Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2014 | Mar. 09, 2015 | Jun. 30, 2014 |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | HOUSTON AMERICAN ENERGY CORP | ||
Entity Central Index Key | 1156041 | ||
Current Fiscal Year End Date | -19 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Smaller Reporting Company | ||
Entity Public Float | $18.70 | ||
Entity Common Stock, Shares Outstanding | 52,169,945 | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY | ||
Document Type | 10-K | ||
Amendment Flag | FALSE | ||
Document Period End Date | 31-Dec-14 |
CONSOLIDATED_BALANCE_SHEETS
CONSOLIDATED BALANCE SHEETS (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
CURRENT ASSETS | ||
Cash | $4,052,212 | $7,578,730 |
Escrow receivable | 321,428 | 1,921,217 |
Insurance claim receivable | 8,612,681 | 0 |
Prepaid expenses and other current assets | 124,960 | 46,175 |
TOTAL CURRENT ASSETS | 13,111,281 | 9,546,122 |
Oil and gas properties, full cost method | ||
Costs subject to amortization | 54,025,617 | 50,320,591 |
Costs not being amortized | 3,586,284 | 3,802,042 |
Office equipment | 90,004 | 90,004 |
Total | 57,701,905 | 54,212,637 |
Accumulated depletion, depreciation, amortization, and impairment | -52,201,878 | -50,349,833 |
PROPERTY AND EQUIPMENT, NET | 5,500,027 | 3,862,804 |
Other assets | 3,167 | 3,167 |
TOTAL ASSETS | 18,614,475 | 13,412,093 |
CURRENT LIABILITIES | ||
Accounts payable | 181,683 | 8,119 |
Litigation settlement payable | 7,000,000 | 0 |
Accrued legal fees | 1,722,681 | 0 |
Contingent liability | 400,000 | 0 |
Accrued expenses | 10,100 | 31,336 |
Taxes payable | 0 | 190,181 |
TOTAL CURRENT LIABILITIES | 9,314,464 | 229,636 |
LONG-TERM LIABILITIES | ||
Reserve for plugging and abandonment costs | 28,147 | 8,424 |
TOTAL LIABILITIES | 9,342,611 | 238,060 |
COMMITMENTS AND CONTINGENCIES | ||
SHAREHOLDERS' EQUITY | ||
Preferred stock, par value $0.001; 10,000,000 shares authorized, 0 shares issued and outstanding | 0 | 0 |
Common stock, par value $0.001; 150,000,000 shares authorized, 52,169,945 shares issued and outstanding | 52,170 | 52,170 |
Additional paid-in capital | 65,928,056 | 65,477,046 |
Accumulated deficit | -56,708,362 | -52,355,183 |
TOTAL SHAREHOLDERS' EQUITY | 9,271,864 | 13,174,033 |
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $18,614,475 | $13,412,093 |
CONSOLIDATED_BALANCE_SHEETS_Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
SHAREHOLDERS' EQUITY | ||
Preferred stock, par value (in dollars per share) | $0.00 | $0.00 |
Preferred stock, authorized (in shares) | 10,000,000 | 10,000,000 |
Preferred stock, issued (in shares) | 0 | 0 |
Preferred stock, outstanding (in shares) | 0 | 0 |
Common stock, par value (in dollars per share) | $0.00 | $0.00 |
Common stock, authorized (in shares) | 150,000,000 | 150,000,000 |
Common stock, issued (in shares) | 52,169,945 | 52,169,945 |
Common stock, outstanding (in shares) | 52,169,945 | 52,169,945 |
CONSOLIDATED_STATEMENTS_OF_OPE
CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
CONSOLIDATED STATEMENTS OF OPERATIONS [Abstract] | ||
OIL AND GAS REVENUE | $363,455 | $347,139 |
EXPENSES OF OPERATIONS | ||
Lease operating expense and severance tax | 113,233 | 81,774 |
Depreciation and depletion | 359,897 | 24,954 |
Impairment of oil and gas properties | 1,492,148 | 0 |
Bad debt expense | 0 | 86,507 |
General and administrative expense | 2,356,519 | 3,417,292 |
Total operating expenses | 4,321,797 | 3,610,527 |
Gain on sale of oil and gas properties | 0 | 45,475 |
Loss from operations | -3,958,342 | -3,217,913 |
OTHER INCOME (EXPENSE) | ||
Interest income | 7,349 | 33,238 |
Contingent loss | -400,000 | 0 |
Other expense | -3 | -1,080 |
Total other income (expense) | -392,654 | 32,158 |
Net loss before taxes | -4,350,996 | -3,185,755 |
Income tax expense (benefit) | 2,183 | -12,274 |
Net loss | ($4,353,179) | ($3,173,481) |
Basic and diluted net loss per common share outstanding (in dollars per share) | ($0.08) | ($0.06) |
Basic and diluted weighted average number of common shares outstanding (in shares) | 52,169,945 | 52,175,677 |
CONSOLIDATED_STATEMENTS_OF_CHA
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (USD $) | Common Stock [Member] | Additional Paid-in Capital [Member] | Accumulated Deficit [Member] | Total |
Balance at Dec. 31, 2012 | $52,180 | $63,963,257 | ($49,181,702) | $14,833,735 |
Balance (in shares) at Dec. 31, 2012 | 52,180,045 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Options issued to directors | 0 | 72,399 | 0 | 72,399 |
Options issued to employees | 0 | 1,284,240 | 0 | 1,284,240 |
Restricted stock issued to employees | 0 | 157,140 | 0 | 157,140 |
Restricted stock cancelled | -10 | 10 | 0 | 0 |
Restricted stock cancelled (in shares) | -10,100 | |||
Net loss | 0 | 0 | -3,173,481 | -3,173,481 |
Balance at Dec. 31, 2013 | 52,170 | 65,477,046 | -52,355,183 | 13,174,033 |
Balance (in shares) at Dec. 31, 2013 | 52,169,945 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Options issued to directors | 0 | 42,676 | 0 | 42,676 |
Options issued to employees | 0 | 371,513 | 0 | 371,513 |
Restricted stock issued to employees | 0 | 36,821 | 0 | 36,821 |
Net loss | 0 | 0 | -4,353,179 | -4,353,179 |
Balance at Dec. 31, 2014 | $52,170 | $65,928,056 | ($56,708,362) | $9,271,864 |
Balance (in shares) at Dec. 31, 2014 | 52,169,945 |
CONSOLIDATED_STATEMENTS_OF_CAS
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
CASH FLOW FROM OPERATING ACTIVITIES | ||
Net loss | ($4,353,179) | ($3,173,481) |
Adjustments to reconcile net loss to net cash provided by (used in) operations | ||
Depreciation and depletion | 359,897 | 24,954 |
Impairment of oil and gas properties | 1,492,148 | 0 |
Deferred tax expense (benefit) | 451,010 | 1,513,779 |
Accretion of asset retirement obligation | 628 | 552 |
Gain on sale of oil and gas properties | 0 | -45,475 |
Bad debt expense | 0 | 86,507 |
Contingent loss | 400,000 | 0 |
Change in operating assets and liabilities: | ||
Increase in income tax refund receivable | 0 | 3,349,798 |
Increase in accounts receivable | -83,878 | 0 |
Increase in insurance receivable | -8,612,681 | 0 |
Increase in prepaid expense and other current assets | 5,093 | -9,636 |
(Decrease) increase in accounts payable and accrued expenses | -129,344 | -136,208 |
Increase in settlement payable | 7,000,000 | 0 |
Increase in accrued legal fees | 1,722,681 | 0 |
Foreign equity taxes payable | 0 | -1,714,224 |
Net cash used in operations | -1,747,625 | -103,434 |
CASH FLOW FROM INVESTING ACTIVITIES | ||
Release of restricted cash | 0 | 3,056,250 |
Payments for acquisition and development of oil and gas properties and assets | -3,364,932 | -1,219,917 |
Proceeds from sale of Colombian properties, net of expenses | 0 | 45,475 |
Proceeds from escrow receivable, net | 1,586,039 | 174,011 |
Net cash provided by (used in) investing activities | -1,778,893 | 2,055,819 |
INCREASE (DECREASE) IN CASH | -3,526,518 | 1,952,385 |
Cash, beginning of year | 7,578,730 | 5,626,345 |
Cash, end of year | 4,052,212 | 7,578,730 |
SUPPLEMENTAL CASH FLOW INFORMATION: | ||
Interest paid | 0 | 0 |
Taxes paid | 192,364 | 1,726,498 |
SUPPLEMENTAL NON-CASH INVESTING AND FINANCING ACTIVITIES | ||
Accrued oil and gas development costs | 105,241 | -3,219,128 |
Net change in estimate of asset retirement obligation | 19,095 | 0 |
Cancellation of stock | $0 | ($10) |
NATURE_OF_COMPANY_AND_SUMMARY_
NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2014 | |
NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [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 Gulf Coast area of the United States and international locations with proven production, which to date has focused on Colombia, South America. | |
Consolidation | |
The accompanying consolidated financial statements include all accounts of HUSA and its subsidiaries (HAEC Louisiana 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. | |
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 $3.2 million in excess of the FDIC’s current insured limit of $250,000 at December 31, 2014 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, 2014, the Company evaluated their receivables and determined an allowance was not required. | |
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, 2014 or 2013. | |
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 $348,197 and $12,111 for the years ended December 31, 2014 and 2013, respectively and accumulated amortization, depreciation and impairment was $52,114,846 and $50,274,501 at December 31, 2014 and 2013, respectively. | |
Costs Excluded | |
Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent costs of investments in unproved properties. The Company excludes these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the costs subject to amortization. | |
Ceiling Test | |
Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X. The ceiling test determines a limit, on a country-by-country basis, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment (“DD&A”) and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, calculated for 2014 using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) with consideration of price change only to the extent provided by contractual arrangement, discounted at 10%, net of related tax effects. If capitalized costs exceed this limit, the excess is charged to expense and reflected as additional accumulated DD&A. During the year, the Company impaired oil and gas properties in the amount of $1,492,148. | |
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 $11,700 and $12,843 for 2014 and 2013, respectively, and accumulated depreciation was $87,032 and $75,332 at December 31, 2014 and 2013, 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. | |
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 have been issued. | |
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 income (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 year ended December 31, 2014, outstanding options to purchase 2,632,832 shares of common stock were excluded from the calculation of diluted net loss per share because they were anti-dilutive. For the year ended December 31, 2013, outstanding options to purchase 2,592,832 shares of common stock were excluded from the calculation of diluted net loss per share because they were anti-dilutive. | |
Concentration of Risk | |
The Company is dependent upon the industry skills and contacts of John F. Terwilliger, the chief executive officer, to identify potential acquisition targets in the onshore coastal Gulf of Mexico region of Texas and Louisiana and in the South American country of Colombia. Further, 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 Hupecol 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, 2014, 36.7% of the Company’s net oil and gas property investment, and 0% of its revenue for the year ended December 31, 2014, was with or derived from interests operated in Colombia. | |
For 2014, 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, 2014 and 2013, respectively. | |
Subsequent Events | |
The Company evaluated subsequent events from December 31, 2014 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, 2014 | |||||||||
