Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2013 | Mar. 03, 2014 | Jun. 30, 2013 |
Document and Entity Information [Abstract] | ' | ' | ' |
Entity Registrant Name | 'HOUSTON AMERICAN ENERGY CORP | ' | ' |
Entity Central Index Key | '0001156041 | ' | ' |
Current Fiscal Year End Date | '--12-31 | ' | ' |
Entity Well-known Seasoned Issuer | 'No | ' | ' |
Entity Voluntary Filers | 'No | ' | ' |
Entity Current Reporting Status | 'Yes | ' | ' |
Entity Filer Category | 'Smaller Reporting Company | ' | ' |
Entity Public Float | ' | ' | $10.90 |
Entity Common Stock, Shares Outstanding | ' | 52,169,945 | ' |
Document Fiscal Year Focus | '2013 | ' | ' |
Document Fiscal Period Focus | 'FY | ' | ' |
Document Type | '10-K | ' | ' |
Amendment Flag | 'false | ' | ' |
Document Period End Date | 31-Dec-13 | ' | ' |
CONSOLIDATED_BALANCE_SHEETS
CONSOLIDATED BALANCE SHEETS (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
CURRENT ASSETS | ' | ' |
Cash | $7,578,730 | $5,626,345 |
Restricted cash - letter of credit | 0 | 3,056,250 |
Accounts receivable - other | 0 | 3,436,305 |
Escrow receivable - current | 1,921,217 | 2,095,228 |
Prepaid expenses and other current assets | 46,175 | 36,539 |
TOTAL CURRENT ASSETS | 9,546,122 | 14,250,667 |
Oil and gas properties, full cost method | ' | ' |
Costs subject to amortization | 50,320,591 | 47,093,419 |
Costs not being amortized | 3,802,042 | 5,809,297 |
Office equipment | 90,004 | 90,004 |
Total | 54,212,637 | 52,992,720 |
Accumulated depletion, depreciation, amortization, and impairment | -50,349,833 | -47,105,751 |
PROPERTY AND EQUIPMENT, NET | 3,862,804 | 5,886,969 |
Other assets | 3,167 | 3,167 |
TOTAL ASSETS | 13,412,093 | 20,140,803 |
CURRENT LIABILITIES | ' | ' |
Accounts payable | 8,119 | 84,740 |
Accrued cash call due to operator | 0 | 3,219,128 |
Accrued expenses | 31,336 | 90,923 |
Taxes payable | 190,181 | 1,711,007 |
TOTAL CURRENT LIABILITIES | 229,636 | 5,105,798 |
LONG-TERM LIABILITIES | ' | ' |
Reserve for plugging and abandonment costs | 8,424 | 7,872 |
Taxes payable long-term | 0 | 193,398 |
TOTAL LONG-TERM LIABILITIES | 8,424 | 201,270 |
TOTAL LIABILITIES | 238,060 | 5,307,068 |
COMMITMENTS AND CONTINGENCIES | 2 | 2 |
SHAREHOLDERS' EQUITY | ' | ' |
Preferred stock, par value $0.001; 10,000,000 shares authorized, 0 shares issued and outstanding, respectively | 0 | 0 |
Common stock, par value $0.001; 150,000,000 shares authorized, 52,169,945 and 52,180,045 shares issued and outstanding, respectively | 52,170 | 52,180 |
Additional paid-in capital | 65,477,046 | 63,963,257 |
Accumulated deficit | -52,355,183 | -49,181,702 |
TOTAL SHAREHOLDERS' EQUITY | 13,174,033 | 14,833,735 |
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $13,412,093 | $20,140,803 |
CONSOLIDATED_BALANCE_SHEETS_Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
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) | 52,180,045 | 52,180,045 |
CONSOLIDATED_STATEMENTS_OF_OPE
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS [Abstract] | ' | ' |
OIL AND GAS REVENUE | $347,139 | $411,349 |
EXPENSES OF OPERATIONS | ' | ' |
Lease operating expense and severance tax | 81,774 | 195,381 |
Joint venture expense | 0 | 3,244 |
Depreciation and depletion | 24,954 | 66,971 |
Impairment of oil and gas properties | 0 | 46,235,574 |
Bad debt expense | 86,507 | 3,951,370 |
Foreign Equity Tax | 0 | 1,689,039 |
Loss on sale of securities | 0 | 97,267 |
General and administrative expense | 3,417,292 | 5,027,024 |
Total operating expenses | 3,610,527 | 57,265,870 |
Gain on sale of oil and gas properties | 45,475 | 387,314 |
Loss from operations | -3,217,913 | -56,467,207 |
OTHER INCOME (EXPENSE) | ' | ' |
Interest income | 33,238 | 10,844 |
Other income expense | -1,080 | -84,163 |
Total other income (expense) | 32,158 | -73,319 |
Net loss before taxes | -3,185,755 | -56,540,526 |
Income tax expense (benefit) | -12,274 | 216,923 |
Net loss | -3,173,481 | -56,757,449 |
Basic and diluted net loss per common share outstanding (in dollars per share) | ($0.06) | ($1.46) |
Basic and diluted weighted average number of common shares outstanding (in shares) | 52,175,677 | 38,799,434 |
COMPREHENSIVE INCOME (LOSS) | ' | ' |
Net loss | -3,173,481 | -56,757,449 |
Unrealized gain on marketable securities | 0 | -106,371 |
Net comprehensive loss | ($3,173,481) | ($56,863,820) |
CONSOLIDATED_STATEMENTS_OF_CHA
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (USD $) | Common Stock [Member] | Additional Paid-in Capital [Member] | Retained Earnings (Deficit) [Member] | Accumulated Other Comprehensive Income [Member] | Total |
Balance at Dec. 31, 2011 | $31,165 | $40,602,643 | $7,575,747 | $106,371 | $48,315,926 |
Balance (in shares) at Dec. 31, 2011 | 31,165,230 | ' | ' | ' | ' |
Stock issued for - | ' | ' | ' | ' | ' |
May 2012 offering | 6,200 | 13,137,800 | 0 | 0 | 13,144,000 |
May 2012 offering (in shares) | 6,200,000 | ' | ' | ' | ' |
October 2012 offering | 14,815 | 9,985,185 | 0 | 0 | 10,000,000 |
October 2012 offering (in shares) | 14,814,815 | ' | ' | ' | ' |
Offering costs | 0 | -1,785,546 | 0 | 0 | -1,785,546 |
Options issued to directors | 0 | 312,286 | 0 | 0 | 312,286 |
Options issued to employees | 0 | 1,463,467 | 0 | 0 | 1,463,467 |
Restricted stock issued to employees | 0 | 247,422 | 0 | 0 | 247,422 |
Other comprehensive income | 0 | 0 | 0 | -106,371 | -106,371 |
Net loss | 0 | 0 | -56,757,449 | 0 | -56,757,449 |
Balance at Dec. 31, 2012 | 52,180 | 63,963,257 | -49,181,702 | 0 | 14,833,735 |
Balance (in shares) at Dec. 31, 2012 | 52,180,045 | ' | ' | ' | ' |
Stock issued for - | ' | ' | ' | ' | ' |
Options issued to directors | 0 | 72,399 | 0 | 0 | 72,399 |
Options issued to employees | 0 | 1,284,240 | 0 | 0 | 1,284,240 |
Restricted stock issued to employees | 0 | 157,140 | 0 | 0 | 157,140 |
Restricted stock cancelled | -10 | 10 | 0 | 0 | 0 |
Restricted stock cancelled (in shares) | -10,100 | ' | ' | ' | ' |
Net loss | 0 | 0 | -3,173,481 | 0 | -3,173,481 |
Balance at Dec. 31, 2013 | $52,170 | $65,477,046 | ($52,355,183) | $0 | $13,174,033 |
Balance (in shares) at Dec. 31, 2013 | 52,169,945 | ' | ' | ' | ' |
CONSOLIDATED_STATEMENTS_OF_CAS
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
CASH FLOW FROM OPERATING ACTIVITIES | ' | ' |
Net loss | ($3,173,481) | ($56,757,449) |
Adjustments to reconcile net loss to net cash provided by (used in) operations | ' | ' |
Depreciation and depletion | 24,954 | 66,971 |
Stock-based compensation | 1,513,779 | 2,023,175 |
Deferred tax expense (benefit) | 0 | 3,195,583 |
Accretion of asset retirement obligation | 552 | 924 |
Amortization of deferred rent | 0 | -3,620 |
Gain on sale of oil and gas properties | -45,475 | -387,314 |
Impairment of oil and gas properties | 0 | 46,235,574 |
Bad debt expense | 86,507 | 3,951,370 |
Loss on sale of securities | 0 | 97,267 |
Change in operating assets and liabilities: | ' | ' |
Decrease in accounts receivable | 0 | 319,016 |
Increase in income tax refund receivable | 3,349,798 | -3,344,126 |
Increase in prepaid expense and other current assets | -9,636 | -12,547 |
(Decrease) increase in accounts payable and accrued expenses | -136,208 | 117,008 |
Foreign equity taxes payable | -1,714,224 | 1,877,331 |
Net cash used in operations | -103,434 | -2,620,837 |
CASH FLOW FROM INVESTING ACTIVITIES | ' | ' |
Release of restricted cash | 3,056,250 | 0 |
Payments for acquisition and development of oil and gas properties and assets | -1,219,917 | -26,033,065 |
Proceeds from sale of Colombian properties, net of expenses | 45,475 | 1,027,068 |
Proceeds from sale of securities | 0 | 660,625 |
Purchase of marketable securities | 0 | -156,817 |
Proceeds from escrow receivable, net | 174,011 | 1,460,633 |
Net cash provided by (used in) investing activities | 2,055,819 | -23,041,556 |
CASH FLOW FROM FINANCING ACTIVITIES | ' | ' |
Sale of common stock and warrants | 0 | 23,144,000 |
Common stock offering costs | 0 | -1,785,546 |
Net cash provided by financing activities | 0 | 21,358,454 |
INCREASE (DECREASE) IN CASH | 1,952,385 | -4,303,939 |
Cash, beginning of year | 5,626,345 | 9,930,284 |
Cash, end of year | 7,578,730 | 5,626,345 |
SUPPLEMENTAL CASH FLOW INFORMATION: | ' | ' |
Interest paid | 0 | 0 |
Taxes paid | 1,726,498 | 0 |
SUPPLEMENTAL NON-CASH INVESTING AND FINANCING ACTIVITIES | ' | ' |
Accrued oil and gas development costs | -3,219,128 | 3,219,128 |
Sales price of oil and gas properties placed in escrow | 0 | 166,995 |
Unrealized gain (loss) on available for sale securities | 0 | -106,371 |
Cancellation of stock | ($10) | $0 |
NATURE_OF_COMPANY_AND_SUMMARY_
NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2013 | |
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. | |
Reclassification | |
Certain amounts for prior periods have been reclassified to conform to the current presentation. | |
Cash and Cash Equivalents | |
Cash and cash equivalents consist of demand deposits and cash investments with initial maturity dates of less than three months. | |
Concentration of Credit Risk | |
Financial instruments that potentially subject the Company to a concentration of credit risk include cash and cash equivalents. The Company had cash deposits of approximately $7.3 million in excess of the FDIC’s current insured limit of $250,000 at December 31, 2013 for interest bearing accounts. The Company has not experienced any losses on its deposits of cash and cash equivalents. | |
Marketable Securities – Available for Sale | |
Management determines the appropriate classification of its investments in marketable securities at the time of purchase and reevaluates such determination at each balance sheet date. Equity securities not classified as trading securities are classified as available-for-sale. Available-for-sale securities are reported at fair value and unrealized gains and losses are included in stockholders' equity. Management determines fair value of its investments based on quoted market prices at each balance sheet date. | |
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, 2013, 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, 2013 or 2012. | |
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 $12,111 and $49,391 for the years ended December 31, 2013 and 2012, respectively and accumulated amortization, depreciation and impairment was $50,274,501 and $47,043,262 at December 31, 2013 and 2012, 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 2013 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. | |
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 $12,843 and $17,580 for 2013 and 2012, respectively, and accumulated depreciation was $75,332 and $62,489 at December 31, 2013 and 2012, respectively. | |
Asset Retirement Obligations | |
