356 Book in excess of tax depreciation, depletion and capitalization methods on oil and gas properties (454,590 ) (713,832 ) Other (327,600 ) (327,600 ) Colombia future tax obligations — — Total Non-Current Deferred tax assets 19,709,803 18,834,816 Valuation Allowance (19,709,803 ) (18,834,816 ) Net deferred tax asset $ — $ —

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Payments Under Lease Agreement	The lease agreement requires future payments as follows: Year Amount 2017 $ 40,479 Total $ 40,479

Geographical Information (Table

Geographical Information (Tables)	12 Months Ended
	Dec. 31, 2016
Geographical Information Tables
Schedule of Revenues and Long Lived Assets Attributable to Geographical Area	Revenues for the years ended December 31, 2016 and 2015 and long-lived assets as of December 31, 2016 and 2015 attributable to each geographical area are presented below: 2016 2015 Revenues Long Lived Assets, Net Revenues Long Lived Assets, Net North America $ 165,910 $ 260,110 $ 429,435 $ 1,019,569 South America — 2,284,187 — 2,113,374 Total $ 165,910 $ 2,544,297 $ 429,435 $ 3,132,943

Supplemental Information On O27

Supplemental Information On Oil and Gas Exploration, Development and Production Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Supplemental Information On Oil And Gas Exploration Development And Production Activities Tables
Schedule of Oil and Gas Revenues and Lease Operating Expenses	The following table shows the Company’s oil and gas revenues and lease operating expenses, which excludes the joint venture expenses incurred in South America, by geographic area: 2016 2015 Revenues North America $ 165,910 $ 429,435 South America — — $ 165,910 $ 429,435 Production Cost North America $ 97,203 $ 148,067 South America — — $ 97,203 $ 148,067
Capitalized Costs and Accumulated Depletion Relating to Oil and Gas Producing Activities	Capitalized costs and accumulated depletion relating to the Company’s oil and gas producing activities as of December 31, 2016, all of which are onshore properties located in the United States and Colombia, South America are summarized below: United States South America Total Unproved properties not being amortized $ 6,994 $ 2,284,187 $ 2,291,181 Proved properties being amortized 6,184,631 49,454,702 55,639,333 Accumulated depreciation, depletion, amortization and impairment (6,018,996 ) (49,454,702 ) (55,473,698 ) Net capitalized costs $ 172,629 $ 2,284,187 $ 2,456,816
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities	Costs incurred in oil and gas property acquisition, exploration and development activities as of December 31, 2016 and 2015 are summarized below: 2016 United States South America Property acquisition costs: Proved $ — $ — Unproved 6,994 — Exploration costs 31,415 170,812 Development costs — — Total costs incurred $ 38,409 $ 170,812 2015 United States South America Property acquisition costs: Proved $ 16,669 $ — Unproved — — Exploration costs 72,500 79,511 Development costs — — Total costs incurred $ 89,169 $ 79,511
Schedule of Proved Developed and Undeveloped Reserves by Product Type	Total estimated proved developed and undeveloped reserves by product type and the changes therein are set forth below for the years indicated. United States South America Total Gas (mcf) Oil (bbls) Gas (mcf) Oil (bbls) Gas (mcf) Oil (bbls) Total proved reserves Balance December 31, 2014 72,710 34,130 — — 72,710 34,130 Revisions of prior estimates 17,136 (19,212 ) — — 17,136 (19,212 ) Production (32,146 ) (6,068 ) — — (32,146 ) (6,068 ) Balance December 31, 2015 57,700 8,850 — — 57,700 8,850 Revisions to prior estimates 2,524 2,763 — — 2,524 2,763 Production (20,204 ) (2,933 ) — — (20,204 ) (2,933 ) Balance December 31, 2016 40,020 8,680 — — 40,020 8,680 Proved developed reserves at December 31, 2015 57,700 8,850 — — 57,700 8,850 at December 31, 2016 40,020 8,680 — — 40,020 8,680 Proved undeveloped reserves at December 31, 2015 — — — — — — at December 31, 2016 — — — — — —
Standardized Measure of Discounted Future Net Cash Flows	Standardized measure of discounted future net cash flows at December 31, 2016: United States South America Total Future cash flows from sales of oil and gas $ 460,760 $ — $ 460,760 Future production cost (264,730 ) — (264,730 ) Future net cash flows 196,030 — 196,030 10% annual discount for timing of cash flow (31,900 ) — (31,900 ) Standardized measure of discounted future net cash flow relating to proved oil and gas reserves $ 164,130 $ — $ 164,130 Changes in standardized measure: Change due to current year operations Sales, net of production costs (68,707 ) — (68,707 ) Change due to revisions in standardized variables: Accretion of discount 25,438 — 25,438 Net change in sales and transfer price, net of production costs (147,362 ) — (147,362 ) Revision and others (43,109 ) — (43,109 ) Changes in production rates and other 143,490 — 143,490 Net (90,250 ) — (90,250 ) Beginning of year 254,380 — 254,380 End of year $ 164,130 $ — $ 164,130 Standardized measure of discounted future net cash flows at December 31, 2015: United States South America Total Future cash flows from sales of oil and gas $ 611,520 $ — $ 611,520 Future production cost (308,020 ) — (308,020 ) Future net cash flows 303,500 — 303,500 10% annual discount for timing of cash flow (49,120 ) — (49,120 ) Standardized measure of discounted future net cash flow relating to proved oil and gas reserves $ 254,380 $ — $ 254,380 Changes in standardized measure: Change due to current year operations Sales, net of production costs (281,368 ) — (285,582 ) Change due to revisions in standardized variables: Accretion of discount 183,828 — 183,828 Net change in sales and transfer price, net of production costs (405,129 ) — (405,129 ) Revision and others (176,014 ) — (176,014 ) Changes in production rates and other (617,498 ) — (613,285 ) Net (1,296,181 ) — (1,296,181 ) Beginning of year 1,550,561 — 1,550,561 End of year $ 254,380 $ — $ 254,380