ESCROW RECEIVABLE [Abstract] | |||||||||
ESCROW RECEIVABLE | NOTE 2—ESCROW RECEIVABLE | ||||||||
At December 31, 2014 and December 31, 2013, the Company’s balance sheet reflected the following escrow receivables relating to various oil and gas properties previously held by the Company: | |||||||||
December 31, | December 31, | ||||||||
2014 | 2013 | ||||||||
Tambaqui Escrow | $ | 4,331 | $ | 22,029 | |||||
HDC LLC and HL LLC 15% Escrow | 294,383 | 1,827,929 | |||||||
HDC LLC and HL LLC 5% Contingency | 11,256 | 57,321 | |||||||
HC LLC 5% Contingency | 11,458 | 13,938 | |||||||
TOTAL | $ | 321,428 | $ | 1,921,217 | |||||
The principal escrow receivables relate to the sale of HupecolCuerva LLC (“HC LLC”) and the 2010 sale of HDC LLC and Hupecol Llanos LLC (“HL LLC”). | |||||||||
Changes in escrow receivables during 2014 reflect the release of an aggregate of $1,586,039 from the various escrow accounts, and netting an accrued liability of $13,750. |
OIL_AND_GAS_PROPERTIES
OIL AND GAS PROPERTIES | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
OIL AND GAS PROPERTIES [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, 2014 included the following: | |||||||||||||
United | South | Total | |||||||||||
States | America | ||||||||||||
Evaluated properties being amortized | $ | 4,570,915 | $ | 49,454,702 | $ | 54,025,617 | |||||||
Accumulated depreciation, depletion, amortization and impairment | -2,660,144 | -49,454,702 | -52,114,846 | ||||||||||
Net capitalized costs | $ | 1,910,771 | $ | — | $ | 1,910,771 | |||||||
Evaluated oil and gas properties subject to amortization at December 31, 2013 included the following: | |||||||||||||
United | South | Total | |||||||||||
States | America | ||||||||||||
Evaluated properties being amortized | $ | 865,889 | $ | 49,454,702 | $ | 50,320,591 | |||||||
Accumulated depreciation, depletion, amortization and impairment | (819,799 | ) | (49,454,702 | ) | (50,274,501 | ) | |||||||
Net capitalized costs | $ | 46,090 | $ | — | $ | 46,090 | |||||||
Unevaluated Oil and Gas Properties | |||||||||||||
Unevaluated oil and gas properties not subject to amortization at December 31, 2014 included the following: | |||||||||||||
North | South | Total | |||||||||||
America | America | ||||||||||||
Leasehold acquisition costs | $ | 868,301 | $ | 141,319 | $ | 1,009,620 | |||||||
Geological, geophysical, screening and evaluation costs | 683,976 | 1,892,688 | 2,576,664 | ||||||||||
Total | $ | 1,552,277 | $ | 2,034,007 | $ | 3,586,284 | |||||||
Unevaluated oil and gas properties not subject to amortization at December 31, 2013 included the following: | |||||||||||||
North | South | Total | |||||||||||
America | America | ||||||||||||
Leasehold acquisition costs | $ | 1,234,888 | $ | 131,335 | $ | 1,366,223 | |||||||
Geological, geophysical, screening and evaluation costs | 777,618 | 1,658,201 | 2,435,819 | ||||||||||
Total | $ | 2,012,506 | $ | 1,789,536 | $ | 3,802,042 |
ASSET_RETIREMENT_OBLIGATION
ASSET RETIREMENT OBLIGATION | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
ASSET RETIREMENT OBLIGATION [Abstract] | |||||||||
ASSET RETIREMENT OBLIGATION | NOTE 4—Asset Retirement Obligation | ||||||||
The following table describes changes in our asset retirement liability during each of the years ended December 31, 2014 and 2013. | |||||||||
2014 | 2013 | ||||||||
ARO liability at January 1 | $ | 8,424 | $ | 7,872 | |||||
Accretion expense | 628 | 552 | |||||||
Liabilities incurred from drilling | 20,812 | — | |||||||
Liabilities settled—assets sold | — | — | |||||||
Changes in estimates | (1,717 | ) | — | ||||||
ARO liability at December 31, | $ | 28,147 | $ | 8,424 |
STOCKBASED_COMPENSATION
STOCK-BASED COMPENSATION | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
STOCK-BASED COMPENSATION [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 allowed for the issuance of up to 2,200,000 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. | ||||||||||||
During 2012 and 2013, the Company’s board of directors and shareholders adopted amendments to the Company’s 2008 Equity Incentive Plan to increase the shares reserved to 6,000,000 shares. | ||||||||||||
Stock Option Activity | ||||||||||||
During 2013, options to purchase an aggregate of 100,000 shares were granted to non-employee directors and options to purchase an aggregate of 1,200,000 shares were granted to employees. | ||||||||||||
The 100,000 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 $0.3075 per share. The option grants to non-employee directors were valued on the date of grant at $24,507using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 1.26%, (2) expected life in years of 5.6, (3) expected stock volatility of 105%, and (4) expected dividend yield of 0%. 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. | ||||||||||||
The 1,200,000 options granted to employees vested 50% on the grant date and vest as to the remaining 50% on the first anniversary of the grant date, have a ten year life and have an exercise price of $0.3075 per share. The option grants to employees were valued on the date of grant at $294,085 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 5.6, (3) expected stock volatility of 105%, and (4) expected dividend yield of 0%. 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 July and August, 2013, respectively, the employment of two officers terminated. As a result of such terminations, the unvested options granted those officers during 2013, covering 150,000 shares each, terminated and the same were forfeited. The remaining options held by those officers, all of which were out-of-the-money, covering an aggregate of 1,520,000 shares, expired three months following the respective termination dates. | ||||||||||||
In 2014, options to purchase an aggregate of 200,000 shares were granted to non-employee directors and options to purchase an aggregate of 600,000 shares were granted to an employee. | ||||||||||||
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 $0.415 per share. The option grants to non-employee directors were valued on the date of grant at $46,651 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 1.57%, (2) expected life in years of 4.65, (3) expected stock volatility of 103.6%, and (4) expected dividend yield of 0%. 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. | ||||||||||||
The 600,000 options granted to an employee 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 the realization of revenues from oil and gas production on the Serrania prospect or receipt of proceeds from the sale of the Serrania prospect, have a ten year life and have an exercise price of $0.415 per share. The option grants to the employee were valued on the date of grant at $126,355 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 1.57%, (2) expected life in years of 4.65, (3) expected stock volatility of 103.6%, and (4) expected dividend yield of 0%. 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. | ||||||||||||
Option activity during 2014 and 2013 was as follows: | ||||||||||||
Options | Weighted | Weighted | Aggregate | |||||||||
Average | Average | Intrinsic | ||||||||||
Exercise | Remaining | Value | ||||||||||
Price | Contractual | |||||||||||
Term (in | ||||||||||||
Years) | ||||||||||||
Outstanding at December 31, 2012 | 2,223,057 | $ | 5.68 | |||||||||
Granted | 2,215,525 | $ | 0.86 | |||||||||
Exercised | — | $ | — | |||||||||
Forfeited | (2,065,750 | ) | $ | 2.53 | ||||||||
Outstanding at December 31, 2013 | 2,592,832 | $ | 4.07 | |||||||||
Granted | 800,000 | $ | 0.42 | |||||||||
Exercised | — | $ | — | |||||||||
Forfeited | — | $ | — | |||||||||
Outstanding at December 31, 2014 | 3,392,832 | $ | 3.21 | 6.02 | $ — | |||||||
During 2014 and 2013, the Company recognized $414,189 and $1,356,639, respectively, of stock compensation expense attributable to outstanding stock option grants, including current period grants and unamortized expense associated with prior period grants. | ||||||||||||
As of December 31, 2014, non-vested options totaled 728,000 and total unrecognized stock-based compensation expense related to non-vested stock options was $114,730. The unrecognized expense is expected to be recognized over a weighted average period of 1.97 years. The weighted average remaining contractual term of the outstanding options and exercisable options at December 31, 2014 is 6.79 years and 6.02 years, respectively. | ||||||||||||
As of December 31, 2014, there were 2,607,168 shares of common stock available for issuance pursuant to future stock or option grants under the Plans. | ||||||||||||
Restricted Stock Activity | ||||||||||||
During 2011, the Company granted to officers an aggregate of 45,000 shares of restricted stock, which shares vest over a period of three years. The fair value of $743,400 was determined based on the fair market value of the shares on the date of grant. This value is being amortized over the vesting period, and during 2014 and 2013, $36,821 and $157,140 was amortized to expense respectively. As a result of the termination of two officers, 5,000 shares of restricted stock were forfeited and cancelled during 2013 with respect to each of the terminated officers. As of December 31, 2014, there was $0 of unrecognized compensation cost related to unvested restricted stock. | ||||||||||||
Share-Based Compensation Expense | ||||||||||||
The following table reflects share-based compensation recorded by the Company for 2014 and 2013: | ||||||||||||
2014 | 2013 | |||||||||||
Share-based compensation expense included in general and administrative expense | $ | 451,010 | $ | 1,513,779 | ||||||||
Earnings per share effect of share-based compensation expense | $ | (0.01 | ) | $ | (0.03 | ) |
TAXES
TAXES | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
TAXES [Abstract] | |||||||||
TAXES | NOTE 6—TAXES | ||||||||
The following table sets forth a reconciliation of the statutory federal income tax for the years ending December 31, 2014 and 2013. | |||||||||
2014 | 2013 | ||||||||
Income (loss) before income taxes | $ | (4,350,996 | ) | $ | (3,185,755 | ) | |||
Income tax expense (benefit) computed at statutory rates | $ | (1,523,613 | ) | $ | (1,115,014 | ) | |||
Permanent differences, nondeductible expenses | 141,446 | (1,177,769 | ) | ||||||
Increase (decrease) in valuation allowance | (696,514 | ) | (902,498 | ) | |||||
Change in tax rate | — | (79,409 | ) | ||||||
Return to accrual items | 1,178,681 | 127,913 | |||||||
Foreign tax credit | — | 3,658,139 | |||||||
Other adjustment | — | (21,156 | ) | ||||||
NOL adjustment | 902,183 | (502,480 | ) | ||||||
State (net of federal benefit) | — | — | |||||||
Tax provision (benefit) | $ | 2,183 | $ | (12,274 | ) | ||||
Total Provision | |||||||||
Current Federal | $ | — | $ | — | |||||
Current State | — | — | |||||||
Deferred Federal | — | — | |||||||
Deferred State | — | — | |||||||
Permanent True-up | — | (21,154 | ) | ||||||
Foreign | 2,183 | 8,880 | |||||||
Total provision (benefit) | $ | 2,183 | $ | (12,274 | ) | ||||