For the Company, asset retirement obligations (“ARO”) represent the systematic, monthly accretion and depreciation of future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, an adjustment is made to the full cost pool, with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. Although the Company’s domestic policy with respect to ARO is to assign depleted wells to a salvager for the assumption of abandonment obligations before the wells have reached their economic limits, the Company has estimated its future ARO obligation with respect to its domestic operations. The ARO assets, which are carried on the balance sheet as part of the full cost pool, have been included in our amortization base for the purposes of calculating depreciation, depletion and amortization expense. For the purposes of calculating the ceiling test, the future cash outflows associated with settling the ARO liability have been included in the computation of the discounted present value of estimated future net revenues. | |
Joint Venture Expense | |
Joint venture expense reflects the indirect field operating and regional administrative expenses billed by the operator of the Colombian concessions. | |
Income Taxes | |
Deferred income taxes are provided on a liability method whereby deferred tax assets and liabilities are established for the difference between the financial reporting and income tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. | |
Stock-Based Compensation | |
The Company measures the cost of employee services received in exchange for stock and stock options based on the grant date fair value of the awards. The Company determines the fair value of stock option grants using the Black-Scholes option pricing model. The Company determines the fair value of shares of non-vested stock based on the last quoted price of our stock on the date of the share grant. The fair value determined represents the cost for the award and is recognized over the vesting period during which an employee is required to provide service in exchange for the award. As share-based compensation expense is recognized based on awards ultimately expected to vest, the Company reduces the expense for estimated forfeitures based on historical forfeiture rates. Previously recognized compensation costs may be adjusted to reflect the actual forfeiture rate for the entire award at the end of the vesting period. Excess tax benefits, if any, are recognized as an addition to paid-in capital. | |
Preferred Stock | |
The Company has authorized 10,000,000 shares of preferred stock with a par value of $0.001. The Board of Directors shall determine the designations, rights, preferences, privileges and voting rights of the preferred stock as well as any restrictions and qualifications thereon. No shares of preferred stock have been issued. | |
Net Income (Loss) Per Share | |
Basic net income (loss) per share is computed by dividing the net income (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 income (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, 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 dilutive. For the year ended December 31, 2012, outstanding options to purchase 2,443,057 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, 2013, 46.5% of the Company’s net oil and gas property investment, and 0% of its revenue for the year ended December 31, 2013, was with or derived from interests operated in Colombia. | |
For 2013, 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, 2013 and 2012, respectively. | |
Subsequent Events | |
The Company evaluated subsequent events from December 31, 2013 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. |
ACCOUNTS_RECEIVABLE_OTHER
ACCOUNTS RECEIVABLE - OTHER | 12 Months Ended |
Dec. 31, 2013 | |
ACCOUNTS RECEIVABLE - OTHER [Abstract] | ' |
ACCOUNTS RECEIVABLE - OTHER | ' |
NOTE 2—ACCOUNTS RECEIVABLE—OTHER | |
Gulf United Energy, Inc. | |
In connection with the Company’s acquisition in July 2010 of an additional 12.5% interest in the approximately 345,452 acre CPO 4 Block in the Llanos Basin of Columbia and which is operated by SK Innovation Co. LTD (“SK Innovation”), the Company entered into a separate agreement with Gulf United Energy, Inc. (“Gulf United”) whereby the Company waived its right of first refusal under the CPO 4 Block Joint Operating Agreement for the specific purpose of permitting Gulf United to acquire from SK Innovation a 12.5% interest in the CPO 4 Block. Under the agreement with Gulf United, as a condition of the Company’s agreement to waive its preferential rights, Gulf United agreed to pay to the Company, not later than 30 days following ANH approval, (i) the Company’s 12.5% share of Past Costs (as defined in the Farmout Agreement with SK Innovation) incurred through July 31, 2010, and (ii) the Company’s 25% share of seismic acquisition costs incurred through July 31, 2010, or a total of $3,951,370. The amount due from Gulf United was classified as accounts receivable – other in the accompanying balance sheet as of December 31, 2012. | |
As a result of Gulf United Energy’s delinquency in satisfying its financial obligations with respect to the CPO 4 prospect, during the year ended December 31, 2012, the Company wrote-off the receivable from Gulf United for $3,951,370 and recorded bad debt expense. | |
Hupecol Operating, LLC | |
During 2011, Hupecol Operating, LLC (“Hupecol”) disbursed funds from a 5% contingency escrow established with a portion of the proceeds from the sale of Hupecol Dorotea & Cabiona Holdings, LLC (“HDC, LLC”), to pay certain operating expenses incurred on behalf of the purchaser of these entities. Hupecol sought reimbursement from the purchaser for these expenses as part of the post-closing process but to date has been unsuccessful in such efforts. The Company established a receivable from Hupecol for the Company’s proportionate share of the escrow funds disbursed for these expenses of $86,507. See Note 3. As a result of the inability to recover such amounts, the amount due from Hupecol was written off as of December 31, 2013. |
ESCROW_RECEIVABLE
ESCROW RECEIVABLE | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
ESCROW RECEIVABLE [Abstract] | ' | ||||||||||||
ESCROW RECEIVABLE | ' | ||||||||||||
NOTE 3—ESCROW RECEIVABLE | |||||||||||||
At December 31, 2013 and December 31, 2012, the Company’s balance sheet reflected the following escrow receivables relating to various oil and gas properties previously held by the Company: | |||||||||||||
Balance as of December 31, 2013 | |||||||||||||
Description | Current | Noncurrent | Total | ||||||||||
Tambaqui Escrow | $ | 22,029 | $ | — | $ | 22,029 | |||||||
HDC LLC and HL LLC 15% Escrow | 1,827,929 | — | 1,827,929 | ||||||||||
HDC LLC and HL LLC 5% Contingency | 57,321 | — | 57,321 | ||||||||||
HC LLC 5% Contingency | 13,938 | — | 13,938 | ||||||||||
TOTAL | $ | 1,921,217 | $ | — | $ | 1,921,217 | |||||||
Balance as of December 31, 2012 | |||||||||||||
Description | Current | Noncurrent | Total | ||||||||||
Tambaqui Escrow | $ | 22,029 | $ | — | $ | 22,029 | |||||||
HDC LLC and HL LLC 15% Escrow | 1,827,929 | — | 1,827,929 | ||||||||||
HDC LLC and HL LLC 5% Contingency | 57,321 | — | 57,321 | ||||||||||
HC LLC 14.66% Escrow | 151,048 | — | 151,048 | ||||||||||
HC LLC 5% Contingency | 36,901 | — | 36,901 | ||||||||||
TOTAL | $ | 2,095,228 | $ | — | $ | 2,095,228 | |||||||
The principal escrow receivables relate to the sale of HC LLC (see Note 5 below) and the 2010 sale of HDC LLC and Hupecol Llanos LLC (“HL LLC”). | |||||||||||||
Hupecol Cuervo, LLC | |||||||||||||
Changes in escrow receivables during 2013 reflect the release of $151,048 from the HC LLC 14.66% escrow and $22,964 from the HC LLC 5% contingency. | |||||||||||||
Hupecol Dorotea and Cabiona, LLC and Hupecol Llanos, LLC Escrow | |||||||||||||
Pursuant to the terms of the sales of HDC, LLC and HL, LLC, on the closing date of the sale, a portion of the purchase price was deposited in escrow to settle post-closing adjustments under the purchase and sale agreement. The Company’s proportionate interest in the escrow deposit totaled $7,069,810, and was recorded as escrow receivable. | |||||||||||||
As of December 31, 2013 and 2012, $1,921,217 and $2,095,228 was recorded as escrow receivable – current. Subsequent to December 31, 2013, the Company collected $1,614,290 of the escrow receivable (see Note 12). |
MARKETABLE_SECURITIES_AVAILABL
MARKETABLE SECURITIES - AVAILABLE FOR SALE | 12 Months Ended |
Dec. 31, 2013 | |
MARKETABLE SECURITIES - AVAILABLE FOR SALE [Abstract] | ' |
MARKETABLE SECURITIES - AVAILABLE FOR SALE | ' |
NOTE 4—MARKETABLE SECURITIES—AVAILABLE FOR SALE | |
During the year ended December 31, 2012, the Company purchased shares of common stock in a publicly traded company at a cost of $156,817. This investment was classified as marketable securities - available for sale and, accordingly, any unrealized changes in market values were recognized as other comprehensive income in the consolidated statements of operations. During the year ended December 31, 2012, the company sold all of its marketable securities and recognized a $97,267 loss. |
OIL_AND_GAS_PROPERTIES
OIL AND GAS PROPERTIES | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
OIL AND GAS PROPERTIES [Abstract] | ' | ||||||||||||
OIL AND GAS PROPERTIES | ' | ||||||||||||
NOTE 5—OIL AND GAS PROPERTIES | |||||||||||||
Sale of La Cuerva and LLA 62 Blocks | |||||||||||||
During the first quarter of 2012, the Company sold all of its interest in Hupecol Cuerva, LLC (“HC, LLC”), which holds interests in the La Cuerva block and, pending approval of the Colombian authorities, the LLA 62 block, together covering approximately 90,000 acres in the Llanos Basin in Colombia. | |||||||||||||
HC, LLC sold for $75 million, adjusted for working capital. 13.3% of the sales price of HC, LLC will be held in escrow to fund potential claims arising from the sale. Pursuant to its 1.6% ownership interest in HC, LLC, the Company received 1.6% in the net sale proceeds after deduction of commissions, overriding royalty interest, and transaction expenses; subject to the escrow holdback and a further contingency holdback by Hupecol of 1.3% of the sales price. Following completion of the sale of HC, LLC, the Company has no continuing interest in the La Cuerva and LLA 62 blocks. | |||||||||||||
At December 31, 2011, the Company’s estimated proved reserves associated with the La Cuerva and LLA 62 blocks totaled 94,619 barrels of oil, which represented 82% of the Company’s estimated proved oil and natural gas reserves. Sales of oil and gas properties under the full cost method of accounting are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and reserves. Since the sale of these oil and gas properties would significantly alter the relationship, the Company recognized a gain on the sale of $315,119 during 2012, computed as follows: | |||||||||||||