Summarized Quarterly Financia28

Summarized Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Summarized Quarterly Financial Information Tables
Summarized Quarterly Financial Information	Three Months Ended March 31, June 30, Sept. 30, Dec. 31, 2016 Operating revenue $ 48,260 $ 33,887 $ 39,738 $ 44,025 Loss from operations (343,411 ) (492,202 ) (371,192 ) (1,442,026 ) Net loss (339,451 ) (490,406 ) (370,343 ) (1,441,425 ) Loss per common share – basic $ (0.01 ) $ (0.01 ) $ (0.01 ) $ (0.03 ) Loss per common share – diluted $ (0.01 ) $ (0.01 ) $ (0.01 ) $ (0.03 ) 2015 Operating revenue $ 101,971 $ 114,122 $ 124,448 $ 88,894 Loss from operations (1,191,769 ) (339,488 ) (468,332 ) (1,735,182 ) Net loss (1,187,064 ) (351,808 ) (463,566 ) (1,827,768 ) Loss per common share – basic $ (0.02 ) $ (0.01 ) $ (0.01 ) $ (0.04 ) Loss per common share – diluted $ (0.02 ) $ (0.01 ) $ (0.01 ) $ (0.04 )

Nature of Company and Summary29

Nature of Company and Summary of Significant Accounting Policies (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Net cash used in operations	$ 1,297,153	$ 1,837,977
Cash deposits in excess of the FDIC's current insured limit	158,000
Current insured limit on interest bearing accounts	250,000
Allowance for accounts receivable	262,016
Depletion and amortization	302,782	756,757
Accumulated amortization, depreciation and impairment	$ 55,563,591	54,676,723
Discount rate, net of related tax effects	10.00%
Impairment of oil and gas properties	$ 584,086	$ 1,718,088
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares issued	0	0
Options to purchase of common stock outstanding, shares	5,232,165	4,432,165
Concentration risk, percentage	0.00%
Oil and Gas Properties [Member]
Depletion and amortization	$ 301,786	$ 754,892
Accumulated amortization, depreciation and impairment	$ 55,473,698	54,587,826
Concentration risk, percentage	89.00%
Office Equipment [Member]
Depletion and amortization	$ 996	1,865
Accumulated amortization, depreciation and impairment	$ 89,893	$ 88,897

Escrow Receivable (Details Narr

Escrow Receivable (Details Narrative)	Dec. 31, 2016USD ($)
Escrow Receivable Details Narrative
Allowance for accounts receivable	$ 262,016