At December 31, 2014 the Company has a federal tax loss carry forward of $44,930,526 and a foreign tax credit carry forward of $486,880, 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, 2014 and 2013 are set out below. | |||||||||
2014 | 2013 | ||||||||
Non-Current Deferred tax assets: | |||||||||
Net operating loss carry forwards | $ | 15,764,184 | $ | 17,003,714 | |||||
Foreign tax credit carry forwards | 486,880 | 484,697 | |||||||
Deferred state tax | 23,277 | 23,277 | |||||||
Stock compensation | 3,525,473 | 3,618,643 | |||||||
Book in excess of tax depreciation, depletion, and capitalization methods on oil and gas properties | (1,524,310 | ) | (2,151,329 | ) | |||||
Other | (76,576 | ) | (83,560 | ) | |||||
Colombia future tax obligations | — | — | |||||||
Total Non-Current Deferred tax assets | 18,198,928 | 18,895,442 | |||||||
Valuation Allowance | (18,198,928 | ) | (18,895,442 | ) | |||||
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 2014 and 2013, we recorded foreign tax expense of $2,183 and $8,880, respectively. |
RELATED_PARTIES
RELATED PARTIES | 12 Months Ended |
Dec. 31, 2014 | |
RELATED PARTIES [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, 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 2014 and 2013, Mr. Terwilliger received royalty payments relating to those properties totaling $20,682 and $20,305, respectively, and Mr. Tawes received royalty payments relating to those properties totaling $20,682 and $20,305, respectively (see Note 8). |
COMMITMENTS_AND_CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
COMMITMENTS AND CONTINGENCIES [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 | ||||
2015 | $ | 93,793 | |||
2016 | 96,162 | ||||
2017 | 40,469 | ||||
Total | $ | 230,424 | |||
Total rental expense was $98,659 and $97,220 in 2014 and 2013, 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. | |||||
Silverman Shareholder Class Action Suit. On April 27, 2012, a purported class action lawsuit was filed in the U.S. District Court for the Southern District of Texas against the Company and certain of its executive officers: Steve Silverman v. Houston American Energy Corp. et al., Case No. 4:12-CV-1332. The complaint generally alleged that, between March 29, 2010 and April 18, 2012, all of the defendants violated Sections 10(b) of the Securities Exchange Act of 1934 and SEC Rule 10b-5 and the individual defendants violated Section 20(a) of the Exchange Act in making materially false and misleading statements including certain statements related to the status and viability of the Tamandua #1 well on the Company’s CPO 4 prospect. Two additional class action lawsuits were filed against us in May 2012. The complaints sought unspecified damages, interest, attorneys’ fees, and other costs. On September 20, 2012, the court consolidated the class action lawsuits and appointed a lead plaintiff and on November 15, 2012 the lead plaintiffs filed an amended complaint. The amended complaint, among other things, expanded the putative class period to November 9, 2009 to April 18, 2012 and added allegations challenging a November 2009 estimate concerning the CPO 4 prospect. On January 14, 2013, we filed a motion to dismiss and, on August 22, 2013, the court granted the motion and dismissed the complaint. The plaintiffs subsequently filed a Notice of Appeal of the dismissal of the complaint. On July 15, 2014, the U.S. Court of Appeals for the Fifth Circuit reversed the dismissal of the case. The appellate court ruling focused on the sufficiency of the pleadings in the case, made no determination regarding the merits of the factual allegations, and remanded the case to the District Court for further proceedings. In October 2014, the parties reached an agreement in principle to settle the consolidated lawsuit. The settlement, which provides for a $7,000,000 payment, is expected to be fully funded by the Company’s insurance and was subject to preliminary and final approval of the court. The parties submitted the settlement to the court for approval on December 31, 2014. If, for any reason, the settlement is not approved and consummated, we may be exposed to damages and costs in excess of our insurance which would have a material adverse effect on our financial position, results of operations or cash flows. | |||||
SEC Administrative Proceeding. On August 4, 2014, following a multi-year investigation, the SEC instituted administrative cease-and-desist proceedings pursuant to Section 8A of the Securities Act of 1933 and 21C of the Securities Exchange Act of 1934, styled In the Matter of Houston American Energy Corp., John F. Terwilliger, Jr., Undiscovered Equities, Inc. and Kevin T. McKnight. The administrative proceeding alleged that Mr. Terwilliger and, in turn, Houston American Energy, made false and misleading statements with respect to the CPO 4 prospect and promoted those statements through Undiscovered Equities and its principal, Kevin McKnight. The SEC was seeking a determination from an administrative law judge as to whether (i) the allegations of the SEC were true; (ii) Houston American Energy and Mr. Terwilliger should be ordered to (A) cease-and-desist from committing or causing violations of Section 10(b) of the Exchange Act and Rule 10b-5 thereunder, (B) pay a civil penalty pursuant to Section 8A(g) of the Securities Act and Section 21B(a) of the Exchange Act, and (C) pay disgorgement pursuant to Section 8A(e) of the Securities Act and Sections 21B(e) and 21C(e) of the Exchange Act; and (iii) Mr. Terwilliger should be prohibited from acting as an officer and director of a public company pursuant to Section 8A(f) of the Securities Act and Section 21C(f) of the Exchange Act. | |||||
At December 31, 2014, the administrative proceeding was pending and was scheduled for trial in January 2015. The trial was stayed in January 2015 pending consideration by the Commission of a proposed settlement and remains pending. Based on the settlement proposal offered for consideration by the Commission, the Company has recorded on its balance sheet a contingent liability, and on its statement of operations a contingent loss, of $400,000. The Company has an insurance policy that insures for legal fees incurred in connection with the above administrative proceeding. At December 31, 2014, the Company had recorded an insurance claim receivable of $1,612,681 for fees which have been incurred, but not yet reimbursed by its insurance company. | |||||
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. The committee may, at its sole discretion, cause the Company to assign to some or all of the participants overriding royalty interests in individual wells in settlement of some or all of the obligations of the Company to make payments from any one or more pools. | |||||
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 2014, the Company made grants under the plan in 13 pools relating to 13 prospects. All of such grants were made to the Company’s principal officer with grants ranging from ½% to 1% of revenues associated with the prospects included in such pools. | |||||
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 $876 at December 31, 2014 and is recorded in accounts payable. |
GEOGRAPHICAL_INFORMATION
GEOGRAPHICAL INFORMATION | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
GEOGRAPHICAL INFORMATION [Abstract] | |||||||||||||||||
GEOGRAPHICAL INFORMATION | NOTE 9—GEOGRAPHICAL INFORMATION | ||||||||||||||||
The Company currently has operations in two geographical areas, the United States and Colombia. Revenues for the years ended December 31, 2014 and 2013 and long-lived assets as of December 31, 2014 and 2013 attributable to each geographical area are presented below: | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Revenues | Long Lived | Revenues | Long Lived | ||||||||||||||
Assets, Net | Assets, Net | ||||||||||||||||
North America | $ | 363,455 | $ | 3,466,020 | $ | 347,139 | $ | 2,073,268 | |||||||||
South America | — | 2,034,007 | — | 1,789,536 | |||||||||||||
Total | $ | 363,455 | $ | 5,500,027 | $ | 347,139 | $ | 3,862,804 |
SUPPLEMENTAL_INFORMATION_ON_OI
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) [Abstract] | |||||||||||||||||||||||||
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) | NOTE 10—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: | |||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
Revenues | |||||||||||||||||||||||||
North America | $ | 363,455 | $ | 347,139 | |||||||||||||||||||||
South America | — | — | |||||||||||||||||||||||
$ | 363,455 | $ | 347,139 | ||||||||||||||||||||||
Production Cost | |||||||||||||||||||||||||
North America | $ | 113,233 | $ | 81,774 | |||||||||||||||||||||
South America | — | — | |||||||||||||||||||||||
$ | 113,233 | $ | 81,774 | ||||||||||||||||||||||
Capital Costs | |||||||||||||||||||||||||
Capitalized costs and accumulated depletion relating to the Company’s oil and gas producing activities as of December 31, 2014, all of which are onshore properties located in the United States and Colombia, South America are summarized below: | |||||||||||||||||||||||||
United | South | Total | |||||||||||||||||||||||
States | America | ||||||||||||||||||||||||
Unproved properties not being amortized | $ | 1,552,277 | $ | 2,034,007 | $ | 3,586,284 | |||||||||||||||||||
Proved properties being amortized | 4,570,915 | 49,454,702 | 54,025,617 | ||||||||||||||||||||||
Accumulated depreciation, depletion, amortization and impairment | (2,660,144 | ) | (49,454,702 | ) | (52,114,846 | ) | |||||||||||||||||||
Net capitalized costs | $ | 3,463,048 | $ | 2,034,007 | $ | 5,497,055 | |||||||||||||||||||
Amortization Rate | |||||||||||||||||||||||||
The amortization rate per unit based on barrel of oil equivalents was $66.05 for the United States and $0 for South America for the year ended December 31, 2014. | |||||||||||||||||||||||||
Acquisition, Exploration and Development Costs Incurred | |||||||||||||||||||||||||
Costs incurred in oil and gas property acquisition, exploration and development activities for the years ended December 31, 2014 and 2013 are summarized below: | |||||||||||||||||||||||||
2014 | |||||||||||||||||||||||||
United States | South America | ||||||||||||||||||||||||
Property acquisition costs: | |||||||||||||||||||||||||
Proved | $ | 54,716 | $ | — | |||||||||||||||||||||
Unproved | 184,612 | 9,984 | |||||||||||||||||||||||
Exploration costs | 3,005,469 | 234,487 | |||||||||||||||||||||||
Development costs | — | — | |||||||||||||||||||||||
Total costs incurred | $ | 3,244,797 | $ | 244,471 | |||||||||||||||||||||
2013 | |||||||||||||||||||||||||
United States | South America | ||||||||||||||||||||||||
Property acquisition costs: | |||||||||||||||||||||||||
Proved | $ | 8,640 | $ | 84,081 | |||||||||||||||||||||
Unproved | 262,883 | — | |||||||||||||||||||||||
Exploration costs | — | 88,171 | |||||||||||||||||||||||
Development costs | 776,142 | — | |||||||||||||||||||||||
Total costs incurred | $ | 1,047,665 | $ | 172,252 | |||||||||||||||||||||
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, 2012 | 85,280 | 6,170 | — | — | 85,280 | 6,170 | |||||||||||||||||||