Sales price | $ | 1,224,393 | |||||||||||
Add: Transfer of asset retirement and other obligations | 34,471 | ||||||||||||
Less: Transaction costs | (30,330 | ) | |||||||||||
Less: Prepaid deposits | (54,857 | ) | |||||||||||
Less: Carrying value of oil and gas properties, net | (858,558 | ) | |||||||||||
Net gain on sale | $ | 315,119 | |||||||||||
The following table presents pro forma data that reflects revenue, income from continuing operations, net loss and loss per common share for 2012 as if the HC, LLC sale had occurred at the beginning of each period and excludes the gain on sale. | |||||||||||||
Pro-Forma Information (unaudited): | 2012 | ||||||||||||
Oil and gas revenue | $ | 148,163 | |||||||||||
Loss from operations | $ | (56,566,181 | ) | ||||||||||
Net loss | $ | (56,847,211 | ) | ||||||||||
Basic and diluted loss per common share | $ | (1.47 | ) | ||||||||||
Impairments | |||||||||||||
During 2012, the Company completed operations on three test wells on the CPO 4 block in Colombia. Each of the test wells was determined to be noncommercial and was plugged and abandoned. As a result of the determinations to plug and abandon each of those test wells, the Company included the costs related to those wells in the full cost pool for inclusion in the ceiling test. The Company recorded an impairment charge of $46,235,574 during 2012 to write off costs not being amortized that were attributable to the drilling of the test wells on the CPO 4 block as well as to write off seismic exploration and evaluation cost, general and administrative cost and environmental and governmental cost that were attributable to the test wells through December 31, 2012. | |||||||||||||
Unevaluated Oil and Gas Properties | |||||||||||||
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 | |||||||
Unevaluated oil and gas properties not subject to amortization at December 31, 2012 included the following: | |||||||||||||
North | South | Total | |||||||||||
America | America | ||||||||||||
Leasehold acquisition costs | $ | 972,005 | $ | 2,015,850 | $ | 2,987,855 | |||||||
Geological, geophysical, screening and evaluation costs | 880 | 2,820,562 | 2,821,442 | ||||||||||
Total | $ | 972,885 | $ | 4,836,412 | $ | 5,809,297 |
ASSET_RETIREMENT_OBLIGATION
ASSET RETIREMENT OBLIGATION | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
ASSET RETIREMENT OBLIGATION [Abstract] | ' | ||||||||||||||||
ASSET RETIREMENT OBLIGATION | ' | ||||||||||||||||
NOTE 6—Asset Retirement Obligation | |||||||||||||||||
The following table describes changes in our asset retirement liability during each of the years ended December 31, 2013 and 2012. The ARO liability in the table below includes amounts classified as both current and long-term at December 31, 2013 and 2012. | |||||||||||||||||
North America | South America | ||||||||||||||||
Years Ended | Years Ended | ||||||||||||||||
31-Dec | 31-Dec | ||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||
ARO liability at January 1 | $ | 7,872 | $ | 7,320 | $ | — | $ | 34,099 | |||||||||
Accretion expense | 552 | 552 | — | 372 | |||||||||||||
Liabilities incurred from drilling | — | — | — | — | |||||||||||||
Liabilities settled—assets sold | — | — | — | (34,471 | ) | ||||||||||||
Changes in estimates | — | — | — | — | |||||||||||||
ARO liability at December 31, | $ | 8,424 | $ | 7,872 | $ | — | $ | — |
COMMON_STOCK
COMMON STOCK | 12 Months Ended |
Dec. 31, 2013 | |
COMMON STOCK [Abstract] | ' |
COMMON STOCK | ' |
NOTE 7—COMMON STOCK | |
May 2012 Offering | |
In May 2012, the Company sold to institutional investors 6,200,000 units, with each unit consisting of one of our common shares and one warrant to purchase one common share, for gross proceeds of approximately $13.14 million, before deducting placement agent fees and estimated offering expenses of $527,000 recorded as cost of capital, in a "registered direct" offering. The investors purchased the units at a purchase price of $2.12 per unit. The warrants, which represent the right to acquire an aggregate of up to 6,200,000 common shares, are exercisable at any time on or after November 9, 2012 and prior to November 9, 2015 at an exercise price of $2.68 per share, which was 120% of the closing price of our common shares on the NYSE MKT on May 2, 2012. | |
October 2012 Offering | |
In October 2012, the Company sold 14,814,815 units, with each unit consisting of one of our common shares, one Class A Warrant and one Class B Warrant, for gross proceeds of approximately $10.0 million, before deducting placement agent fees and estimated offering expenses of $828,000 recorded as cost of capital, in a "registered direct" public offering. The investors purchased the units at a purchase price of $0.675 per unit. The Class A Warrants represent the right to acquire one-half common share per warrant, or an aggregate of up to 7,407,407 common shares for a period of six months at an exercise price of $0.81 per share. The Class B Warrants represent the right to acquire one-half common share per warrant, or an aggregate of up to 7,407,407 common shares for a period of three years at an exercise price of $0.90 per share. |
STOCKBASED_COMPENSATION
STOCK-BASED COMPENSATION | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
STOCK-BASED COMPENSATION [Abstract] | ' | ||||||||||||||||
STOCK-BASED COMPENSATION | ' | ||||||||||||||||
NOTE 8—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 2012, the Company granted 325,000 options to non-employee directors and 1,200,000 options to employees. | |||||||||||||||||
300,000 of the options granted to non-employee directors vested 20% on the grant date and vested as to the remaining 80% nine months from the grant date, have a ten year life and have an exercise price of $1.65 per share. Of those options, 155,475 were exercisable commencing 6 months from the date of grant and 144,525 were exercisable on and after shareholder approval of the amendment to the Company’s 2008 Equity Incentive Plan to increase the shares reserved under the plan to facilitate exercise. The option grants to non-employee directors, excluding grants that were subject to shareholder approval of amendment to the 2008 Equity Incentive Plan, were valued on the date of grant at $128,328 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 0.35%, (2) expected life in years of 2.83, (3) expected stock volatility of 84.6%, and (4) expected dividend yield of 1.21%. | |||||||||||||||||
25,000 of the options granted to non-employee directors were granted to a new non-employee director, vested 20% on the grant date and vested as to the remaining 80% nine months from the grant date, have a ten year life and have an exercise price of $1.18 per share. Those options have a fair value of $19,375 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 0.82%, (2) expected life in years of 5.835, (3) expected stock volatility of 91.70%, and (4) expected dividend yield of 1.70%. | |||||||||||||||||
The 1,200,000 options granted to employees vested on the grant date, have a ten-year life and have an exercise price of $1.65 per share. Of those options, 429,000 were exercisable commencing 6 months from the date of grant and 771,000 were exercisable on and after shareholder approval of the amendment to the Company’s 2008 Equity Incentive Plan to increase the shares reserved under the plan to facilitate exercise. The option grants to employees, excluding grants that were subject to shareholder approval of amendment to the 2008 Equity Incentive Plan, were valued on the date of grant at $354,098 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 0.35%, (2) expected life in years of 2.83, (3) expected stock volatility of 84.6%, and (4) expected dividend yield of 1.21%. | |||||||||||||||||
In June 2013, the Company’s shareholders approved the amendment to the Company’s 2008 Equity Incentive Plan to increase the shares reserved thereunder, resulting in the vesting of options to purchase 915,525 shares of common stock. The options were valued on the date of shareholder approval at $164,377 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. | |||||||||||||||||
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. | |||||||||||||||||
Option activity during 2013 and 2012 was as follows: | |||||||||||||||||
Options | Weighted | Weighted | Aggregate | ||||||||||||||
Average | Average | Intrinsic | |||||||||||||||
Exercise | Remaining | Value | |||||||||||||||
Price | Contractual | ||||||||||||||||
Term (in | |||||||||||||||||
Years) | |||||||||||||||||
Outstanding at December 31, 2011 | 1,833,582 | $ | 7.02 | ||||||||||||||
Granted | 609,475 | $ | 1.63 | ||||||||||||||
Exercised | — | $ | — | ||||||||||||||
Forfeited | — | $ | — | ||||||||||||||
Outstanding at December 31, 2012 | 2,443,057 | $ | 5.68 | ||||||||||||||
Granted (1) | 2,215,525 | $ | 0.86 | ||||||||||||||
Exercised | — | $ | — | ||||||||||||||
Forfeited | (2,065,750 | ) | $ | 2.53 | |||||||||||||
Outstanding at December 31, 2013 | 2,592,832 | $ | 4.07 | 6.97 | $ | - | |||||||||||
-1 | Includes 915,525 options granted in 2012, the exercise of which was subject to shareholder approval of an amendment to the Company’s 2008 Equity Incentive Plan to increase the shares reserved for issuance thereunder, which approval was obtained during 2013. | ||||||||||||||||
During 2013 and 2012, the Company recognized $1,513,779 and $1,775,753, 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, 2013, non-vested options totaled 530,000 and total unrecognized stock-based compensation expense related to non-vested stock options was $353,555. The unrecognized expense is expected to be recognized over a weighted average period of 0.45 years. The weighted average remaining contractual term of the outstanding options and exercisable options at December 31, 2013 is 6.97 years and 7.24 years, respectively. | |||||||||||||||||
As of December 31, 2013, there were 3,907,168 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 2013 and 2012, $157,140 and $247,422 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, 2013, there was $37,001 of unrecognized compensation cost related to unvested restricted stock. The cost is expected to be recognized over a weighted average period of approximately 0.45 years. | |||||||||||||||||
Share-Based Compensation Expense | |||||||||||||||||
The following table reflects share-based compensation recorded by the Company for 2013 and 2012: | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
Share-based compensation expense included in general and administrative expense | $ | 1,513,779 | $ | 2,023,175 | |||||||||||||
Earnings per share effect of share-based compensation expense | $ | (0.03 | ) | $ | (0.05 | ) |