Escrow Receivable - Schedule of

Escrow Receivable - Schedule of Escrow Receivables Relating to Oil and Gas Properties (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Restricted Cash and Cash Equivalents Items [Line Items]
Escrow receivable - Total		$ 262,016
HDC LLC and HL LLC 15% Escrow [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Escrow receivable - Total		$ 251,125
Escrow receivables, percentage		15.00%
HDC LLC and HL LLC 5% Contingency [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Escrow receivable - Total		$ 10,891
Escrow receivables, percentage		5.00%

Oil and Gas Properties - Schedu

Oil and Gas Properties - Schedule of Evaluated Oil and Gas Properties Subject to Amortization (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Evaluated properties being amortized	$ 55,639,333	$ 54,840,600
Accumulated depreciation, depletion, amortization and impairment	(55,473,698)	(54,587,826)
Net capitalized costs	165,635	252,774
United States [Member]
Evaluated properties being amortized	6,184,631	5,385,898
Accumulated depreciation, depletion, amortization and impairment	(6,018,996)	(5,133,124)
Net capitalized costs	165,635	252,774
South America [Member]
Evaluated properties being amortized	49,454,702	49,454,702
Accumulated depreciation, depletion, amortization and impairment	(49,454,702)	(49,454,702)
Net capitalized costs

Oil and Gas Properties - Sche33

Oil and Gas Properties - Schedule of Unevaluated Oil and Gas Properties Not Subject to Amortization (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Leasehold acquisition costs	$ 141,318	$ 902,864
Geological, geophysical, screening and evaluation costs	2,149,863	1,976,199
Total	2,291,181	2,876,199
United States [Member]
Leasehold acquisition costs		761,545
Geological, geophysical, screening and evaluation costs	6,994	4,143
Total	6,994	765,688
South America [Member]
Leasehold acquisition costs	141,318	141,319
Geological, geophysical, screening and evaluation costs	2,142,869	1,972,056
Total	$ 2,284,187	$ 2,133,375

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Changes in Our Asset Retirement Liability (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligations - Schedule Of Changes In Our Asset Retirement Liability Details
ARO liability at January 1	$ 25,262	$ 28,147
Accretion expense	552	1,329
Changes in estimates	1,630	(4,214)
ARO liability at December 31	$ 27,444	$ 25,262