Extensions and discoveries | — | — | — | — | — | — | |||||||||||||||||||
Purchase of minerals in place | — | — | — | — | — | — | |||||||||||||||||||
Revisions of prior estimates | (39,011 | ) | 7,943 | — | — | (39,011 | ) | 7,943 | |||||||||||||||||
Sale of minerals in place | — | — | — | — | — | — | |||||||||||||||||||
Production | (9,459 | ) | (2,963 | ) | — | — | (9,459 | ) | (2,963 | ) | |||||||||||||||
Balance December 31, 2013 | 36,810 | 11,150 | — | — | 36,810 | 11,150 | |||||||||||||||||||
Extensions and discoveries | 24,944 | 32,090 | — | — | 24,944 | 32,090 | |||||||||||||||||||
Purchase of minerals in place | — | — | — | — | — | — | |||||||||||||||||||
Revisions to prior estimates | 23,673 | (5,958 | ) | — | — | 23,673 | (5,958 | ) | |||||||||||||||||
Sales of minerals in place | — | — | — | — | — | — | |||||||||||||||||||
Production | (12,717 | ) | (3,152 | ) | — | — | (12,717 | ) | (3,152 | ) | |||||||||||||||
Balance December 31, 2014 | 72,710 | 34,130 | — | — | 72,710 | 34,130 | |||||||||||||||||||
Proved developed reserves | |||||||||||||||||||||||||
at December 31, 2013 | 36,810 | 11,150 | — | — | 36,810 | 11,150 | |||||||||||||||||||
at December 31, 2014 | 72,710 | 34,130 | — | — | 72,710 | 34,130 | |||||||||||||||||||
Proved undeveloped reserves | |||||||||||||||||||||||||
at December 31, 2013 | — | — | — | — | — | — | |||||||||||||||||||
at December 31, 2014 | — | — | — | — | — | — | |||||||||||||||||||
During 2014 and 2013, the Company recorded extensions and discoveries resulting principally from its ongoing drilling operations in Colombia. As of December 31, 2014, we had no proved undeveloped (“PUD”) reserves. None of the PUD reserves as of December 31, 2013 were converted to proved developed producing reserves in 2014. | |||||||||||||||||||||||||
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, 2014: | |||||||||||||||||||||||||
United | South | Total | |||||||||||||||||||||||
States | America | ||||||||||||||||||||||||
Future cash flows from sales of oil and gas | $ | 3,579,990 | $ | — | $ | 3,579,990 | |||||||||||||||||||
Future production cost | (1,091,790 | ) | — | (1,091,790 | ) | ||||||||||||||||||||
Future development cost | — | — | — | ||||||||||||||||||||||
Future income tax | (287,709 | ) | — | (287,709 | ) | ||||||||||||||||||||
Future net cash flows | 2,200,491 | — | 2,200,491 | ||||||||||||||||||||||
10% annual discount for timing of cash flow | (649,930 | ) | — | (649,930 | ) | ||||||||||||||||||||
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves | $ | 1,550,561 | $ | — | $ | 1,550,561 | |||||||||||||||||||
Changes in standardized measure: | |||||||||||||||||||||||||
Change due to current year operations | |||||||||||||||||||||||||
Sales, net of production costs | (250,222 | ) | — | (250,222 | ) | ||||||||||||||||||||
Change due to revisions in standardized variables: | |||||||||||||||||||||||||
Income taxes | (287,709 | ) | — | (287,709 | ) | ||||||||||||||||||||
Accretion of discount | 112,021 | — | 112,021 | ||||||||||||||||||||||
Net change in sales and transfer price, net of production costs | (193,777 | ) | — | (193,777 | ) | ||||||||||||||||||||
Previously estimated development costs incurred during the period | — | — | — | ||||||||||||||||||||||
Changes in estimated future development costs | — | — | — | ||||||||||||||||||||||
Revision and others | — | — | — | ||||||||||||||||||||||
Discoveries | 999,242 | — | 999,242 | ||||||||||||||||||||||
Sales of reserves in place | — | — | — | ||||||||||||||||||||||
Changes in production rates and other | 451,971 | — | 451,971 | ||||||||||||||||||||||
Net | 831,526 | — | 831,526 | ||||||||||||||||||||||
Beginning of year | 719,035 | — | 719,035 | ||||||||||||||||||||||
End of year | $ | 1,550,561 | $ | — | $ | 1,550,561 | |||||||||||||||||||
Standardized measure of discounted future net cash flows at December 31, 2013: | |||||||||||||||||||||||||
United | South | Total | |||||||||||||||||||||||
States | America | ||||||||||||||||||||||||
Future cash flows from sales of oil and gas | $ | 1,306,020 | $ | — | $ | 1,306,020 | |||||||||||||||||||
Future production cost | (357,970 | ) | — | (357,970 | ) | ||||||||||||||||||||
Future development cost | — | — | — | ||||||||||||||||||||||
Future income tax | (14,525 | ) | — | (14,525 | ) | ||||||||||||||||||||
Future net cash flows | 933,525 | — | 933,525 | ||||||||||||||||||||||
10% annual discount for timing of cash flow | (214,490 | ) | — | (214,490 | ) | ||||||||||||||||||||
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves | $ | 719,035 | $ | — | $ | 719,035 | |||||||||||||||||||
Changes in standardized measure: | |||||||||||||||||||||||||
Change due to current year operations | |||||||||||||||||||||||||
Sales, net of production costs | (265,365 | ) | — | (265,365 | ) | ||||||||||||||||||||
Change due to revisions in standardized variables: | |||||||||||||||||||||||||
Income taxes | (14,525 | ) | — | (14,525 | ) | ||||||||||||||||||||
Accretion of discount | 29,807 | — | 29,807 | ||||||||||||||||||||||
Net change in sales and transfer price, net of production costs | 48,603 | — | 48,603 | ||||||||||||||||||||||
Previously estimated development costs incurred during the period | — | — | — | ||||||||||||||||||||||
Changes in estimated future development costs | — | — | — | ||||||||||||||||||||||
Revision and others | 30,997 | — | 30,997 | ||||||||||||||||||||||
Discoveries | — | — | — | ||||||||||||||||||||||
Sales of reserves in place | — | — | — | ||||||||||||||||||||||
Changes in production rates and other | 591,448 | — | 591,448 | ||||||||||||||||||||||
Net | 420,965 | — | 420,965 | ||||||||||||||||||||||
Beginning of year | 298,070 | — | 298,070 | ||||||||||||||||||||||
End of year | $ | 719,035 | $ | — | $ | 719,035 |
SUMMARIZED_QUARTERLY_FINANCIAL
SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) [Abstract] | |||||||||||||||||
SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | NOTE 11—SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | ||||||||||||||||
Three Months Ended | |||||||||||||||||
March 31, | June 30, | Sept. 30, | Dec. 31, | ||||||||||||||
2014 | |||||||||||||||||
Operating revenue | $ | 106,023 | $ | 67,450 | $ | 56,805 | $ | 133,177 | |||||||||
Loss from operations | (536,105 | ) | (684,728 | ) | (512,919 | ) | (2,224,590 | ) | |||||||||
Net loss | (535,368 | ) | (683,644 | ) | (511,653 | ) | (2,222,514 | ) | |||||||||
Loss per common share - basic | $ | (0.01 | ) | $ | (0.01 | ) | $ | (0.01 | ) | $ | (0.04 | ) | |||||
Loss per common share - diluted | $ | (0.01 | ) | $ | (0.01 | ) | $ | (0.01 | ) | $ | (0.04 | ) | |||||
2013 | |||||||||||||||||
Operating revenue | $ | 15,032 | $ | 19,223 | $ | 170,311 | $ | 142,573 | |||||||||
Income from operations | (785,191 | ) | (1,296,227 | ) | (526,248 | ) | (610,247 | ) | |||||||||
Net loss | (806,175 | ) | (1,266,267 | ) | (526,464 | ) | (574,575 | ) | |||||||||
Earnings per common share - basic | $ | (0.02 | ) | $ | (0.02 | ) | $ | (0.01 | ) | $ | (0.01 | ) | |||||
Earnings per common share - diluted | (0.02 | ) | (0.02 | ) | (0.01 | ) | (0.01 | ) |
NATURE_OF_COMPANY_AND_SUMMARY_1
NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2014 | |
NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract] | |
Consolidation | Consolidation |
The accompanying consolidated financial statements include all accounts of HUSA and its subsidiaries (HAEC Louisiana 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. | |
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 $3.2 million in excess of the FDIC’s current insured limit of $250,000 at December 31, 2014 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, 2014, the Company evaluated their receivables and determined an allowance was not required. | |
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, 2014 or 2013. | |
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 $348,197 and $12,111 for the years ended December 31, 2014 and 2013, respectively and accumulated amortization, depreciation and impairment was $52,114,846 and $50,274,501 at December 31, 2014 and 2013, 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”) and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, calculated for 2014 using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) with consideration of price change only to the extent provided by contractual arrangement, discounted at 10%, net of related tax effects. If capitalized costs exceed this limit, the excess is charged to expense and reflected as additional accumulated DD&A. During the year, the Company impaired oil and gas properties in the amount of $1,492,148. | |
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 $11,700 and $12,843 for 2014 and 2013, respectively, and accumulated depreciation was $87,032 and $75,332 at December 31, 2014 and 2013, 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. | |
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 have been issued. | |
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 income (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 year ended December 31, 2014, outstanding options to purchase 2,632,832 shares of common stock were excluded from the calculation of diluted net loss per share because they were anti-dilutive. For the year ended December 31, 2013, outstanding options to purchase 2,592,832 shares of common stock were excluded from the calculation of diluted net loss per share because they were anti-dilutive. | |
Concentration of Risk | Concentration of Risk |
The Company is dependent upon the industry skills and contacts of John F. Terwilliger, the chief executive officer, to identify potential acquisition targets in the onshore coastal Gulf of Mexico region of Texas and Louisiana and in the South American country of Colombia. Further, 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 Hupecol 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, 2014, 36.7% of the Company’s net oil and gas property investment, and 0% of its revenue for the year ended December 31, 2014, was with or derived from interests operated in Colombia. | |
For 2014, 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, 2014 and 2013, respectively. | |
Subsequent Events | Subsequent Events |
The Company evaluated subsequent events from December 31, 2014 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, 2014 | |||||||||
ESCROW RECEIVABLE [Abstract] | |||||||||
Escrow receivables relating to oil and gas properties | At December 31, 2014 and December 31, 2013, the Company’s balance sheet reflected the following escrow receivables relating to various oil and gas properties previously held by the Company: | ||||||||
December 31, | December 31, | ||||||||
2014 | 2013 | ||||||||
Tambaqui Escrow | $ | 4,331 | $ | 22,029 | |||||
HDC LLC and HL LLC 15% Escrow | 294,383 | 1,827,929 | |||||||
HDC LLC and HL LLC 5% Contingency | 11,256 | 57,321 | |||||||
HC LLC 5% Contingency | 11,458 | 13,938 | |||||||
TOTAL | $ | 321,428 | $ | 1,921,217 |
OIL_AND_GAS_PROPERTIES_Tables
OIL AND GAS PROPERTIES (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
OIL AND GAS PROPERTIES [Abstract] | |||||||||||||