TAXES
TAXES | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
TAXES [Abstract] | ' | ||||||||
TAXES | ' | ||||||||
NOTE 9—TAXES | |||||||||
The following table sets forth a reconciliation of the statutory federal income tax for the years ending December 31, 2013 and 2012. | |||||||||
2013 | 2012 | ||||||||
Income (loss) before income taxes | $ | (3,185,755 | ) | $ | (56,540,526 | ) | |||
Income tax expense (benefit) computed at statutory rates | $ | (1,115,014 | ) | $ | (19,223,779 | ) | |||
Permanent differences, nondeductible expenses | (1,177,769 | ) | 282,547 | ||||||
Current Colombian tax expense | 8,880 | 216,923 | |||||||
Increase (decrease) in valuation allowance | (902,498 | ) | 22,026,880 | ||||||
Valuation allowance (decrease) related to carryback | — | (3,345,683 | ) | ||||||
Change in tax rate | (79,409 | ) | — | ||||||
Return to accrual items | 127,913 | — | |||||||
Foreign tax credit | 3,649,259 | — | |||||||
Other adjustment | (21,156 | ) | 260,035 | ||||||
NOL adjustment | (502,480 | ) | — | ||||||
State (net of federal benefit) | — | — | |||||||
Tax provision (benefit) | $ | (12,274 | ) | $ | 216,923 | ||||
Total Provision | |||||||||
Current Federal | $ | — | $ | (3,195,583 | ) | ||||
Current State | — | — | |||||||
Deferred Federal | — | 3,195,583 | |||||||
Deferred State | — | — | |||||||
Permanent True-up | (21,154 | ) | — | ||||||
Foreign | 8,880 | 216,923 | |||||||
Total provision (benefit) | $ | (12,274 | ) | $ | 216,923 | ||||
At December 31, 2013 the Company has a federal tax loss carry forward of $48,582,039 and a foreign tax credit carry forward of $484,697, 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, 2013 and 2012 are set out below. | |||||||||
2013 | 2012 | ||||||||
Non-Current Deferred tax assets: | |||||||||
Net operating loss carry forwards | $ | 17,003,714 | $ | 12,964,068 | |||||
Foreign tax credit carry forwards | 484,697 | 4,133,956 | |||||||
Deferred state tax | 23,277 | 66,505 | |||||||
Stock compensation | 3,618,643 | 3,000,568 | |||||||
Book in excess of tax depreciation, depletion, and capitalization methods on oil and gas properties | (2,151,329 | ) | (271,419 | ) | |||||
Other | (83,560 | ) | (95,738 | ) | |||||
Colombia future tax obligations | — | — | |||||||
Total Non-Current Deferred tax assets | 18,895,442 | 19,797,940 | |||||||
Valuation Allowance | (18,895,442 | ) | (19,797,940 | ) | |||||
Net deferred tax asset | $ | — | $ | — | |||||
Foreign Income Taxes | |||||||||
The Company owns direct ownership in several properties in Colombia operated by Hupecol and SK Innovation. Colombia’s current income tax rate is 33%. During 2013 and 2012, we recorded foreign tax expense of $8,880 and $216,923, respectively. | |||||||||
Foreign Equity Tax | |||||||||
During 2012, we recorded a one-time foreign equity tax expense of $1,689,039 relating to a newly enacted Colombian equity tax measure based on the equity of our Colombian branch as of January 1, 2011. For U.S. GAAP purposes, the equity tax is not considered an income tax. |
RELATED_PARTIES
RELATED PARTIES | 12 Months Ended |
Dec. 31, 2013 | |
RELATED PARTIES [Abstract] | ' |
RELATED PARTIES | ' |
NOTE 10—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 2013 and 2012, Mr. Terwilliger received royalty payments relating to those properties totaling $20,305 and $16,594, respectively, and Mr. Tawes received royalty payments relating to those properties totaling $20,305 and $16,594, respectively. |
COMMITMENTS_AND_CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended | ||||
Dec. 31, 2013 | |||||
COMMITMENTS AND CONTINGENCIES [Abstract] | ' | ||||
COMMITMENTS AND CONTINGENCIES | ' | ||||
NOTE 11—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 | ||||
2014 | 91,432 | ||||
2015 | 93,793 | ||||
2016 | 96,162 | ||||
2017 | 40,479 | ||||
Total | 321,866 | ||||
Total rental expense was $97,220 and $90,194 in 2013 and 2012, respectively. The Company does not have any capital leases or other operating lease commitments. | |||||
Standby Letter of Credit – CPO 4 Block | |||||
On November 5, 2009, JP Morgan Chase issued a Letter of Credit to Banco de Bogota S.A. for $2,037,500. Banco de Bogota then in turn issued a Stand by Letter of Credit to the Agency De National Hydrocarbons to guaranty the Company’s compliance and proper execution of the work obligations relating to the phase one (1) work program of the CPO-4 block for the Company’s 25% interest in the Block. Per the Standby Letter of Credit issued between JP Morgan Chase and Banco de Bogota, the Company was required to keep on deposit with JP Morgan Chase $2,037,500. In addition, the Company was required by JP Morgan Chase to pay fees associated with the Standby Letter of Credit equal to 1.0% per year of the amount, equal to $20,375. | |||||
On December 2, 2010, JP Morgan Chase amended the Letter of Credit to Banco de Bogota S.A. to increase the total amount of the Letter of Credit to $3,056,250. Banco de Bogota then in turn issued an amended Stand by Letter of Credit to the Agency de National Hydrocarbons to guaranty the Company’s compliance and proper execution of the work obligations relating to the phase one (1) work program for the CPO-4 block for the Company’s 37.5% interest in the Block. Per the amended Standby Letter of Credit issued between JP Morgan Chase and Banco de Bogota, the date of expiration was extended until April 1, 2013 and the Company is required to keep on deposit with JP Morgan Chase $3,056,250. This increase in deposits was related to the Company increasing its interest in the CPO 4 block from 25.0% to 37.5%. All other terms and conditions of the Letter of Credit remained unchanged. The Company paid JP Morgan fees associated with the Standby Letter of Credit equal to 1.0% per year of the amount, equal to $32,070. The deposit with JP Morgan Chase was classified as Restricted cash – letter of credit in the accompanying balance sheet as of December 31, 2012. Due to the settlement agreement with SK Innovation in which the Company assigned its 37.5% interest in the CPO-4 prospect, the Company did not renew the Letter of Credit and, during 2013, funds securing the Letter of Credit, in the amount of $3,056,250, were released to the Company. | |||||
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. | |||||
At December 31, 2013, the Company was the subject of a formal investigation being conducted by the Securities and Exchange Commission (the “SEC”). Pursuant to the investigation, the Company received subpoenas issued by the SEC. The subpoenas called for the testimony of certain of the Company’s officers and the delivery of certain documents. The subpoenas were issued pursuant to a nonpublic formal order of private investigation issued by the SEC on March 1, 2011, which followed a nonpublic informal inquiry commenced by the SEC in October 2010. The Company received a copy of the nonpublic formal order of private investigation on February 10, 2012 in connection with a subpoena issued by the SEC. The SEC is investigating whether there have been any violations of the federal securities laws and has focused on matters relating to disclosures in the late 2009 and early 2010 time period regarding resource potential for the CPO 4 prospect. The Company has presented information supporting its disclosure relative to resource potential on the CPO 4 prospect. On August 29, 2013, the Company and John Terwilliger received a “Wells” notice advising them that the staff of the SEC has made a preliminary recommendation to initiate an enforcement action and providing them an opportunity to provide reasons of law, policy or fact why the proposed enforcement action should not be filed. The Company has cooperated fully, and is committed to continuing to cooperate fully, with the SEC in this matter. It is not possible at this time to predict the timing or outcome of the SEC investigation, including whether or when any proceedings might be initiated, when these matters may be resolved or what, if any, penalties or other remedies may be imposed, and whether any such penalties or remedies would have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows. | |||||
In connection with the ongoing investigation being conducted by the SEC and indemnification provisions contained in an engagement agreement with Global Hunter Securities, LLC relating to our 2009 equity offering, in July 2012, the Company entered into an agreement with Global Hunter to settle any and all claims by Global Hunter related to reimbursement of attorney’s fees under the indemnity provision. During 2012, the Company paid a total of $490,850 to Global Hunter and in exchange for the payments, the Company was granted a full release by Global Hunter Securities of any future claims or liabilities asserted by Global Hunter in connection with the offering. The payment to Global Hunter Securities was recorded as a charge to additional paid in capital and is listed under the Cash Flow from Financing Activities in the statement of cash flows as Cost of capital. | |||||
On April 27, 2012, a purported class action lawsuit was filed in the U.S. District Court for the Southern District of Texas against us and certain of our executive officers: Steve Silverman v. Houston American Energy Corp. et al., Case No. 4:12-CV-1332. The complaint generally alleges 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. Two additional class action lawsuits were filed against us in May 2012. The complaints seek 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. On January 14, 2013, we filed a motion to dismiss and, on August 22, 2013, the court granted our motion and dismissed the complaint. The plaintiffs have since filed a Notice of Appeal of the dismissal of the complaint and the appeal is presently pending before the U.S. Court of Appeals for the Fifth Circuit. We believe all of the claims in the consolidated class action lawsuits are without merit and intend to vigorously defend against these claims. It is not possible at this time to predict the timing or outcome of the class action lawsuits that have or may be filed. | |||||