Stock-Based Compensation (Detai

Stock-Based Compensation (Details Narrative) - USD ($)	1 Months Ended			12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Aug. 12, 2015	Dec. 31, 2008
Number of stock option shares granted				820,000	1,108,333
Options granted exercise price of per share				$ 0.22	$ 0.21
Stock compensation amortized expense				$ 138,912	$ 91,625
Unrecognized share-based compensation expense related to non-vested stock options	$ 120,687			$ 120,687
Number of non-vested options	1,310,000			1,310,000
Weighted average period for recognition of compensation expense				1 year 2 months 23 days
Weighted average remaining contractual term of the outstanding options				6 years 4 months 6 days
Weighted average remaining contractual term of the exercisable options				5 years 6 months
Shares available for issuance	767,835			767,835
Number of common stock shares repurchased				702,557	190,000
Common stock shares repurchased value				$ 135,973	$ 38,152
Non Employee Director [Member]
Number of stock option shares granted				8,333	8,333
Stock option expected life				4 years 11 months 23 days
Fair value of options granted				$ 805
Risk free interest rate				1.36%
Expected stock volatility				106.00%
Non Employee Director [Member] | Share-based Compensation Award, Tranche One [Member]
Stock option vesting percentage				20.00%
Stock option grand period				10 years
Options granted exercise price of per share				$ 0.2158
Non Employee Director [Member] | Share-based Compensation Award, Tranche Two [Member]
Stock option vesting percentage				80.00%
New Officer [Member]
Number of stock option shares granted					900,000
Non Employee Directors [Member]
Number of stock option shares granted		800,000	20,000		200,000
Stock option grand period		10 years	5 years
Options granted exercise price of per share			$ 0.1982
Fair value of options granted			$ 2,896
Risk free interest rate			1.49%
Expected stock volatility			106.95%
Forfeiture rate			15.22%
Stock options vested date			Aug. 15, 2016
Option vesting period			5 years
Non Employee Directors [Member] | Ad Hoc Board Committee [Member]
Stock option expected life			4 years 11 months 27 days
Non Employee Directors [Member] | Minimum [Member]
Sale of shares of equity securities for cash				$ 10,000,000
Aggregate purchase price of asset				$ 10,000,000
Non Employee Directors [Member] | Share-based Compensation Award, Tranche One [Member]
Number of stock option shares granted				200,000
Stock option vesting percentage				20.00%
Stock option grand period				10 years
Options granted exercise price of per share				$ 0.2028
Fair value of options granted				$ 17,370
Risk free interest rate				1.73%
Expected stock volatility				105.00%
Non Employee Directors [Member] | Share-based Compensation Award, Tranche One [Member] | One Time Supplemental Grant [Member]
Number of stock option shares granted		600,000
Stock option vesting percentage		80.00%
Stock option expected life		5 years 3 months 11 days
Options granted exercise price of per share		$ 0.2201
Fair value of options granted		$ 32,640
Risk free interest rate		1.26%
Expected stock volatility		108.50%
Expected dividend yield		0.00%
Forfeiture rate		15.01%
Non Employee Directors [Member] | Share-based Compensation Award, Tranche Two [Member]
Stock option vesting percentage				80.00%
Stock option expected life				5 years 4 days
Non Employee Directors [Member] | Share-based Compensation Award, Tranche Two [Member] | One Time Supplemental Grant [Member]
Number of stock option shares granted		200,000
Stock option vesting percentage		20.00%
Stock option expected life		5 years 3 months 11 days
Options granted exercise price of per share		$ 0.2201
Fair value of options granted		$ 83,421
Risk free interest rate		1.26%
Expected stock volatility		108.50%
Sale of shares of equity securities for cash		$ 2,000,000
Non Employee Directors [Member] | June 7, 2017 [Member]
Stock option vesting percentage	50.00%
Non Employee Directors [Member] | June 7, 2018 [Member]
Stock option vesting percentage	50.00%
Employee [Member]
Number of stock option shares granted				900,000
Stock option grand period				10 years
Stock option expected life				4 years 11 months 23 days
Options granted exercise price of per share				$ 0.2158
Fair value of options granted				$ 82,000
Risk free interest rate				1.36%
Expected stock volatility				106.00%
2005 Plan [Member]
Number of options authorized to purchase shares of common stock						500,000
2008 Equity Incentive Plan [Member]
Number of options authorized to purchase shares of common stock							6,000,000

Stock-Based Compensation - Summ

Stock-Based Compensation - Summary of Stock Option Activity (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Options Outstanding at beginning of the period	4,432,165	3,392,832
Options Granted	820,000	1,108,333
Options Exercised
Options Forfeited	(20,000)	(69,000)
Options Outstanding at end of the period	5,232,165	4,432,165
Weighted-Average Exercise Price Outstanding at beginning of the period	$ 2.47	$ 3.21
Weighted-Average Exercise Price Granted	0.22	0.21
Weighted-Average Exercise Price Exercised
Weighted-Average Exercise Price Forfeited	4.10	2.55
Weighted-Average Exercise Price Outstanding at end of the period	$ 2.11	$ 2.47
Weighted Average Remaining Contractual Term (in Years)	6 years 4 months 6 days
Aggregate Intrinsic Value Outstanding at end of the period

Stock-Based Compensation - Sche

Stock-Based Compensation - Schedule of Share-based Compensation Expense (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Share-based compensation expense included in general and administrative expense	$ 138,912	$ 91,625
General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Share-based compensation expense included in general and administrative expense	$ 138,911	$ 91,625
Earnings per share effect of share-based compensation expense	$ 0	$ 0

Taxes (Details Narrative)

Taxes (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Federal tax loss carry forward	$ 48,205,895
Foreign tax credit carry forward	$ 505,745
Income tax rate, current	25.00%
Foreign tax expense		$ 18,865