Schedule of evaluated oil and gas properties subject to amortization | Evaluated oil and gas properties subject to amortization at December 31, 2014 included the following: | ||||||||||||
United | South | Total | |||||||||||
States | America | ||||||||||||
Evaluated properties being amortized | $ | 4,570,915 | $ | 49,454,702 | $ | 54,025,617 | |||||||
Accumulated depreciation, depletion, amortization and impairment | -2,660,144 | -49,454,702 | -52,114,846 | ||||||||||
Net capitalized costs | $ | 1,910,771 | $ | — | $ | 1,910,771 | |||||||
Evaluated oil and gas properties subject to amortization at December 31, 2013 included the following: | |||||||||||||
United | South | Total | |||||||||||
States | America | ||||||||||||
Evaluated properties being amortized | $ | 865,889 | $ | 49,454,702 | $ | 50,320,591 | |||||||
Accumulated depreciation, depletion, amortization and impairment | (819,799 | ) | (49,454,702 | ) | (50,274,501 | ) | |||||||
Net capitalized costs | $ | 46,090 | $ | — | $ | 46,090 | |||||||
Schedule of unevaluated oil and gas properties not subject to amortization | Unevaluated oil and gas properties not subject to amortization at December 31, 2014 included the following: | ||||||||||||
North | South | Total | |||||||||||
America | America | ||||||||||||
Leasehold acquisition costs | $ | 868,301 | $ | 141,319 | $ | 1,009,620 | |||||||
Geological, geophysical, screening and evaluation costs | 683,976 | 1,892,688 | 2,576,664 | ||||||||||
Total | $ | 1,552,277 | $ | 2,034,007 | $ | 3,586,284 | |||||||
Unevaluated oil and gas properties not subject to amortization at December 31, 2013 included the following: | |||||||||||||
North | South | Total | |||||||||||
America | America | ||||||||||||
Leasehold acquisition costs | $ | 1,234,888 | $ | 131,335 | $ | 1,366,223 | |||||||
Geological, geophysical, screening and evaluation costs | 777,618 | 1,658,201 | 2,435,819 | ||||||||||
Total | $ | 2,012,506 | $ | 1,789,536 | $ | 3,802,042 |
ASSET_RETIREMENT_OBLIGATION_Ta
ASSET RETIREMENT OBLIGATION (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
ASSET RETIREMENT OBLIGATION [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, 2014 and 2013. | ||||||||
2014 | 2013 | ||||||||
ARO liability at January 1 | $ | 8,424 | $ | 7,872 | |||||
Accretion expense | 628 | 552 | |||||||
Liabilities incurred from drilling | 20,812 | — | |||||||
Liabilities settled—assets sold | — | — | |||||||
Changes in estimates | (1,717 | ) | — | ||||||
ARO liability at December 31, | $ | 28,147 | $ | 8,424 |
STOCKBASED_COMPENSATION_Tables
STOCK-BASED COMPENSATION (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
STOCK-BASED COMPENSATION [Abstract] | ||||||||||||
Option activity | Option activity during 2014 and 2013 was as follows: | |||||||||||
Options | Weighted | Weighted | Aggregate | |||||||||
Average | Average | Intrinsic | ||||||||||
Exercise | Remaining | Value | ||||||||||
Price | Contractual | |||||||||||
Term (in | ||||||||||||
Years) | ||||||||||||
Outstanding at December 31, 2012 | 2,223,057 | $ | 5.68 | |||||||||
Granted | 2,215,525 | $ | 0.86 | |||||||||
Exercised | — | $ | — | |||||||||
Forfeited | (2,065,750 | ) | $ | 2.53 | ||||||||
Outstanding at December 31, 2013 | 2,592,832 | $ | 4.07 | |||||||||
Granted | 800,000 | $ | 0.42 | |||||||||
Exercised | — | $ | — | |||||||||
Forfeited | — | $ | — | |||||||||
Outstanding at December 31, 2014 | 3,392,832 | $ | 3.21 | 6.02 | $ — | |||||||
Share-based compensation expense | The following table reflects share-based compensation recorded by the Company for 2014 and 2013: | |||||||||||
2014 | 2013 | |||||||||||
Share-based compensation expense included in general and administrative expense | $ | 451,010 | $ | 1,513,779 | ||||||||
Earnings per share effect of share-based compensation expense | $ | (0.01 | ) | $ | (0.03 | ) |
TAXES_Tables
TAXES (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
TAXES [Abstract] | |||||||||
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, 2014 and 2013. | ||||||||
2014 | 2013 | ||||||||
Income (loss) before income taxes | $ | (4,350,996 | ) | $ | (3,185,755 | ) | |||
Income tax expense (benefit) computed at statutory rates | $ | (1,523,613 | ) | $ | (1,115,014 | ) | |||
Permanent differences, nondeductible expenses | 141,446 | (1,177,769 | ) | ||||||
Increase (decrease) in valuation allowance | (696,514 | ) | (902,498 | ) | |||||
Change in tax rate | — | (79,409 | ) | ||||||
Return to accrual items | 1,178,681 | 127,913 | |||||||
Foreign tax credit | — | 3,658,139 | |||||||
Other adjustment | — | (21,156 | ) | ||||||
NOL adjustment | 902,183 | (502,480 | ) | ||||||
State (net of federal benefit) | — | — | |||||||
Tax provision (benefit) | $ | 2,183 | $ | (12,274 | ) | ||||
Total Provision | |||||||||
Current Federal | $ | — | $ | — | |||||
Current State | — | — | |||||||
Deferred Federal | — | — | |||||||
Deferred State | — | — | |||||||
Permanent True-up | — | (21,154 | ) | ||||||
Foreign | 2,183 | 8,880 | |||||||
Total provision (benefit) | $ | 2,183 | $ | (12,274 | ) | ||||
Significant components of the deferred tax asset and liability | Significant components of the deferred tax asset and liability as of December 31, 2014 and 2013 are set out below. | ||||||||
2014 | 2013 | ||||||||
Non-Current Deferred tax assets: | |||||||||
Net operating loss carry forwards | $ | 15,764,184 | $ | 17,003,714 | |||||
Foreign tax credit carry forwards | 486,880 | 484,697 | |||||||
Deferred state tax | 23,277 | 23,277 | |||||||
Stock compensation | 3,525,473 | 3,618,643 | |||||||
Book in excess of tax depreciation, depletion, and capitalization methods on oil and gas properties | (1,524,310 | ) | (2,151,329 | ) | |||||
Other | (76,576 | ) | (83,560 | ) | |||||
Colombia future tax obligations | — | — | |||||||
Total Non-Current Deferred tax assets | 18,198,928 | 18,895,442 | |||||||
Valuation Allowance | (18,198,928 | ) | (18,895,442 | ) | |||||
Net deferred tax asset | $ | — | $ | — |
COMMITMENTS_AND_CONTINGENCIES_
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
COMMITMENTS AND CONTINGENCIES [Abstract] | |||||
Future payments under lease agreement | 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 | ||||
2015 | $ | 93,793 | |||
2016 | 96,162 | ||||
2017 | 40,469 | ||||
Total | $ | 230,424 |
GEOGRAPHICAL_INFORMATION_Table
GEOGRAPHICAL INFORMATION (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
GEOGRAPHICAL INFORMATION [Abstract] | |||||||||||||||||
Revenues and long-lived assets attributable to each geographical area | The Company currently has operations in two geographical areas, the United States and Colombia. Revenues for the years ended December 31, 2014 and 2013 and long-lived assets as of December 31, 2014 and 2013 attributable to each geographical area are presented below: | ||||||||||||||||
2014 | 2013 | ||||||||||||||||
Revenues | Long Lived | Revenues | Long Lived | ||||||||||||||
Assets, Net | Assets, Net | ||||||||||||||||
North America | $ | 363,455 | $ | 3,466,020 | $ | 347,139 | $ | 2,073,268 | |||||||||
South America | — | 2,034,007 | — | 1,789,536 | |||||||||||||
Total | $ | 363,455 | $ | 5,500,027 | $ | 347,139 | $ | 3,862,804 |
SUPPLEMENTAL_INFORMATION_ON_OI1
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) [Abstract] | |||||||||||||
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: | ||||||||||||
2014 | 2013 | ||||||||||||
Revenues | |||||||||||||
North America | $ | 363,455 | $ | 347,139 | |||||||||
South America | — | — | |||||||||||
$ | 363,455 | $ | 347,139 | ||||||||||
Production Cost | |||||||||||||
North America | $ | 113,233 | $ | 81,774 | |||||||||
South America | — | — | |||||||||||
$ | 113,233 | $ | 81,774 | ||||||||||
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, 2014, all of which are onshore properties located in the United States and Colombia, South America are summarized below: | ||||||||||||
United | South | Total | |||||||||||
States | America | ||||||||||||
Unproved properties not being amortized | $ | 1,552,277 | $ | 2,034,007 | $ | 3,586,284 | |||||||
Proved properties being amortized | 4,570,915 | 49,454,702 | 54,025,617 | ||||||||||
Accumulated depreciation, depletion, amortization and impairment | (2,660,144 | ) | (49,454,702 | ) | (52,114,846 | ) | |||||||
Net capitalized costs | $ | 3,463,048 | $ | 2,034,007 | $ | 5,497,055 | |||||||
Costs incurred in oil and gas property acquisition, exploration and development activities | Costs incurred in oil and gas property acquisition, exploration and development activities for the years ended December 31, 2014 and 2013 are summarized below: | ||||||||||||
2014 | |||||||||||||
United States | South America | ||||||||||||
Property acquisition costs: | |||||||||||||
Proved | $ | 54,716 | $ | — | |||||||||
Unproved | 184,612 | 9,984 | |||||||||||
Exploration costs | 3,005,469 | 234,487 | |||||||||||
Development costs | — | — | |||||||||||
Total costs incurred | $ | 3,244,797 | $ | 244,471 | |||||||||
2013 | |||||||||||||
United States | South America | ||||||||||||
Property acquisition costs: | |||||||||||||
Proved | $ | 8,640 | $ | 84,081 | |||||||||
Unproved | 262,883 | — | |||||||||||
Exploration costs | — | 88,171 | |||||||||||
Development costs | 776,142 | — | |||||||||||
Total costs incurred | $ | 1,047,665 | $ | 172,252 | |||||||||
Standardized measure of discounted future net cash flows | Standardized measure of discounted future net cash flows at December 31, 2014: | ||||||||||||
United | South | Total | |||||||||||
States | America | ||||||||||||
Future cash flows from sales of oil and gas | $ | 3,579,990 | $ | — | $ | 3,579,990 | |||||||
Future production cost | (1,091,790 | ) | — | (1,091,790 | ) | ||||||||
Future development cost | — | — | — | ||||||||||
Future income tax | (287,709 | ) | — | (287,709 | ) | ||||||||
Future net cash flows | 2,200,491 | — | 2,200,491 | ||||||||||
10% annual discount for timing of cash flow | (649,930 | ) | — | (649,930 | ) | ||||||||
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves | $ | 1,550,561 | $ | — | $ | 1,550,561 | |||||||
Changes in standardized measure: | |||||||||||||
Change due to current year operations | |||||||||||||
Sales, net of production costs | (250,222 | ) | — | (250,222 | ) | ||||||||
Change due to revisions in standardized variables: | |||||||||||||
Income taxes | (287,709 | ) | — | (287,709 | ) | ||||||||
Accretion of discount | 112,021 | — | 112,021 | ||||||||||
Net change in sales and transfer price, net of production costs | (193,777 | ) | — | (193,777 | ) | ||||||||
Previously estimated development costs incurred during the period | — | — | — | ||||||||||
Changes in estimated future development costs | — | — | — | ||||||||||
Revision and others | — | — | — | ||||||||||
Discoveries | 999,242 | — | 999,242 | ||||||||||
Sales of reserves in place | — | — | — | ||||||||||
Changes in production rates and other | 451,971 | — | 451,971 | ||||||||||
Net | 831,526 | — | 831,526 | ||||||||||
Beginning of year | 719,035 | — | 719,035 | ||||||||||
End of year | $ | 1,550,561 | $ | — | $ | 1,550,561 | |||||||
Standardized measure of discounted future net cash flows at December 31, 2013: | |||||||||||||
United | South | Total | |||||||||||