On July 19, 2012, a purported derivative cause of action was filed in the U.S. District Court for the Southern District of Texas against certain of the Company’s directors and officers and the Company, as nominal defendant: E. Howard King, Jr., derivatively, on behalf of Houston American Energy Corp., v. John F. Terwilliger, John P. Boylan, Orrie Lee Tawes III, Stephen Hartzell, James J. Jacobs, Kenneth A. Jeffers, defendants, and Houston American Energy Corp., as nominal defendant, Case No. 4:12-CV-02182. The complaint asserts a cause of action by a shareholder on behalf of the Company against certain of its directors and senior executive officers in connection with the June 11, 2012 approval of payment of certain bonuses, increases in salary, grant of certain stock options and entry into certain Change in Control Agreements. The complaint alleges that the approval of such matters constituted breach of fiduciary duty and corporate waste and seeks injunctive relief to bar each of the actions in question and seeks restitution. No damages have been or, by the nature of the derivative cause of action, are expected to be alleged against the Company. The Company may, however, incur certain costs and demands on management time and resources in connection with the lawsuit. On February 26, 2013, an order was entered granting a motion by the company to dismiss the lawsuit and providing leave to the plaintiff to amend its complaint to cure pleading deficiencies. The Plaintiff’s allotted time to amend its complaint by the Court expired on March 26, 2013, and no amendment was made by the Plaintiff, effectively ending the lawsuit. | |||||
Environmental Contingencies | |||||
The Company’s oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require the Company to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on its results of operations, competitive position or financial condition as well as the industry in general. Under these environmental laws and regulations, the Company could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether the Company was responsible for the release or if its operations were standard in the industry at the time they were performed. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. | |||||
Development Commitments | |||||
During the ordinary course of oil and gas prospect development, the Company commits to a proportionate share for the cost of acquiring mineral interests, drilling exploratory or development wells and acquiring seismic and geological information. | |||||
Production Incentive Compensation Plan | |||||
In August 2013, the Company’s compensation committee adopted a Production Incentive Compensation Plan. The purpose of the Plan is to encourage employees and consultants participating in the Plan to identify and secure for the Company participation in attractive oil and gas opportunities. | |||||
Under that Plan, the committee may establish one or more Pools and designate employees and consultants to participate in those Pools and designate prospects and wells, and a defined percentage of the Company’s revenues from those wells, to fund those Pools. Only prospects acquired on or after establishment of the Plan, and excluding all prospects in Colombia, may be designated to fund a Pool. The maximum percentage of the Company’s share of revenues from a well that may be designated to fund a Pool is 2% (the “Pool Cap”); provided, however, that with respect to wells with a net revenue interest to the 8/8 of less than 73%, the Pool Cap with respect to such wells shall be reduced on a 1-for-1 basis such that no portion of the Company’s revenues from a well may be designated to fund a Pool if the NRI is 71% or less. | |||||
Designated participants in a Pool will be assigned a specific percentage out of the Company’s revenues assigned to the Pool and will be paid that percentage of such revenues from all wells designated to such Pool and spud during that participant’s employment or services with the Company. In no event may the percentage assigned to the Company’s chief executive officer relative to any well within a Pool exceed one-half of the applicable Pool Cap for that well. Payouts of revenues funded into Pools shall be made to participants not later than 60 days following year end, subject to the committee’s right to make partial interim payouts. Participants will continue to receive their percentage share of revenues from wells included in a Pool and spud during the term of their employment or service so long as revenues continue to be derived by the Company from those wells even after termination of employment or services of the Participant; provided, however, that a participant’s interest in all Pools shall terminate on the date of termination of employment or services where such termination is for cause. | |||||
In the event of certain changes in control of the Company, the acquirer or survivor of such transaction must assume all obligations under the Plan; provided, however, that in lieu of such assumption obligation, the committee may, at its sole discretion, assign overriding royalty interests in wells to substantially mirror the rights of participants under the Plan. Similarly, the committee may, at any time, assign overriding royalty interests in wells in settlement of obligations under the Plan. | |||||
The Plan is administered by the Company’s compensation committee which shall consult with the Company’s chief executive officer relative to Pool participants, prospects, wells and interests assign although the committee will have final and absolute authority to make all such determinations. |
SUBSEQUENT_EVENTS
SUBSEQUENT EVENTS | 12 Months Ended |
Dec. 31, 2013 | |
SUBSEQUENT EVENTS [Abstract] | ' |
SUBSEQUENT EVENTS | ' |
NOTE 12—SUBSEQUENT EVENTS | |
Subsequent to December 31, 2013, the Company collected $1,614,290 of escrow receivables, leaving an uncollected balance of $306,927 as of March 12, 2014. |
GEOGRAPHICAL_INFORMATION
GEOGRAPHICAL INFORMATION | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
GEOGRAPHICAL INFORMATION [Abstract] | ' | ||||||||||||||||
GEOGRAPHICAL INFORMATION | ' | ||||||||||||||||
NOTE 13—GEOGRAPHICAL INFORMATION | |||||||||||||||||
The Company currently has operations in two geographical areas, the United States and Colombia. Revenues for the years ended December 31, 2013 and 2012 and long-lived assets as of December 31, 2013 and 2012 attributable to each geographical area are presented below: | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
Revenues | Long Lived | Revenues | Long Lived | ||||||||||||||
Assets, Net | Assets, Net | ||||||||||||||||
North America | 347,139 | 2,073,268 | $ | 148,163 | $ | 1,050,557 | |||||||||||
South America | — | 1,789,536 | 263,186 | 4,836,412 | |||||||||||||
Total | 347,139 | 3,862,804 | $ | 411,349 | $ | 5,886,969 |
SUPPLEMENTAL_INFORMATION_ON_OI
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
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 14—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: | |||||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||||
Revenues | |||||||||||||||||||||||||
North America | $ | 347,139 | $ | 148,163 | |||||||||||||||||||||
South America | — | 263,186 | |||||||||||||||||||||||
$ | 347,139 | $ | 411,349 | ||||||||||||||||||||||
Production Cost | |||||||||||||||||||||||||
North America | $ | 81,774 | $ | 76,593 | |||||||||||||||||||||
South America | — | 118,788 | |||||||||||||||||||||||
$ | 81,774 | $ | 195,381 | ||||||||||||||||||||||
Capital Costs | |||||||||||||||||||||||||
Capitalized costs and accumulated depletion relating to the Company’s oil and gas producing activities as of December 31, 2013, all of which are onshore properties located in the United States and Colombia, South America are summarized below: | |||||||||||||||||||||||||
United States | South | Total | |||||||||||||||||||||||
America | |||||||||||||||||||||||||
Unproved properties not being amortized | $ | 2,012,506 | $ | 1,789,536 | $ | 3,802,042 | |||||||||||||||||||
Proved 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 | $ | 2,058,596 | $ | 1,789,536 | $ | 3,848,132 | |||||||||||||||||||
Amortization Rate | |||||||||||||||||||||||||
The amortization rate per unit based on barrel of oil equivalents was $2.67 for the United States and $0 for South America for the year ended December 31, 2013. | |||||||||||||||||||||||||
Acquisition, Exploration and Development Costs Incurred | |||||||||||||||||||||||||
Costs incurred in oil and gas property acquisition, exploration and development activities as of December 31, 2013 and 2012 are summarized below: | |||||||||||||||||||||||||
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 | ||||||||||||||||||||||
2012 | |||||||||||||||||||||||||
United States | South America | ||||||||||||||||||||||||
Property acquisition costs: | |||||||||||||||||||||||||
Proved | $ | — | $ | — | |||||||||||||||||||||
Unproved | 110,836 | — | |||||||||||||||||||||||
Exploration costs | — | 25,915,741 | |||||||||||||||||||||||
Development costs | 6,488 | — | |||||||||||||||||||||||
Total costs incurred | $ | 117,324 | $ | 25,915,741 | |||||||||||||||||||||
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, 2011 | 86,800 | 6,540 | — | 94,619 | 86,800 | 101,159 | |||||||||||||||||||
Extensions and discoveries | — | — | — | — | — | — | |||||||||||||||||||
Purchase of minerals in place | — | — | — | — | — | — | |||||||||||||||||||
Revisions of prior estimates | 10,546 | 662 | — | 253 | 10,546 | 915 | |||||||||||||||||||
Sale of minerals in place | — | — | — | (93,117 | ) | — | (93,117 | ) | |||||||||||||||||
Production | (12,066 | ) | (1,032 | ) | — | (1,755 | ) | (12,066 | ) | (2,787 | ) | ||||||||||||||
Balance December 31, 2012 | 85,280 | 6,170 | — | — | 85,280 | 6,170 | |||||||||||||||||||
Purchase of minerals in place | |||||||||||||||||||||||||
Revisions to prior estimates | (39,011 | ) | 7,943 | — | — | (39,011 | ) | 7,943 | |||||||||||||||||
Sales 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 | |||||||||||||||||||
Proved developed reserves | |||||||||||||||||||||||||
at December 31, 2012 | 85,280 | 6,170 | — | — | 85,280 | 6,170 | |||||||||||||||||||
at December 31, 2013 | 36,810 | 11,150 | 36,810 | 11,150 | |||||||||||||||||||||
Proved undeveloped reserves | |||||||||||||||||||||||||
at December 31, 2012 | — | — | — | — | — | — | |||||||||||||||||||
at December 31, 2013 | — | — | — | — | — | — | |||||||||||||||||||
During 2013 and 2012, the Company recorded extensions and discoveries resulting principally from its ongoing drilling operations in Colombia. As of December 31, 2013, we had no proved undeveloped (“PUD”) reserves. None of the PUD reserves as of December 31, 2012 were converted to proved developed producing reserves in 2013. All remaining PUD reserves as of December 31, 2011 were sold during 2012 in connection with the sale of our indirect 1.6% ownership in an entity holding interests in the La Cuerva and LLA 62 blocks in Colombia. | |||||||||||||||||||||||||
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, 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 | 591,447 | — | 591,447 | ||||||||||||||||||||||
Net | 420,965 | — | 420,965 | ||||||||||||||||||||||
Beginning of year | 298,070 | — | 298,070 | ||||||||||||||||||||||
End of year | $ | 719,035 | $ | — | $ | 719,035 | |||||||||||||||||||