Taxes - Schedule of Reconciliat

Taxes - Schedule of Reconciliation of the Statutory Federal Income Tax (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Taxes - Schedule Of Reconciliation Of Statutory Federal Income Tax Details
Income (loss) before income taxes	$ (2,641,625)	$ (3,811,341)
Income tax expense (benefit) computed at statutory rates	(924,569)	(1,333,969)
Permanent differences, nondeductible expenses	514	501
Increase (decrease) in valuation allowance	874,987	635,888
Return to accrual items		(764)
Other adjustment	49,068	717,209
NOL adjustment
Tax provision		18,865
Foreign		18,865
Total provision (benefit)		$ 18,865

Taxes - Significant Components

Taxes - Significant Components of the Deferred Tax Asset and Liability (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Taxes - Significant Components Of Deferred Tax Asset And Liability Details
Net operating loss carry forward	$ 16,872,064	$ 16,255,870
Foreign tax credit carry forward	505,745	505,745
Deferred state tax	23,277	23,277
Stock compensation	3,090,907	3,091,356
Book in excess of tax depreciation, depletion and capitalization methods on oil and gas properties	(454,590)	(713,832)
Other	(327,600)	(327,600)
Colombia future tax obligations
Total Non-Current Deferred tax assets	19,709,803	18,834,816
Valuation Allowance	(19,709,803)	(18,834,816)
Net deferred tax asset

Related Parties (Details Narrat

Related Parties (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
John F. Terwilliger [Member]
Overriding royalty interests owned	1.50%
Royalty payments	$ 0	$ 919
Orrie L. Tawes [Member]
Overriding royalty interests owned	1.50%
Royalty payments	$ 0	$ 919

Commitments and Contingencies42

Commitments and Contingencies (Details Narrative) - USD ($)	1 Months Ended	12 Months Ended
	Aug. 31, 2013	Dec. 31, 2016	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Operating lease agreement expiration date		May 31, 2017
Total rental expense		$ 107,620	$ 95,711
Description of production incentive compensation plan	The maximum percentage of the Company’s share of revenues from a well that may be designated to fund a Pool is 2% (the “Pool Cap”); provided, however, that with respect to wells with a net revenue interest to the 8/8 of less than 73%, the Pool Cap with respect to such wells shall be reduced on a 1-for-1 basis such that no portion of the Company’s revenues from a well may be designated to fund a Pool if the NRI is 71% or less.
Maximum percentage of revenue to fund a pool from a well	2.00%
Maximum percentage of revenue from a well considered for pool cap	73.00%
Maximum percentage of revenue from a well considered for pool NRI	71.00%
Period consider for payout of revenues to participants	60 days
Grants issued under plan		0
Reduction of revenue associated with plan		$ 0

Commitments and Contingencies -

Commitments and Contingencies - Schedule of Future Payments under Lease Agreement (Details)	Dec. 31, 2016USD ($)
Commitments and Contingencies Disclosure [Abstract]
2,017	$ 40,479
Total	$ 40,479

Subsequent Events (Details Narr

Subsequent Events (Details Narrative) - Subsequent Event [Member]	1 Months Ended
	Feb. 28, 2017USD ($)a	Jan. 31, 2017USD ($)LeaseBlocks$ / sharesshares
Percentage of working interest rate		25.00%
Percentage of proportionate back-in after prospect payout | $ / shares		$ 0.05
Number of block proportionate back-in after prospect payout | LeaseBlocks		2
Area of buliding acquire | a	717
Payments to acquire buliding | $	$ 986,000
12% Series A Convertible Preferred Stock [Member]
Estimated drilling cost for well | $		$ 1,700,000
Number of preferred stock issued | shares		1,200
Proceeds from issuance of preferred stock | $		$ 1,200,000
Dividend payable or declared date		Jul. 1, 2017
Preferred stock dividend percentage		12.00%
Debt conversion price per share | $ / shares		$ 0.20
Preferred stock liquidation preference price per share | $ / shares		$ 1,000
12% Series A Convertible Preferred Stock [Member] | Minimum [Member]
Premium issuance price decreased percentage		0.00%
12% Series A Convertible Preferred Stock [Member] | Maximum [Member]
Premium issuance price decreased percentage		12.00%