States | America | ||||||||||||
Future cash flows from sales of oil and gas | $ | 1,306,020 | $ | — | $ | 1,306,020 | |||||||
Future production cost | (357,970 | ) | — | (357,970 | ) | ||||||||
Future development cost | — | — | — | ||||||||||
Future income tax | (14,525 | ) | — | (14,525 | ) | ||||||||
Future net cash flows | 933,525 | — | 933,525 | ||||||||||
10% annual discount for timing of cash flow | (214,490 | ) | — | (214,490 | ) | ||||||||
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves | $ | 719,035 | $ | — | $ | 719,035 | |||||||
Changes in standardized measure: | |||||||||||||
Change due to current year operations | |||||||||||||
Sales, net of production costs | (265,365 | ) | — | (265,365 | ) | ||||||||
Change due to revisions in standardized variables: | |||||||||||||
Income taxes | (14,525 | ) | — | (14,525 | ) | ||||||||
Accretion of discount | 29,807 | — | 29,807 | ||||||||||
Net change in sales and transfer price, net of production costs | 48,603 | — | 48,603 | ||||||||||
Previously estimated development costs incurred during the period | — | — | — | ||||||||||
Changes in estimated future development costs | — | — | — | ||||||||||
Revision and others | 30,997 | — | 30,997 | ||||||||||
Discoveries | — | — | — | ||||||||||
Sales of reserves in place | — | — | — | ||||||||||
Changes in production rates and other | 591,448 | — | 591,448 | ||||||||||
Net | 420,965 | — | 420,965 | ||||||||||
Beginning of year | 298,070 | — | 298,070 | ||||||||||
End of year | $ | 719,035 | $ | — | $ | 719,035 |
SUMMARIZED_QUARTERLY_FINANCIAL1
SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) [Abstract] | |||||||||||||||||
Summarized quarterly financial information | Three Months Ended | ||||||||||||||||
March 31, | June 30, | Sept. 30, | Dec. 31, | ||||||||||||||
2014 | |||||||||||||||||
Operating revenue | $ | 106,023 | $ | 67,450 | $ | 56,805 | $ | 133,177 | |||||||||
Loss from operations | (536,105 | ) | (684,728 | ) | (512,919 | ) | (2,224,590 | ) | |||||||||
Net loss | (535,368 | ) | (683,644 | ) | (511,653 | ) | (2,222,514 | ) | |||||||||
Loss per common share - basic | $ | (0.01 | ) | $ | (0.01 | ) | $ | (0.01 | ) | $ | (0.04 | ) | |||||
Loss per common share - diluted | $ | (0.01 | ) | $ | (0.01 | ) | $ | (0.01 | ) | $ | (0.04 | ) | |||||
2013 | |||||||||||||||||
Operating revenue | $ | 15,032 | $ | 19,223 | $ | 170,311 | $ | 142,573 | |||||||||
Income from operations | (785,191 | ) | (1,296,227 | ) | (526,248 | ) | (610,247 | ) | |||||||||
Net loss | (806,175 | ) | (1,266,267 | ) | (526,464 | ) | (574,575 | ) | |||||||||
Earnings per common share - basic | $ | (0.02 | ) | $ | (0.02 | ) | $ | (0.01 | ) | $ | (0.01 | ) | |||||
Earnings per common share - diluted | (0.02 | ) | (0.02 | ) | (0.01 | ) | (0.01 | ) |
NATURE_OF_COMPANY_AND_SUMMARY_2
NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Concentration of Credit Risk [Abstract] | ||
Cash deposits in excess of the FDIC's current insured limit | $3,200,000 | |
Current insured limit on interest bearing accounts | 250,000 | |
Ceiling Test [Abstract] | ||
Discount rate, net of related tax effects (in hundredths) | 10.00% | |
Impairment of oil and gas properties | 1,492,148 | 0 |
Property, Plant and Equipment [Line Items] | ||
Depletion and amortization | 359,897 | 24,954 |
Accumulated amortization, depreciation and impairment | 52,201,878 | 50,349,833 |
Preferred Stock [Abstract] | ||
Preferred stock, authorized (in shares) | 10,000,000 | 10,000,000 |
Preferred stock, par value (in dollars per share) | $0.00 | $0.00 |
Concentration Risk [Line Items] | ||
Percentage of sales to a single buyer (in hundredths) | 10.00% | |
Allowance for uncollectible accounts | 0 | 0 |
Oil and Gas Property Investment [Member] | Hupecol Operating LLC [Member] | ||
Concentration Risk [Line Items] | ||
Concentration risk, percentage (in hundredths) | 36.70% | |
Revenue [Member] | Hupecol Operating LLC [Member] | ||
Concentration Risk [Line Items] | ||
Concentration risk, percentage (in hundredths) | 0.00% | |
Options [Member] | ||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||
Antidilutive securities excluded from computation of earnings per share (in shares) | 2,632,832 | 2,592,832 |
Oil and Gas Properties [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Depletion and amortization | 348,197 | 12,111 |
Accumulated amortization, depreciation and impairment | 52,114,846 | 50,274,501 |
Furniture and Equipment [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Depletion and amortization | 11,700 | 12,843 |
Accumulated amortization, depreciation and impairment | $87,032 | $75,332 |
Furniture and Equipment [Member] | Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Useful life of the assets | 3 years | |
Furniture and Equipment [Member] | Maximum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Useful life of the assets | 5 years |
ESCROW_RECEIVABLE_Details
ESCROW RECEIVABLE (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Escrow receivables relating to oil and gas properties [Abstract] | ||
Escrow receivables - Total | $321,428 | $1,921,217 |
Tambaqui Escrow [Member] | ||
Escrow receivables relating to oil and gas properties [Abstract] | ||
Escrow receivables - Total | 4,331 | 22,029 |
HDC LLC and HL LLC 15% Escrow [Member] | ||
Escrow receivables relating to oil and gas properties [Abstract] | ||
Escrow receivables - Total | 294,383 | 1,827,929 |
Escrow receivables, percentage (in hundredths) | 15.00% | 15.00% |
HDC LLC and HL LLC 5% Contingency [Member] | ||
Escrow receivables relating to oil and gas properties [Abstract] | ||
Escrow receivables - Total | 11,256 | 57,321 |
Escrow receivables, percentage (in hundredths) | 5.00% | 5.00% |
HC LLC 5% Contingency [Member] | ||
Escrow receivables relating to oil and gas properties [Abstract] | ||
Escrow receivables - Total | 11,458 | 13,938 |
Escrow receivables, percentage (in hundredths) | 5.00% | 5.00% |
Various Escrow Accounts [Member] | ||
Escrow receivables relating to oil and gas properties [Abstract] | ||
Proceeds from settlement of escrow account | 1,586,039 | |
Accrued liability | $13,750 |
OIL_AND_GAS_PROPERTIES_Details
OIL AND GAS PROPERTIES (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Evaluated oil and gas properties subject to amortization [Abstract] | ||
Evaluated properties being amortized | $54,025,617 | $50,320,591 |
Accumulated depreciation, depletion, amortization and impairment | -52,114,846 | -50,274,501 |
Net capitalized costs | 1,910,771 | 46,090 |
Unevaluated oil and gas properties not subject to amortization [Abstract] | ||
Leasehold acquisition costs | 1,009,620 | 1,366,223 |
Geological, geophysical, screening and evaluation costs | 2,576,664 | 2,435,819 |
Total | 3,586,284 | 3,802,042 |
United States [Member] | ||
Evaluated oil and gas properties subject to amortization [Abstract] | ||
Evaluated properties being amortized | 4,570,915 | 865,889 |
Accumulated depreciation, depletion, amortization and impairment | -2,660,144 | -819,799 |
Net capitalized costs | 1,910,771 | 46,090 |
Unevaluated oil and gas properties not subject to amortization [Abstract] | ||
Total | 1,552,277 | |
South America [Member] | ||
Evaluated oil and gas properties subject to amortization [Abstract] | ||
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 | 0 | 0 |
Unevaluated oil and gas properties not subject to amortization [Abstract] | ||
Leasehold acquisition costs | 141,319 | 131,335 |
Geological, geophysical, screening and evaluation costs | 1,892,688 | 1,658,201 |
Total | 2,034,007 | 1,789,536 |
North America [Member] | ||
Unevaluated oil and gas properties not subject to amortization [Abstract] | ||
Leasehold acquisition costs | 868,301 | 1,234,888 |
Geological, geophysical, screening and evaluation costs | 683,976 | 777,618 |
Total | $1,552,277 | $2,012,506 |
ASSET_RETIREMENT_OBLIGATION_De
ASSET RETIREMENT OBLIGATION (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Changes in our asset retirement liability [Roll Forward] | ||
ARO liability at January 1 | $8,424 | $7,872 |
Accretion expense | 628 | 552 |
Liabilities incurred from drilling | 20,812 | 0 |
Liabilities settled-assets sold | 0 | 0 |
Changes in estimates | -1,717 | 0 |
ARO liability at December 31 | $28,147 | $8,424 |
STOCKBASED_COMPENSATION_Detail
STOCK-BASED COMPENSATION (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2011 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Options granted (in shares) | 800,000 | 2,215,525 | |
Exercise price of options granted (in dollars per share) | $0.42 | $0.86 | |
Options [Roll Forward] | |||
Outstanding at beginning of the period (in shares) | 2,592,832 | 2,223,057 | |
Granted (in shares) | 800,000 | 2,215,525 | |
Exercised (in shares) | 0 | 0 | |
Forfeited (in shares) | 0 | -2,065,750 | |
Outstanding at end of the period (in shares) | 3,392,832 | 2,592,832 | |
Weighted-Average Exercise Price [Roll Forward] | |||
Outstanding at beginning of the period (in dollars per share) | $4.07 | $5.68 | |
Granted (in dollars per share) | $0.42 | $0.86 | |
Exercised (in dollars per share) | $0 | $0 | |
Forfeited (in dollars per share) | $0 | $2.53 | |
Outstanding at end of the period (in dollars per share) | $3.21 | $4.07 | |
Weighted Average Remaining Contractual Term [Abstract] | |||
Weighted average remaining contractual term of the outstanding options | 6 years 0 months 7 days | ||
Aggregate Intrinsic Value [Abstract] | |||
Outstanding at end of the period | $0 | ||
Weighted average remaining contractual term of the outstanding options | 6 years 0 months 7 days | ||
Officer [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of officer employment terminated | 2 | ||
Options forfeited for each terminated officer (in shares) | 150,000 | ||
Options to be expired due to out of money (in shares) | 1,520,000 | ||
Employee [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Options granted (in shares) | 600,000 | 1,200,000 | |
Stock option vesting percentage (in hundredths) | 33.00% | 50.00% | |
Percentage of stock options expected to vest (in hundredths) | 50.00% | ||
Option vesting period | 10 years | 10 years | |
Exercise price of options granted (in dollars per share) | $0.42 | $0.31 | |
Total value of options granted | 126,355 | 294,085 | |
Risk free interest rate (in hundredths) | 1.57% | 1.26% | |
Stock option expected life | 4 years 7 months 24 days | 5 years 7 months 6 days | |
Expected stock volatility (in hundredths) | 103.60% | 105.00% | |
Expected dividend yield (in hundredths) | 0.00% | 0.00% | |
Options [Roll Forward] | |||
Granted (in shares) | 600,000 | 1,200,000 | |
Weighted-Average Exercise Price [Roll Forward] | |||
Granted (in dollars per share) | $0.42 | $0.31 | |
Aggregate Intrinsic Value [Abstract] | |||
Vesting period of restricted stock award granted to officers | 10 years | 10 years | |
Non-employee directors [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Options granted (in shares) | 200,000 | 100,000 | |
Stock option vesting percentage (in hundredths) | 20.00% | ||
Percentage of stock options expected to vest (in hundredths) | 80.00% | ||
Option vesting period | 10 years | ||