Standardized measure of discounted future net cash flows at December 31, 2012: | |||||||||||||||||||||||||
United | South | Total | |||||||||||||||||||||||
States | America | ||||||||||||||||||||||||
Future cash inflows from sales of oil and gas | $ | 921,070 | $ | — | $ | 921,070 | |||||||||||||||||||
Future production cost | (392,430 | ) | — | (392,430 | ) | ||||||||||||||||||||
Future development cost | — | — | — | ||||||||||||||||||||||
Future income tax | — | — | — | ||||||||||||||||||||||
528,640 | 528,640 | ||||||||||||||||||||||||
10% annual discount for timing of cash flow | (230,570 | ) | — | (230,570 | ) | ||||||||||||||||||||
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves | $ | 298,070 | $ | — | $ | 298,070 | |||||||||||||||||||
Changes in standardized measure: | |||||||||||||||||||||||||
Change due to current year operations Sales, net of production costs | (71,570 | ) | (144,398 | ) | (215,968 | ) | |||||||||||||||||||
Change due to revisions in standardized variables: | |||||||||||||||||||||||||
Income taxes | (12,911 | ) | — | (12,911 | ) | ||||||||||||||||||||
Accretion of discount | 49,238 | — | 49,238 | ||||||||||||||||||||||
Net change in sales and transfer price, net of production costs | (62,724 | ) | — | (62,724 | ) | ||||||||||||||||||||
Previously estimated development costs incurred during the period | — | — | — | ||||||||||||||||||||||
Changes in estimated future development costs | — | — | — | ||||||||||||||||||||||
Revision and others | 35,781 | — | 35,781 | ||||||||||||||||||||||
Discoveries | — | — | — | ||||||||||||||||||||||
Sales of reserves in place | — | (2,505,431 | ) | (2,505,431 | ) | ||||||||||||||||||||
Changes in production rates and other | (42,954 | ) | — | (42,954 | ) | ||||||||||||||||||||
Net | (105,140 | ) | (2,649,829 | ) | (2,754,969 | ) | |||||||||||||||||||
Beginning of year | 403,210 | 2,649,829 | 3,053,039 | ||||||||||||||||||||||
End of year | $ | 298,070 | $ | — | $ | 298,070 |
SUMMARIZED_QUARTERLY_FINANCIAL
SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) [Abstract] | ' | ||||||||||||||||
SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | ' | ||||||||||||||||
NOTE 15—SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | |||||||||||||||||
Three Months Ended | |||||||||||||||||
March 31, | June 30, | Sept. 30, | Dec. 31, | ||||||||||||||
2013 | |||||||||||||||||
Operating revenue | $ | 15,032 | $ | 19,223 | $ | 170,311 | $ | 142,573 | |||||||||
Loss from operations | (785,191 | ) | (1,296,227 | ) | (526,248 | ) | (610,247 | ) | |||||||||
Net loss | (806,175 | ) | (1,266,267 | ) | (526,464 | ) | (574,575 | ) | |||||||||
Loss per common share - basic | $ | (0.02 | ) | $ | (0.02 | ) | $ | (0.01 | ) | $ | (0.01 | ) | |||||
Loss per common share - diluted | $ | (0.02 | ) | $ | (0.02 | ) | $ | (0.01 | ) | (0.01 | ) | ||||||
2012 | |||||||||||||||||
Operating revenue | $ | 320,510 | $ | 36,347 | $ | 30,752 | $ | 23,740 | |||||||||
Income from operations | (20,633,191 | ) | (18,654,298 | ) | (5,910,504 | ) | (11,269,214 | ) | |||||||||
Net income | (20,668,095 | ) | (22,022,079 | ) | (5,935,713 | ) | (8,131,562 | ) | |||||||||
Earnings per common share - basic | $ | (0.66 | ) | $ | (0.63 | ) | $ | (0.16 | ) | $ | (0.16 | ) | |||||
Earnings per common share - diluted | (0.66 | ) | (0.63 | ) | (0.16 | ) | (0.16 | ) |
NATURE_OF_COMPANY_AND_SUMMARY_1
NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2013 | |
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. | |
Reclassification | ' |
Reclassification | |
Certain amounts for prior periods have been reclassified to conform to the current presentation. | |
Cash and Cash Equivalents | ' |
Cash and Cash Equivalents | |
Cash and cash equivalents consist of demand deposits and cash investments with initial maturity dates of less than three months. | |
Concentration of Credit Risk | ' |
Concentration of Credit Risk | |
Financial instruments that potentially subject the Company to a concentration of credit risk include cash and cash equivalents. The Company had cash deposits of approximately $7.3 million in excess of the FDIC’s current insured limit of $250,000 at December 31, 2013 for interest bearing accounts. The Company has not experienced any losses on its deposits of cash and cash equivalents. | |
Marketable Securities - Available for Sale | ' |
Marketable Securities – Available for Sale | |
Management determines the appropriate classification of its investments in marketable securities at the time of purchase and reevaluates such determination at each balance sheet date. Equity securities not classified as trading securities are classified as available-for-sale. Available-for-sale securities are reported at fair value and unrealized gains and losses are included in stockholders' equity. Management determines fair value of its investments based on quoted market prices at each balance sheet date. | |
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, 2013, 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, 2013 or 2012. | |
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 $12,111 and $49,391 for the years ended December 31, 2013 and 2012, respectively and accumulated amortization, depreciation and impairment was $50,274,501 and $47,043,262 at December 31, 2013 and 2012, 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 2013 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. | |
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 $12,843 and $17,580 for 2013 and 2012, respectively, and accumulated depreciation was $75,332 and $62,489 at December 31, 2013 and 2012, respectively. | |
Asset Retirement Obligations | ' |
Asset Retirement Obligations | |
For the Company, asset retirement obligations (“ARO”) represent the systematic, monthly accretion and depreciation of future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, an adjustment is made to the full cost pool, with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. Although the Company’s domestic policy with respect to ARO is to assign depleted wells to a salvager for the assumption of abandonment obligations before the wells have reached their economic limits, the Company has estimated its future ARO obligation with respect to its domestic operations. The ARO assets, which are carried on the balance sheet as part of the full cost pool, have been included in our amortization base for the purposes of calculating depreciation, depletion and amortization expense. For the purposes of calculating the ceiling test, the future cash outflows associated with settling the ARO liability have been included in the computation of the discounted present value of estimated future net revenues. | |
Joint Venture Expense | ' |
Joint Venture Expense | |
Joint venture expense reflects the indirect field operating and regional administrative expenses billed by the operator of the Colombian concessions. | |
Income Taxes | ' |
Income Taxes | |
Deferred income taxes are provided on a liability method whereby deferred tax assets and liabilities are established for the difference between the financial reporting and income tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. | |
Stock-Based Compensation | ' |
Stock-Based Compensation | |
The Company measures the cost of employee services received in exchange for stock and stock options based on the grant date fair value of the awards. The Company determines the fair value of stock option grants using the Black-Scholes option pricing model. The Company determines the fair value of shares of non-vested stock based on the last quoted price of our stock on the date of the share grant. The fair value determined represents the cost for the award and is recognized over the vesting period during which an employee is required to provide service in exchange for the award. As share-based compensation expense is recognized based on awards ultimately expected to vest, the Company reduces the expense for estimated forfeitures based on historical forfeiture rates. Previously recognized compensation costs may be adjusted to reflect the actual forfeiture rate for the entire award at the end of the vesting period. Excess tax benefits, if any, are recognized as an addition to paid-in capital. | |
Preferred Stock | ' |
Preferred Stock | |
The Company has authorized 10,000,000 shares of preferred stock with a par value of $0.001. The Board of Directors shall determine the designations, rights, preferences, privileges and voting rights of the preferred stock as well as any restrictions and qualifications thereon. No shares of preferred stock have been issued. | |
Net Income (Loss) Per Share | ' |
Net Income (Loss) Per Share | |
Basic net income (loss) per share is computed by dividing the net income (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 income (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, 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 dilutive. For the year ended December 31, 2012, outstanding options to purchase 2,443,057 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, 2013, 46.5% of the Company’s net oil and gas property investment, and 0% of its revenue for the year ended December 31, 2013, was with or derived from interests operated in Colombia. | |
For 2013, 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, 2013 and 2012, respectively. | |
Subsequent Events | ' |
Subsequent Events | |
The Company evaluated subsequent events from December 31, 2013 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, 2013 | |||||||||||||
ESCROW RECEIVABLE [Abstract] | ' | ||||||||||||
Escrow receivables relating to oil and gas properties | ' | ||||||||||||
At December 31, 2013 and December 31, 2012, the Company’s balance sheet reflected the following escrow receivables relating to various oil and gas properties previously held by the Company: | |||||||||||||
Balance as of December 31, 2013 | |||||||||||||
Description | Current | Noncurrent | Total | ||||||||||
Tambaqui Escrow | $ | 22,029 | $ | — | $ | 22,029 | |||||||
HDC LLC and HL LLC 15% Escrow | 1,827,929 | — | 1,827,929 | ||||||||||
HDC LLC and HL LLC 5% Contingency | 57,321 | — | 57,321 | ||||||||||
HC LLC 5% Contingency | 13,938 | — | 13,938 | ||||||||||
TOTAL | $ | 1,921,217 | $ | — | $ | 1,921,217 | |||||||
Balance as of December 31, 2012 | |||||||||||||
Description | Current | Noncurrent | Total | ||||||||||
Tambaqui Escrow | $ | 22,029 | $ | — | $ | 22,029 | |||||||
HDC LLC and HL LLC 15% Escrow | 1,827,929 | — | 1,827,929 | ||||||||||
HDC LLC and HL LLC 5% Contingency | 57,321 | — | 57,321 | ||||||||||
HC LLC 14.66% Escrow | 151,048 | — | 151,048 | ||||||||||
HC LLC 5% Contingency | 36,901 | — | 36,901 | ||||||||||
TOTAL | $ | 2,095,228 | $ | — | $ | 2,095,228 |
OIL_AND_GAS_PROPERTIES_Tables