Geographical Information - Sche

Geographical Information - Schedule of Revenues and Long Lived Assets Attributable to Geographical Area (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenue	$ 44,025	$ 39,738	$ 33,887	$ 48,260	$ 88,894	$ 124,448	$ 114,122	$ 101,971	$ 165,910	$ 429,435
Long Lived Assets, Net	2,544,297				3,132,943				2,544,297	3,132,943
North America [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenue									165,910	429,435
South America [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenue
Reportable Geographical Components [Member] | North America [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenue									165,910	429,435
Long Lived Assets, Net	260,110				1,019,569				260,110	1,019,569
Reportable Geographical Components [Member] | South America [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenue
Long Lived Assets, Net	$ 2,284,187				$ 2,113,374				$ 2,284,187	$ 2,113,374

Supplemental Information on O46

Supplemental Information on Oil And Gas Exploration, Development And Production Activities (Unaudited) (Details Narrative)	12 Months Ended
	Dec. 31, 2016$ / shares
Period of average prices used in calculating proved oil and gas reserves	12 months
Minimum experience of Vice President of independent professional engineering firm	30 years
Period of average prices used in calculating future cash inflows related to standardized measure of discounted future net cash flows	12 months
Discount rate of estimated future cash flows	10.00%
United States [Member]
Amortization rate per unit	$ 48.57
South America [Member]
Amortization rate per unit	$ 0

Supplemental Information on O47

Supplemental Information on Oil And Gas Exploration, Development And Production Activities (Unaudited) - Schedule of Oil and Gas Revenues and Lease Operating Expenses (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenue	$ 44,025	$ 39,738	$ 33,887	$ 48,260	$ 88,894	$ 124,448	$ 114,122	$ 101,971	$ 165,910	$ 429,435
Production Cost									97,203	148,067
North America [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenue									165,910	429,435
Production Cost									97,203	148,067
South America [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenue
Production Cost

Supplemental Information on O48

Supplemental Information on Oil And Gas Exploration, Development And Production Activities (Unaudited) - Capitalized Costs and Accumulated Depletion Relating to Oil and Gas Producing Activities (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved properties not being amortized	$ 2,291,181	$ 2,876,199
Proved properties being amortized	55,639,333	54,840,600
Accumulated depreciation, depletion, amortization and impairment	(55,473,698)	(54,587,826)
Net capitalized costs	2,456,816
United States [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved properties not being amortized	6,994
Proved properties being amortized	6,184,631
Accumulated depreciation, depletion, amortization and impairment	(6,018,996)
Net capitalized costs	172,629
South America [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved properties not being amortized	2,284,187	2,133,375
Proved properties being amortized	49,454,702	49,454,702
Accumulated depreciation, depletion, amortization and impairment	(49,454,702)	$ (49,454,702)
Net capitalized costs	$ 2,284,187

Supplemental Information on O49

Supplemental Information on Oil And Gas Exploration, Development And Production Activities (Unaudited) - Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
United States [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved		$ 16,669
Unproved	6,994
Exploration costs	31,415	72,500
Development costs
Total costs incurred	38,409	89,169
South America [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved
Unproved
Exploration costs	170,812	79,511
Development costs
Total costs incurred	$ 170,812	$ 79,511