Exercise price of options granted (in dollars per share) | $0.42 | ||
Total value of options granted | 46,651 | ||
Risk free interest rate (in hundredths) | 1.57% | ||
Stock option expected life | 4 years 7 months 24 days | ||
Expected stock volatility (in hundredths) | 103.60% | ||
Expected dividend yield (in hundredths) | 0.00% | ||
Options [Roll Forward] | |||
Granted (in shares) | 200,000 | 100,000 | |
Weighted-Average Exercise Price [Roll Forward] | |||
Granted (in dollars per share) | $0.42 | ||
Aggregate Intrinsic Value [Abstract] | |||
Vesting period of restricted stock award granted to officers | 10 years | ||
Previous non employee director [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Options granted (in shares) | 100,000 | ||
Stock option vesting percentage (in hundredths) | 20.00% | ||
Percentage of stock options expected to vest (in hundredths) | 80.00% | ||
Option vesting period | 10 years | ||
Exercise price of options granted (in dollars per share) | $0.31 | ||
Total value of options granted | 24,507 | ||
Risk free interest rate (in hundredths) | 1.26% | ||
Stock option expected life | 5 years 7 months 6 days | ||
Expected stock volatility (in hundredths) | 105.00% | ||
Expected dividend yield (in hundredths) | 0.00% | ||
Options [Roll Forward] | |||
Granted (in shares) | 100,000 | ||
Weighted-Average Exercise Price [Roll Forward] | |||
Granted (in dollars per share) | $0.31 | ||
Aggregate Intrinsic Value [Abstract] | |||
Vesting period of restricted stock award granted to officers | 10 years | ||
2005 Stock Option Plan [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of options authorized (in shares) | 500,000 | ||
Number of shares of common stock authorized (in shares) | 500,000 | ||
2008 Equity Incentive Plan [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares of common stock authorized (in shares) | 2,200,000 | ||
Amendments to 2008 Equity Incentive Plan [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares of common stock authorized (in shares) | 6,000,000 | ||
Options [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock compensation amortized expense | 414,189 | 1,356,639 | |
Weighted Average Remaining Contractual Term [Abstract] | |||
Weighted average remaining contractual term of the outstanding options | 6 years 9 months 14 days | ||
Aggregate Intrinsic Value [Abstract] | |||
Unvested options outstanding (in shares) | 728,000 | ||
Weighted average remaining contractual term of the outstanding options | 6 years 9 months 14 days | ||
Weighted average remaining contractual term of the exercisable options | 6 years 0 months 7 days | ||
Unrecognized stock-based compensation expense related to non-vested stock options | 114,730 | ||
Shares available for issuance (in shares) | 2,607,168 | ||
Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock compensation amortized expense | 36,821 | 157,140 | |
Aggregate Intrinsic Value [Abstract] | |||
Weighted average period for recognition of compensation expense | 1 year 11 months 19 days | ||
Fair market value of the shares on date of grant | 743,400 | ||
Restricted stock forfeited and cancelled for each terminated officer (in shares) | 5,000 | ||
Unrecognized compensation cost related to unvested restricted stock | $0 | ||
Restricted Stock [Member] | Officer [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Option vesting period | 3 years | ||
Aggregate Intrinsic Value [Abstract] | |||
Restricted stock granted to officers (in shares) | 45,000 | ||
Vesting period of restricted stock award granted to officers | 3 years |
STOCKBASED_COMPENSATION_Alloca
STOCK-BASED COMPENSATION, Allocation of Recognized Period Costs (Details) (General and administrative expense [Member], USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
General and administrative expense [Member] | ||
Share-based compensation expense [Abstract] | ||
Share-based compensation expense included in general and administrative expense | $451,010 | $1,513,779 |
Earnings per share effect of share based compensation expense (in dollars per share) | ($0.01) | ($0.03) |
TAXES_Details
TAXES (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Reconciliation of the statutory federal income tax [Abstract] | ||
Income (loss) before income taxes | ($4,350,996) | ($3,185,755) |
Income tax expense (benefit) computed at statutory rates | -1,523,613 | -1,115,014 |
Permanent differences, nondeductible expenses | 141,446 | -1,177,769 |
Increase (decrease) in valuation allowance | -696,514 | -902,498 |
Change in tax rate | 0 | -79,409 |
Return to accrual items | 1,178,681 | 127,913 |
Foreign tax credit | 0 | 3,658,139 |
Other adjustment | 0 | -21,156 |
NOL adjustment | 902,183 | -502,480 |
State (net of federal benefit) | 0 | 0 |
Tax provision (benefit) | 2,183 | -12,274 |
Total Provision [Abstract] | ||
Current Federal | 0 | 0 |
Current State | 0 | 0 |
Deferred Federal | 0 | 0 |
Deferred State | 0 | 0 |
Permanent True-up | 0 | -21,154 |
Foreign | 2,183 | 8,880 |
Tax provision (benefit) | 2,183 | -12,274 |
Federal tax loss carry forward | 44,930,526 | |
Foreign tax credit carry forward | 486,880 | |
Non-Current Deferred tax assets [Abstract] | ||
Net operating loss carry forwards | 15,764,184 | 17,003,714 |
Foreign tax credit carry forwards | 486,880 | 484,697 |
Deferred state tax | 23,277 | 23,277 |
Stock compensation | 3,525,473 | 3,618,643 |
Book in excess of tax depreciation, depletion, and capitalization methods on oil and gas properties | -1,524,310 | -2,151,329 |
Other | -76,576 | -83,560 |
Colombia future tax obligations | 0 | 0 |
Total Non-Current Deferred tax assets | 18,198,928 | 18,895,442 |
Valuation Allowance | -18,198,928 | -18,895,442 |
Net deferred tax asset | $0 | $0 |
Foreign Income Taxes [Member] | ||
Income Tax Contingency [Line Items] | ||
Colombia's current income tax rate (in hundredths) | 25.00% |
RELATED_PARTIES_Details
RELATED PARTIES (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
John F. Terwilliger [Member] | ||
Related Party Transaction [Line Items] | ||
Overriding royalty interests owned (in hundredths) | 1.50% | |
Royalty payments | $20,682 | $20,305 |
Orrie L. Tawes [Member] | ||
Related Party Transaction [Line Items] | ||
Overriding royalty interests owned (in hundredths) | 1.50% | |
Royalty payments | $20,682 | $20,305 |
COMMITMENTS_AND_CONTINGENCIES_1
COMMITMENTS AND CONTINGENCIES (Details) (USD $) | 1 Months Ended | 12 Months Ended | |
Aug. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | |
Claim | |||
Lease Commitment [Abstract] | |||
Operating lease agreement expiration date | 31-May-17 | ||
Future payments under lease agreement [Abstract] | |||
2015 | $93,793 | ||
2016 | 96,162 | ||
2017 | 40,469 | ||
Total | 230,424 | ||
Total rental expense | 98,659 | 97,220 | |
Legal Contingencies [Abstract] | |||
Additional class action lawsuits | 2 | ||
Litigation settlement payable | 7,000,000 | 0 | |
Contingent liability | 400,000 | 0 | |
Increase in insurance receivable | 1,612,681 | ||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | |||
Description of production incentive compensation plan | The maximum percentage of the Companybs share of revenues from a well that may be designated to fund a Pool is 2% (the bPool Capb); 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 Companybs 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 (in hundredths) | 2.00% | ||
Maximum percentage of revenue from a well considered for pool cap one (in hundredths) | 73.00% | ||
Maximum percentage of revenue from a well considered for pool cap two (in hundredths) | 71.00% | ||
Period consider for payout of revenues to participants | 60 days | ||
Production Based Compensation Plan [Member] | |||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | |||
Number of pools | 13 | ||
Number of prospects | 13 | ||
Reduction of revenue associated with plan | $876 | ||
Chief Executive Officer [Member] | |||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | |||
Maximum percentage of pool cap related to well assigned (in hundredths) | 50.00% | ||
Officer [Member] | Minimum [Member] | |||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | |||
Grants issued to officers (in hundredths) | 0.50% | ||
Officer [Member] | Maximum [Member] | |||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | |||
Grants issued to officers (in hundredths) | 1.00% |
GEOGRAPHICAL_INFORMATION_Detai
GEOGRAPHICAL INFORMATION (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||||||||
Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | |
Area | Area | |||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||||||||||
Number of geographical areas in which entity operates | 2 | 2 | ||||||||
Revenues and long-lived assets attributable to each geographical area [Abstract] | ||||||||||
Operating revenue | $133,177 | $56,805 | $67,450 | $106,023 | $142,573 | $170,311 | $19,223 | $15,032 | $363,455 | $347,139 |
Long Lived Assets, Net | 5,500,027 | 3,862,804 | 5,500,027 | 3,862,804 | ||||||
North America [Member] | ||||||||||
Revenues and long-lived assets attributable to each geographical area [Abstract] | ||||||||||
Operating revenue | 363,455 | 347,139 | ||||||||
Long Lived Assets, Net | 3,466,020 | 2,073,268 | 3,466,020 | 2,073,268 | ||||||
South America [Member] | ||||||||||
Revenues and long-lived assets attributable to each geographical area [Abstract] | ||||||||||
Operating revenue | 0 | 0 | ||||||||
Long Lived Assets, Net | $2,034,007 | $1,789,536 | $2,034,007 | $1,789,536 |
SUPPLEMENTAL_INFORMATION_ON_OI2
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||||||||
Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | |
Boe | Boe | Boe | Boe | |||||||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||||||||||
Operating revenue | $133,177 | $56,805 | $67,450 | $106,023 | $142,573 | $170,311 | $19,223 | $15,032 | $363,455 | $347,139 |
Production Cost | 113,233 | 81,774 | ||||||||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||||||||||
Unproved properties not being amortized | 3,586,284 | 3,802,042 | 3,586,284 | 3,802,042 | ||||||
Proved properties being amortized | 54,025,617 | 50,320,591 | 54,025,617 | 50,320,591 | ||||||
Accumulated depreciation, depletion, amortization and impairment | -52,114,846 | -50,274,501 | -52,114,846 | -50,274,501 | ||||||
Net capitalized costs | 5,497,055 | 5,497,055 | ||||||||
Property acquisition costs [Abstract] | ||||||||||
Period of average prices used in calculating proved oil and gas reserves | 12 months | |||||||||
Period of average prices used in calculating future cash inflows related to standardized measure of discounted future net cash flows | 12 months | |||||||||
Minimum experience of Vice President of independent professional engineering firm | 30 years | |||||||||
Total proved reserves [Abstract] | ||||||||||
Total proved undeveloped reserve | 0 | 0 | 0 | 0 | ||||||
Discount rate of estimated future cash flows (in hundredths) | 10.00% | |||||||||
Standardized measure of discounted future net cash flows [Abstract] | ||||||||||
Future cash inflows from sales of oil and gas | 3,579,990 | 1,306,020 | 3,579,990 | 1,306,020 | ||||||