OIL AND GAS PROPERTIES (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
OIL AND GAS PROPERTIES [Abstract] | ' | ||||||||||||
Computation of gain on sale of oil and gas property | ' | ||||||||||||
Since the sale of these oil and gas properties would significantly alter the relationship, the Company recognized a gain on the sale of $315,119 during 2012, computed as follows: | |||||||||||||
Sales price | $ | 1,224,393 | |||||||||||
Add: Transfer of asset retirement and other obligations | 34,471 | ||||||||||||
Less: Transaction costs | (30,330 | ) | |||||||||||
Less: Prepaid deposits | (54,857 | ) | |||||||||||
Less: Carrying value of oil and gas properties, net | (858,558 | ) | |||||||||||
Net gain on sale | $ | 315,119 | |||||||||||
Pro-forma information | ' | ||||||||||||
The following table presents pro forma data that reflects revenue, income from continuing operations, net loss and loss per common share for 2012 as if the HC, LLC sale had occurred at the beginning of each period and excludes the gain on sale. | |||||||||||||
Pro-Forma Information (unaudited): | 2012 | ||||||||||||
Oil and gas revenue | $ | 148,163 | |||||||||||
Loss from operations | $ | (56,566,181 | ) | ||||||||||
Net loss | $ | (56,847,211 | ) | ||||||||||
Basic and diluted loss per common share | $ | (1.47 | ) | ||||||||||
Schedule of unevaluated oil and gas properties not subject to amortization | ' | ||||||||||||
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 | |||||||
Unevaluated oil and gas properties not subject to amortization at December 31, 2012 included the following: | |||||||||||||
North | South | Total | |||||||||||
America | America | ||||||||||||
Leasehold acquisition costs | $ | 972,005 | $ | 2,015,850 | $ | 2,987,855 | |||||||
Geological, geophysical, screening and evaluation costs | 880 | 2,820,562 | 2,821,442 | ||||||||||
Total | $ | 972,885 | $ | 4,836,412 | $ | 5,809,297 |
ASSET_RETIREMENT_OBLIGATION_Ta
ASSET RETIREMENT OBLIGATION (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
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, 2013 and 2012. The ARO liability in the table below includes amounts classified as both current and long-term at December 31, 2013 and 2012. | |||||||||||||||||
North America | South America | ||||||||||||||||
Years Ended | Years Ended | ||||||||||||||||
31-Dec | 31-Dec | ||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||
ARO liability at January 1 | $ | 7,872 | $ | 7,320 | $ | — | $ | 34,099 | |||||||||
Accretion expense | 552 | 552 | — | 372 | |||||||||||||
Liabilities incurred from drilling | — | — | — | — | |||||||||||||
Liabilities settled—assets sold | — | — | — | (34,471 | ) | ||||||||||||
Changes in estimates | — | — | — | — | |||||||||||||
ARO liability at December 31, | $ | 8,424 | $ | 7,872 | $ | — | $ | — |
STOCKBASED_COMPENSATION_Tables
STOCK-BASED COMPENSATION (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
STOCK-BASED COMPENSATION [Abstract] | ' | ||||||||||||||||
Option activity | ' | ||||||||||||||||
Option activity during 2013 and 2012 was as follows: | |||||||||||||||||
Options | Weighted | Weighted | Aggregate | ||||||||||||||
Average | Average | Intrinsic | |||||||||||||||
Exercise | Remaining | Value | |||||||||||||||
Price | Contractual | ||||||||||||||||
Term (in | |||||||||||||||||
Years) | |||||||||||||||||
Outstanding at December 31, 2011 | 1,833,582 | $ | 7.02 | ||||||||||||||
Granted | 609,475 | $ | 1.63 | ||||||||||||||
Exercised | — | $ | — | ||||||||||||||
Forfeited | — | $ | — | ||||||||||||||
Outstanding at December 31, 2012 | 2,443,057 | $ | 5.68 | ||||||||||||||
Granted (1) | 2,215,525 | $ | 0.86 | ||||||||||||||
Exercised | — | $ | — | ||||||||||||||
Forfeited | (2,065,750 | ) | $ | 2.53 | |||||||||||||
Outstanding at December 31, 2013 | 2,592,832 | $ | 4.07 | 6.97 | $ | - | |||||||||||
-1 | Includes 915,525 options granted in 2012, the exercise of which was subject to shareholder approval of an amendment to the Company’s 2008 Equity Incentive Plan to increase the shares reserved for issuance thereunder, which approval was obtained during 2013. | ||||||||||||||||
Share-based compensation expense | ' | ||||||||||||||||
The following table reflects share-based compensation recorded by the Company for 2013 and 2012: | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
Share-based compensation expense included in general and administrative expense | $ | 1,513,779 | $ | 2,023,175 | |||||||||||||
Earnings per share effect of share-based compensation expense | $ | (0.03 | ) | $ | (0.05 | ) |
TAXES_Tables
TAXES (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
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, 2013 and 2012. | |||||||||
2013 | 2012 | ||||||||
Income (loss) before income taxes | $ | (3,185,755 | ) | $ | (56,540,526 | ) | |||
Income tax expense (benefit) computed at statutory rates | $ | (1,115,014 | ) | $ | (19,223,779 | ) | |||
Permanent differences, nondeductible expenses | (1,177,769 | ) | 282,547 | ||||||
Current Colombian tax expense | 8,880 | 216,923 | |||||||
Increase (decrease) in valuation allowance | (902,498 | ) | 22,026,880 | ||||||
Valuation allowance (decrease) related to carryback | — | (3,345,683 | ) | ||||||
Change in tax rate | (79,409 | ) | — | ||||||
Return to accrual items | 127,913 | — | |||||||
Foreign tax credit | 3,649,259 | — | |||||||
Other adjustment | (21,156 | ) | 260,035 | ||||||
NOL adjustment | (502,480 | ) | — | ||||||
State (net of federal benefit) | — | — | |||||||
Tax provision (benefit) | $ | (12,274 | ) | $ | 216,923 | ||||
Total Provision | |||||||||
Current Federal | $ | — | $ | (3,195,583 | ) | ||||
Current State | — | — | |||||||
Deferred Federal | — | 3,195,583 | |||||||
Deferred State | — | — | |||||||
Permanent True-up | (21,154 | ) | — | ||||||
Foreign | 8,880 | 216,923 | |||||||
Total provision (benefit) | $ | (12,274 | ) | $ | 216,923 | ||||
Significant components of the deferred tax asset and liability | ' | ||||||||
Significant components of the deferred tax asset and liability as of December 31, 2013 and 2012 are set out below. | |||||||||
2013 | 2012 | ||||||||
Non-Current Deferred tax assets: | |||||||||
Net operating loss carry forwards | $ | 17,003,714 | $ | 12,964,068 | |||||
Foreign tax credit carry forwards | 484,697 | 4,133,956 | |||||||
Deferred state tax | 23,277 | 66,505 | |||||||
Stock compensation | 3,618,643 | 3,000,568 | |||||||
Book in excess of tax depreciation, depletion, and capitalization methods on oil and gas properties | (2,151,329 | ) | (271,419 | ) | |||||
Other | (83,560 | ) | (95,738 | ) | |||||
Colombia future tax obligations | — | — | |||||||
Total Non-Current Deferred tax assets | 18,895,442 | 19,797,940 | |||||||
Valuation Allowance | (18,895,442 | ) | (19,797,940 | ) | |||||
Net deferred tax asset | $ | — | $ | — |
COMMITMENTS_AND_CONTINGENCIES_
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended | ||||
Dec. 31, 2013 | |||||
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 | ||||
2014 | 91,432 | ||||
2015 | 93,793 | ||||
2016 | 96,162 | ||||
2017 | 40,479 | ||||
Total | 321,866 |
GEOGRAPHICAL_INFORMATION_Table
GEOGRAPHICAL INFORMATION (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
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, 2013 and 2012 and long-lived assets as of December 31, 2013 and 2012 attributable to each geographical area are presented below: | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
Revenues | Long Lived | Revenues | Long Lived | ||||||||||||||
Assets, Net | Assets, Net | ||||||||||||||||
North America | 347,139 | 2,073,268 | $ | 148,163 | $ | 1,050,557 | |||||||||||
South America | — | 1,789,536 | 263,186 | 4,836,412 | |||||||||||||
Total | 347,139 | 3,862,804 | $ | 411,349 | $ | 5,886,969 |
SUPPLEMENTAL_INFORMATION_ON_OI1
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Tables) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
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: | |||||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||||
Revenues | |||||||||||||||||||||||||
North America | $ | 347,139 | $ | 148,163 | |||||||||||||||||||||
South America | — | 263,186 | |||||||||||||||||||||||
$ | 347,139 | $ | 411,349 | ||||||||||||||||||||||
Production Cost | |||||||||||||||||||||||||
North America | $ | 81,774 | $ | 76,593 | |||||||||||||||||||||
South America | — | 118,788 | |||||||||||||||||||||||
$ | 81,774 | $ | 195,381 | ||||||||||||||||||||||
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, 2013, all of which are onshore properties located in the United States and Colombia, South America are summarized below: | |||||||||||||||||||||||||
United States | South | Total | |||||||||||||||||||||||
America | |||||||||||||||||||||||||
Unproved properties not being amortized | $ | 2,012,506 | $ | 1,789,536 | $ | 3,802,042 | |||||||||||||||||||
Proved 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 | $ | 2,058,596 | $ | 1,789,536 | $ | 3,848,132 | |||||||||||||||||||
Costs incurred in oil and gas property acquisition, exploration and development activities | ' | ||||||||||||||||||||||||
Costs incurred in oil and gas property acquisition, exploration and development activities as of December 31, 2013 and 2012 are summarized below: | |||||||||||||||||||||||||
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 | ||||||||||||||||||||||
2012 | |||||||||||||||||||||||||
United States | South America | ||||||||||||||||||||||||
Property acquisition costs: | |||||||||||||||||||||||||
Proved | $ | — | $ | — | |||||||||||||||||||||
Unproved | 110,836 | — | |||||||||||||||||||||||
Exploration costs | — | 25,915,741 | |||||||||||||||||||||||
Development costs | 6,488 | — | |||||||||||||||||||||||
Total costs incurred | $ | 117,324 | $ | 25,915,741 | |||||||||||||||||||||
Total estimated proved developed and undeveloped reserves by product type | ' | ||||||||||||||||||||||||
Total estimated proved developed and undeveloped reserves by product type and the changes therein are set forth below for the years indicated. | |||||||||||||||||||||||||
United States | South America | Total | |||||||||||||||||||||||
Gas (mcf) | Oil (bbls) | Gas (mcf) | Oil (bbls) | Gas (mcf) | Oil (bbls) | ||||||||||||||||||||
Total proved reserves | |||||||||||||||||||||||||
Balance December 31, 2011 | 86,800 | 6,540 | — | 94,619 | 86,800 | 101,159 | |||||||||||||||||||
Extensions and discoveries | — | — | — | — | — | — | |||||||||||||||||||
Purchase of minerals in place | — | — | — | — | — | — | |||||||||||||||||||
Revisions of prior estimates | 10,546 | 662 | — | 253 | 10,546 | 915 | |||||||||||||||||||
Sale of minerals in place | — | — | — | (93,117 | ) | — | (93,117 | ) | |||||||||||||||||
Production | (12,066 | ) | (1,032 | ) | — | (1,755 | ) | (12,066 | ) | (2,787 | ) | ||||||||||||||