Supplemental Information on O50

Supplemental Information on Oil And Gas Exploration, Development And Production Activities (Unaudited) - Schedule of Proved Developed and Undeveloped Reserves by Product Type (Details)	12 Months Ended
	Dec. 31, 2016MMcfbbl	Dec. 31, 2015MMcfbbl
Gas [Member]
Reserve Quantities [Line Items]
Balance at beginning of the period | MMcf	57,700	72,710
Revisions of prior estimates | MMcf	2,524	17,136
Production | MMcf	(20,204)	(32,146)
Balance at end of the period | MMcf	40,020	57,700
Proved developed reserves | MMcf	40,020	57,700
Proved undeveloped reserves | MMcf
Gas [Member] | United States [Member]
Reserve Quantities [Line Items]
Balance at beginning of the period | MMcf	57,700	72,710
Revisions of prior estimates | MMcf	2,524	17,136
Production | MMcf	(20,204)	(32,146)
Balance at end of the period | MMcf	40,020	57,700
Proved developed reserves | MMcf	40,020	57,700
Proved undeveloped reserves | MMcf
Gas [Member] | South America [Member]
Reserve Quantities [Line Items]
Balance at beginning of the period | MMcf
Purchase of minerals in place | MMcf
Revisions of prior estimates | MMcf
Production | MMcf
Balance at end of the period | MMcf
Proved developed reserves | MMcf
Proved undeveloped reserves | MMcf
Oil [Member]
Reserve Quantities [Line Items]
Balance at beginning of the period | bbl	8,850	34,130
Revisions of prior estimates | bbl	2,763	(19,212)
Production | bbl	(2,933)	(6,068)
Balance at end of the period | bbl	8,680	8,850
Proved developed reserves | bbl	8,680	8,850
Proved undeveloped reserves | bbl
Oil [Member] | United States [Member]
Reserve Quantities [Line Items]
Balance at beginning of the period | bbl	8,850	34,130
Revisions of prior estimates | bbl	2,763	(19,212)
Production | bbl	(2,933)	(6,068)
Balance at end of the period | bbl	8,680	8,850
Proved developed reserves | bbl	8,680	8,850
Proved undeveloped reserves | bbl
Oil [Member] | South America [Member]
Reserve Quantities [Line Items]
Balance at beginning of the period | bbl
Purchase of minerals in place | bbl
Revisions of prior estimates | bbl
Production | bbl
Balance at end of the period | bbl
Proved developed reserves | bbl
Proved undeveloped reserves | bbl

Supplemental Information on O51

Supplemental Information on Oil And Gas Exploration, Development And Production Activities (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash flows from sales of oil and gas			$ 460,760	$ 611,520
Future production cost			(264,730)	(308,020)
Future net cash flows			196,030	303,500
10% annual discount for timing of cash flow			(31,900)	(49,120)
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves	$ 164,130	$ 254,380	164,130	254,380
Change due to current year operations Sales, net of production costs	(68,707)	(285,582)
Accretion of discount	25,438	183,828
Net change in sales and transfer price, net of production costs	(147,362)	(405,129)
Revision and others	(43,109)	(176,014)
Changes in production rates and other	143,490	(613,285)
Net	(90,250)	(1,296,181)
Beginning of year	254,380	1,550,561
End of year	164,130	254,380
United States [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash flows from sales of oil and gas			460,760	611,520
Future production cost			(264,730)	(308,020)
Future net cash flows			196,030	303,500
10% annual discount for timing of cash flow			(31,900)	(49,120)
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves	164,130	1,550,561	164,130	254,380
Change due to current year operations Sales, net of production costs	(68,707)	(281,368)
Accretion of discount	25,438	183,828
Net change in sales and transfer price, net of production costs	(147,362)	(405,129)
Revision and others	(43,109)	(176,014)
Changes in production rates and other	143,490	(617,498)
Net	(90,250)	(1,296,181)
Beginning of year	254,380	1,550,561
End of year	164,130	254,380
South America [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash flows from sales of oil and gas
Future production cost
Future net cash flows
10% annual discount for timing of cash flow
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves
Change due to current year operations Sales, net of production costs
Accretion of discount
Net change in sales and transfer price, net of production costs
Revision and others
Changes in production rates and other
Net
Beginning of year
End of year

Summarized Quarterly Financia52

Summarized Quarterly Financial Information (Unaudited) - Summarized Quarterly Financial Information (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Operating revenue	$ 44,025	$ 39,738	$ 33,887	$ 48,260	$ 88,894	$ 124,448	$ 114,122	$ 101,971	$ 165,910	$ 429,435
Loss from operations	(1,442,026)	(371,192)	(492,202)	(343,411)	(1,735,182)	(468,332)	(339,488)	(1,191,769)	2,648,831	3,734,771
Net loss	$ (1,441,425)	$ (370,343)	$ (490,406)	$ (339,451)	$ (1,827,768)	$ (463,566)	$ (351,808)	$ (1,187,064)	$ (2,641,625)	$ (3,830,206)
loss per common share - basic	$ (0.03)	$ (0.01)	$ (0.01)	$ (0.01)	$ (0.04)	$ (0.01)	$ (0.01)	$ (0.02)
loss per common share - diluted	$ (0.03)	$ (0.01)	$ (0.01)	$ (0.01)	$ (0.04)	$ (0.01)	$ (0.01)	$ (0.02)