Future production cost | -1,091,790 | -357,970 | -1,091,790 | -357,970 | ||||||
Future development cost | 0 | 0 | 0 | 0 | ||||||
Future income tax | -287,709 | -14,525 | -287,709 | -14,525 | ||||||
Future net cash flows | 2,200,491 | 933,525 | 2,200,491 | 933,525 | ||||||
10% annual discount for timing of cash flow | -649,930 | -214,490 | -649,930 | -214,490 | ||||||
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves | 1,550,561 | 719,035 | 1,550,561 | 719,035 | ||||||
Changes in standardized measure [Roll Forward] | ||||||||||
Change due to current year operations Sales, net of production costs | -250,222 | -265,365 | ||||||||
Change due to revisions in standardized variables [Abstract] | ||||||||||
Income taxes | -287,709 | -14,525 | ||||||||
Accretion of discount | 112,021 | 29,807 | ||||||||
Net change in sales and transfer price, net of production costs | -193,777 | 48,603 | ||||||||
Previously estimated development costs incurred during the period | 0 | 0 | ||||||||
Changes in estimated future development costs | 0 | 0 | ||||||||
Revision and others | 0 | 30,997 | ||||||||
Discoveries | 999,242 | 0 | ||||||||
Sales of reserves in place | 0 | 0 | ||||||||
Changes in production rates and other | 451,971 | 591,448 | ||||||||
Net | 831,526 | 420,965 | ||||||||
Beginning of year | 719,035 | 298,070 | 719,035 | 298,070 | ||||||
End of year | 1,550,561 | 719,035 | 1,550,561 | 719,035 | ||||||
Gas [Member] | ||||||||||
Total proved reserves [Abstract] | ||||||||||
Balance at beginning of the period | 36,810 | 85,280 | 36,810 | 85,280 | ||||||
Extensions and discoveries | 24,944 | 0 | ||||||||
Purchase of minerals in place | 0 | 0 | ||||||||
Revisions of prior estimates | 23,673 | -39,011 | ||||||||
Sales of minerals in place | 0 | 0 | ||||||||
Production | -12,717 | -9,459 | ||||||||
Balance at end of the period | 72,710 | 36,810 | 72,710 | 36,810 | ||||||
Proved developed reserves | 72,710 | 36,810 | 72,710 | 36,810 | ||||||
Proved undeveloped reserves | 0 | 0 | 0 | 0 | ||||||
Oil [Member] | ||||||||||
Total proved reserves [Abstract] | ||||||||||
Balance at beginning of the period | 11,150,000,000 | 6,170,000,000 | 11,150,000,000 | 6,170,000,000 | ||||||
Extensions and discoveries | 32,090,000,000 | 0 | ||||||||
Purchase of minerals in place | 0 | 0 | ||||||||
Revisions of prior estimates | -5,958,000,000 | 7,943,000,000 | ||||||||
Sales of minerals in place | 0 | 0 | ||||||||
Production | -3,152,000,000 | -2,963,000,000 | ||||||||
Balance at end of the period | 34,130,000,000 | 11,150,000,000 | 34,130,000,000 | 11,150,000,000 | ||||||
Proved developed reserves | 34,130,000,000 | 11,150,000,000 | 34,130,000,000 | 11,150,000,000 | ||||||
Proved undeveloped reserves | 0 | 0 | 0 | 0 | ||||||
North America [Member] | ||||||||||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||||||||||
Operating revenue | 363,455 | 347,139 | ||||||||
Production Cost | 113,233 | 81,774 | ||||||||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||||||||||
Unproved properties not being amortized | 1,552,277 | 2,012,506 | 1,552,277 | 2,012,506 | ||||||
United States [Member] | ||||||||||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||||||||||
Unproved properties not being amortized | 1,552,277 | 1,552,277 | ||||||||
Proved properties being amortized | 4,570,915 | 865,889 | 4,570,915 | 865,889 | ||||||
Accumulated depreciation, depletion, amortization and impairment | -2,660,144 | -819,799 | -2,660,144 | -819,799 | ||||||
Net capitalized costs | 3,463,048 | 3,463,048 | ||||||||
Amortization Expense Per Equivalent Unit of Production or Per Dollar of Gross Revenue [Line Items] | ||||||||||
Amortization rate per unit (in dollars per share) | $66.05 | $66.05 | ||||||||
Property acquisition costs [Abstract] | ||||||||||
Proved | 54,716 | 8,640 | ||||||||
Unproved | 184,612 | 262,883 | ||||||||
Exploration costs | 3,005,469 | 0 | ||||||||
Development costs | 0 | 776,142 | ||||||||
Total costs incurred | 3,244,797 | 1,047,665 | ||||||||
Standardized measure of discounted future net cash flows [Abstract] | ||||||||||
Future cash inflows from sales of oil and gas | 3,579,990 | 1,306,020 | 3,579,990 | 1,306,020 | ||||||
Future production cost | -1,091,790 | -357,970 | -1,091,790 | -357,970 | ||||||
Future development cost | 0 | 0 | 0 | 0 | ||||||
Future income tax | -287,709 | -14,525 | -287,709 | -14,525 | ||||||
Future net cash flows | 2,200,491 | 933,525 | 2,200,491 | 933,525 | ||||||
10% annual discount for timing of cash flow | -649,930 | -214,490 | -649,930 | -214,490 | ||||||
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves | 1,550,561 | 719,035 | 1,550,561 | 719,035 | ||||||
Changes in standardized measure [Roll Forward] | ||||||||||
Change due to current year operations Sales, net of production costs | -250,222 | -265,365 | ||||||||
Change due to revisions in standardized variables [Abstract] | ||||||||||
Income taxes | -287,709 | -14,525 | ||||||||
Accretion of discount | 112,021 | 29,807 | ||||||||
Net change in sales and transfer price, net of production costs | -193,777 | 48,603 | ||||||||
Previously estimated development costs incurred during the period | 0 | 0 | ||||||||
Changes in estimated future development costs | 0 | 0 | ||||||||
Revision and others | 0 | 30,997 | ||||||||
Discoveries | 999,242 | 0 | ||||||||
Sales of reserves in place | 0 | 0 | ||||||||
Changes in production rates and other | 451,971 | 591,448 | ||||||||
Net | 831,526 | 420,965 | ||||||||
Beginning of year | 719,035 | 298,070 | 719,035 | 298,070 | ||||||
End of year | 1,550,561 | 719,035 | 1,550,561 | 719,035 | ||||||
United States [Member] | Gas [Member] | ||||||||||
Total proved reserves [Abstract] | ||||||||||
Balance at beginning of the period | 36,810 | 85,280 | 36,810 | 85,280 | ||||||
Extensions and discoveries | 24,944 | 0 | ||||||||
Purchase of minerals in place | 0 | 0 | ||||||||
Revisions of prior estimates | 23,673 | -39,011 | ||||||||
Sales of minerals in place | 0 | 0 | ||||||||
Production | -12,717 | -9,459 | ||||||||
Balance at end of the period | 72,710 | 36,810 | 72,710 | 36,810 | ||||||
Proved developed reserves | 72,710 | 36,810 | 72,710 | 36,810 | ||||||
Proved undeveloped reserves | 0 | 0 | 0 | 0 | ||||||
United States [Member] | Oil [Member] | ||||||||||
Total proved reserves [Abstract] | ||||||||||
Balance at beginning of the period | 11,150,000,000 | 6,170,000,000 | 11,150,000,000 | 6,170,000,000 | ||||||
Extensions and discoveries | 32,090,000,000 | 0 | ||||||||
Purchase of minerals in place | 0 | 0 | ||||||||
Revisions of prior estimates | -5,958,000,000 | 7,943,000,000 | ||||||||
Sales of minerals in place | 0 | 0 | ||||||||
Production | -3,152,000,000 | -2,963,000,000 | ||||||||
Balance at end of the period | 34,130,000,000 | 11,150,000,000 | 34,130,000,000 | 11,150,000,000 | ||||||
Proved developed reserves | 34,130,000,000 | 11,150,000,000 | 34,130,000,000 | 11,150,000,000 | ||||||
Proved undeveloped reserves | 0 | 0 | 0 | 0 | ||||||
South America [Member] | ||||||||||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||||||||||
Operating revenue | 0 | 0 | ||||||||
Production Cost | 0 | 0 | ||||||||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||||||||||
Unproved properties not being amortized | 2,034,007 | 1,789,536 | 2,034,007 | 1,789,536 | ||||||
Proved properties being amortized | 49,454,702 | 49,454,702 | 49,454,702 | 49,454,702 | ||||||
Accumulated depreciation, depletion, amortization and impairment | -49,454,702 | -49,454,702 | -49,454,702 | -49,454,702 | ||||||
Net capitalized costs | 2,034,007 | 2,034,007 | ||||||||
Amortization Expense Per Equivalent Unit of Production or Per Dollar of Gross Revenue [Line Items] | ||||||||||
Amortization rate per unit (in dollars per share) | $0 | $0 | ||||||||
Property acquisition costs [Abstract] | ||||||||||
Proved | 0 | 84,081 | ||||||||
Unproved | 9,984 | 0 | ||||||||
Exploration costs | 234,487 | 88,171 | ||||||||
Development costs | 0 | 0 | ||||||||
Total costs incurred | 244,471 | 172,252 | ||||||||
Standardized measure of discounted future net cash flows [Abstract] | ||||||||||
Future cash inflows from sales of oil and gas | 0 | 0 | 0 | 0 | ||||||
Future production cost | 0 | 0 | 0 | 0 | ||||||
Future development cost | 0 | 0 | 0 | 0 | ||||||
Future income tax | 0 | 0 | 0 | 0 | ||||||
Future net cash flows | 0 | 0 | ||||||||
10% annual discount for timing of cash flow | 0 | 0 | 0 | 0 | ||||||
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves | 0 | 0 | 0 | 0 | ||||||
Changes in standardized measure [Roll Forward] | ||||||||||
Change due to current year operations Sales, net of production costs | 0 | 0 | ||||||||
Change due to revisions in standardized variables [Abstract] | ||||||||||
Income taxes | 0 | 0 | ||||||||
Accretion of discount | 0 | 0 | ||||||||
Net change in sales and transfer price, net of production costs | 0 | 0 | ||||||||
Previously estimated development costs incurred during the period | 0 | 0 | ||||||||
Changes in estimated future development costs | 0 | 0 | ||||||||
Revision and others | 0 | 0 | ||||||||
Discoveries | 0 | 0 | ||||||||
Sales of reserves in place | 0 | 0 | ||||||||
Changes in production rates and other | 0 | 0 | ||||||||
Net | 0 | 0 | ||||||||
Beginning of year | 0 | 0 | 0 | 0 | ||||||
End of year | $0 | $0 | $0 | $0 | ||||||
South America [Member] | Gas [Member] | ||||||||||
Total proved reserves [Abstract] | ||||||||||
Balance at beginning of the period | 0 | 0 | 0 | 0 | ||||||
Extensions and discoveries | 0 | 0 | ||||||||
Purchase of minerals in place | 0 | 0 | ||||||||
Production | 0 | 0 | ||||||||
Balance at end of the period | 0 | 0 | 0 | 0 | ||||||
Proved developed reserves | 0 | 0 | ||||||||
Proved undeveloped reserves | 0 | 0 | 0 | 0 | ||||||
South America [Member] | Oil [Member] | ||||||||||
Total proved reserves [Abstract] | ||||||||||
Balance at beginning of the period | 0 | 0 | 0 | 0 | ||||||
Extensions and discoveries | 0 | 0 | ||||||||
Purchase of minerals in place | 0 | 0 | ||||||||
Revisions of prior estimates | 0 | 0 | ||||||||
Sales of minerals in place | 0 | 0 | ||||||||
Production | 0 | 0 | ||||||||
Balance at end of the period | 0 | 0 | 0 | 0 | ||||||
Proved developed reserves | 0 | 0 | ||||||||
Proved undeveloped reserves | 0 | 0 | 0 | 0 |
SUMMARIZED_QUARTERLY_FINANCIAL2
SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||||||||
Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | |
Summarized quarterly financial information [Abstract] | ||||||||||
Operating revenue | $133,177 | $56,805 | $67,450 | $106,023 | $142,573 | $170,311 | $19,223 | $15,032 | $363,455 | $347,139 |
Loss from operations | -2,224,590 | -512,919 | -684,728 | -536,105 | -610,247 | -526,248 | -1,296,227 | -785,191 | 3,958,342 | 3,217,913 |
Net loss | ($2,222,514) | ($511,653) | ($683,644) | ($535,368) | ($574,575) | ($526,464) | ($1,266,267) | ($806,175) | ($4,353,179) | ($3,173,481) |
Earnings per common share - basic (in dollars per share) | ($0.04) | ($0.01) | ($0.01) | ($0.01) | ($0.01) | ($0.01) | ($0.02) | ($0.02) | ||
Earnings per common share - diluted (in dollars per share) | ($0.04) | ($0.01) | ($0.01) | ($0.01) | ($0.01) | ($0.01) | ($0.02) | ($0.02) |