Balance December 31, 2012 | 85,280 | 6,170 | — | — | 85,280 | 6,170 | |||||||||||||||||||
Purchase of minerals in place | |||||||||||||||||||||||||
Revisions to prior estimates | (39,011 | ) | 7,943 | — | — | (39,011 | ) | 7,943 | |||||||||||||||||
Sales 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 | |||||||||||||||||||
Proved developed reserves | |||||||||||||||||||||||||
at December 31, 2012 | 85,280 | 6,170 | — | — | 85,280 | 6,170 | |||||||||||||||||||
at December 31, 2013 | 36,810 | 11,150 | 36,810 | 11,150 | |||||||||||||||||||||
Proved undeveloped reserves | |||||||||||||||||||||||||
at December 31, 2012 | — | — | — | — | — | — | |||||||||||||||||||
at December 31, 2013 | — | — | — | — | — | — | |||||||||||||||||||
Standardized measure of discounted future net cash flows | ' | ||||||||||||||||||||||||
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 | 591,447 | — | 591,447 | ||||||||||||||||||||||
Net | 420,965 | — | 420,965 | ||||||||||||||||||||||
Beginning of year | 298,070 | — | 298,070 | ||||||||||||||||||||||
End of year | $ | 719,035 | $ | — | $ | 719,035 | |||||||||||||||||||
Standardized measure of discounted future net cash flows at December 31, 2012: | |||||||||||||||||||||||||
United | South | Total | |||||||||||||||||||||||
States | America | ||||||||||||||||||||||||
Future cash inflows from sales of oil and gas | $ | 921,070 | $ | — | $ | 921,070 | |||||||||||||||||||
Future production cost | (392,430 | ) | — | (392,430 | ) | ||||||||||||||||||||
Future development cost | — | — | — | ||||||||||||||||||||||
Future income tax | — | — | — | ||||||||||||||||||||||
528,640 | 528,640 | ||||||||||||||||||||||||
10% annual discount for timing of cash flow | (230,570 | ) | — | (230,570 | ) | ||||||||||||||||||||
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves | $ | 298,070 | $ | — | $ | 298,070 | |||||||||||||||||||
Changes in standardized measure: | |||||||||||||||||||||||||
Change due to current year operations Sales, net of production costs | (71,570 | ) | (144,398 | ) | (215,968 | ) | |||||||||||||||||||
Change due to revisions in standardized variables: | |||||||||||||||||||||||||
Income taxes | (12,911 | ) | — | (12,911 | ) | ||||||||||||||||||||
Accretion of discount | 49,238 | — | 49,238 | ||||||||||||||||||||||
Net change in sales and transfer price, net of production costs | (62,724 | ) | — | (62,724 | ) | ||||||||||||||||||||
Previously estimated development costs incurred during the period | — | — | — | ||||||||||||||||||||||
Changes in estimated future development costs | — | — | — | ||||||||||||||||||||||
Revision and others | 35,781 | — | 35,781 | ||||||||||||||||||||||
Discoveries | — | — | — | ||||||||||||||||||||||
Sales of reserves in place | — | (2,505,431 | ) | (2,505,431 | ) | ||||||||||||||||||||
Changes in production rates and other | (42,954 | ) | — | (42,954 | ) | ||||||||||||||||||||
Net | (105,140 | ) | (2,649,829 | ) | (2,754,969 | ) | |||||||||||||||||||
Beginning of year | 403,210 | 2,649,829 | 3,053,039 | ||||||||||||||||||||||
End of year | $ | 298,070 | $ | — | $ | 298,070 |
SUMMARIZED_QUARTERLY_FINANCIAL1
SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) [Abstract] | ' | ||||||||||||||||
Summarized quarterly financial information | ' | ||||||||||||||||
Three Months Ended | |||||||||||||||||
March 31, | June 30, | Sept. 30, | Dec. 31, | ||||||||||||||
2013 | |||||||||||||||||
Operating revenue | $ | 15,032 | $ | 19,223 | $ | 170,311 | $ | 142,573 | |||||||||
Loss from operations | (785,191 | ) | (1,296,227 | ) | (526,248 | ) | (610,247 | ) | |||||||||
Net loss | (806,175 | ) | (1,266,267 | ) | (526,464 | ) | (574,575 | ) | |||||||||
Loss per common share - basic | $ | (0.02 | ) | $ | (0.02 | ) | $ | (0.01 | ) | $ | (0.01 | ) | |||||
Loss per common share - diluted | $ | (0.02 | ) | $ | (0.02 | ) | $ | (0.01 | ) | (0.01 | ) | ||||||
2012 | |||||||||||||||||
Operating revenue | $ | 320,510 | $ | 36,347 | $ | 30,752 | $ | 23,740 | |||||||||
Income from operations | (20,633,191 | ) | (18,654,298 | ) | (5,910,504 | ) | (11,269,214 | ) | |||||||||
Net income | (20,668,095 | ) | (22,022,079 | ) | (5,935,713 | ) | (8,131,562 | ) | |||||||||
Earnings per common share - basic | $ | (0.66 | ) | $ | (0.63 | ) | $ | (0.16 | ) | $ | (0.16 | ) | |||||
Earnings per common share - diluted | (0.66 | ) | (0.63 | ) | (0.16 | ) | (0.16 | ) |
NATURE_OF_COMPANY_AND_SUMMARY_2
NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
Concentration of Credit Risk [Abstract] | ' | ' |
Cash deposits in excess of the FDIC's current insured limit | $7,300,000 | ' |
Current insured limit on interest bearing accounts | 250,000 | ' |
Ceiling Test [Abstract] | ' | ' |
Discount rate, net of related tax effects (in hundredths) | 10.00% | ' |
Property, Plant and Equipment [Line Items] | ' | ' |
Depletion and amortization | 24,954 | 66,971 |
Accumulated amortization, depreciation and impairment | 50,349,833 | 47,105,751 |
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) | 46.50% | ' |
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) | 2,592,832 | 2,443,057 |
Oil and Gas Properties [Member] | ' | ' |
Property, Plant and Equipment [Line Items] | ' | ' |
Depletion and amortization | 12,111 | 49,391 |
Accumulated amortization, depreciation and impairment | 50,274,501 | 47,043,262 |
Furniture and Equipment [Member] | ' | ' |
Property, Plant and Equipment [Line Items] | ' | ' |
Depletion and amortization | 12,843 | 17,580 |
Accumulated amortization, depreciation and impairment | $75,332 | $62,489 |
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 | ' |
ACCOUNTS_RECEIVABLE_OTHER_Deta
ACCOUNTS RECEIVABLE - OTHER (Details) (USD $) | 12 Months Ended | 1 Months Ended | 12 Months Ended | ||||
Dec. 31, 2013 | Dec. 31, 2012 | Jul. 31, 2010 | Jul. 31, 2010 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | |
acre | Gulf United Energy, Inc. [Member] | Gulf United Energy, Inc. [Member] | Hupecol Operating, LLC [Member] | Hupecol Operating, LLC [Member] | |||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Additional ownership interest acquired in CPO 4 Block (in hundredths) | ' | ' | 12.50% | ' | ' | ' | ' |
Gas and oil area in CPO 4 Block (in acres) | ' | ' | 345,452 | ' | ' | ' | ' |
Payment period under agreement | ' | ' | ' | '30 days | ' | ' | ' |
Share of past costs receivable under agreement (in hundredths) | ' | ' | ' | 12.50% | ' | ' | ' |
Percentage of acquisition costs receivable under agreement (in hundredths) | ' | ' | ' | 25.00% | ' | ' | ' |
Amount receivable under agreement in connection with seismic acquisition costs | ' | ' | ' | $3,951,370 | ' | ' | ' |
Bad debt expense | 86,507 | 3,951,370 | ' | ' | 3,951,370 | ' | ' |
Escrow receivables, percentage (in hundredths) | ' | 13.30% | ' | ' | ' | ' | 5.00% |
Amount receivable for entity's proportionate share of escrow funds | $0 | $3,436,305 | ' | ' | ' | $86,507 | ' |
ESCROW_RECEIVABLE_Details
ESCROW RECEIVABLE (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2010 | Jan. 31, 2014 |
Caracara Escrow [Member] | Tambaqui Escrow [Member] | Tambaqui Escrow [Member] | HDC LLC and HL LLC 15% Escrow [Member] | HDC LLC and HL LLC 15% Escrow [Member] | HDC LLC and HL LLC 5% Contingency [Member] | HDC LLC and HL LLC 5% Contingency [Member] | HC LLC 14.66% Escrow [Member] | HC LLC 5% Contingency [Member] | HC LLC 5% Contingency [Member] | HDC LLC and HL LLC Escrow [Member] | HDC LLC and HL LLC Escrow [Member] | |||
Subsequent Event [Member] | ||||||||||||||
Escrow receivables relating to oil and gas properties [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Escrow receivable - Current | $1,921,217 | $2,095,228 | $131,021 | $22,029 | $22,029 | $1,827,929 | $1,827,929 | $57,321 | $57,321 | $151,048 | $13,938 | $36,901 | ' | ' |
Escrow receivable - Noncurrent | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | ' | ' |
Total | 1,921,217 | 2,095,228 | 131,021 | 22,029 | 22,029 | 1,827,929 | 1,827,929 | 57,321 | 57,321 | 151,048 | 13,938 | 36,901 | ' | ' |
Escrow receivables, percentage (in hundredths) | ' | 13.30% | ' | ' | ' | 15.00% | 15.00% | 5.00% | 5.00% | 14.66% | 5.00% | 5.00% | ' | ' |
Proceeds from settlement of escrow account | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22,964 | ' | ' | 1,614,290 |
Amount receivable for entity's proportionate share of escrow funds | $0 | $3,436,305 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $7,069,810 | ' |
MARKETABLE_SECURITIES_AVAILABL1
MARKETABLE SECURITIES - AVAILABLE FOR SALE (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
MARKETABLE SECURITIES - AVAILABLE FOR SALE [Abstract] | ' | ' |
Payment for purchase of common stock in publicly traded company | $0 | $156,817 |
Loss on sale of marketable securities | $0 | $97,267 |
OIL_AND_GAS_PROPERTIES_Details
OIL AND GAS PROPERTIES (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Mar. 31, 2012 | Dec. 02, 2010 | Nov. 05, 2009 | |
Well | bbl | acre | ||||
Sale of La Cuerva and LLA 62 Blocks [Abstract] | ' | ' | ' | ' | ' | ' |
Oil and gas area in Llanos Basin in Colombia (in acres) | ' | ' | ' | 90,000 | ' | ' |
Sale price of oil gas property | ' | $75,000,000 | ' | ' | ' | ' |
Percentage of sale proceeds held in escrow account (in hundredths) | ' | 13.30% | ' | ' | ' | ' |
Percentage ownership interest in HC, LLC (in hundredths) | 1.60% | 1.60% | ' | ' | 37.50% | 25.00% |
Percentage of contingency holdback (in hundredths) | ' | 1.30% | ' | ' | ' | ' |
Estimated proved reserves associated with the La Cuerva and LLA 62 blocks | ' | ' | 94,619 | ' | ' | ' |
Percentage of estimated proved oil and gas reserve (in hundredths) | ' | ' | 82.00% | ' | ' | ' |
Computation of gain on sale of oil and gas properties [Abstract] | ' | ' | ' | ' | ' | ' |
Sales price | 1,224,393 | ' | ' | ' | ' | ' |
Add: Transfer of asset retirement and other obligations | 34,471 | ' | ' | ' | ' | ' |
Less: Transaction costs | -30,330 | ' | ' | ' | ' | ' |
Less: Prepaid deposits | -54,857 | ' | ' | ' | ' | ' |
Less: Carrying value of oil and gas properties, net | -858,558 | ' | ' | ' | ' | ' |
Net gain on sale | 315,119 | ' | ' | ' | ' | ' |
Impairments [Abstract] | ' | ' | ' | ' | ' | ' |
Number of wells | 3 | ' | ' | ' | ' | ' |
Impairment of oil and gas properties | 0 | 46,235,574 | ' | ' | ' | ' |
Unevaluated oil and gas properties not subject to amortization [Abstract] | ' | ' | ' | ' | ' | ' |
Leasehold acquisition costs | 1,366,223 | 2,987,855 | ' | ' | ' | ' |
Geological, geophysical, screening and evaluation costs | 2,435,819 | 2,821,442 | ' | ' | ' | ' |
Total | 3,802,042 | 5,809,297 | ' | ' | ' | ' |
North America [Member] | ' | ' | ' | ' | ' | ' |
Computation of gain on sale of oil and gas properties [Abstract] | ' | ' | ' | ' | ' | ' |
Add: Transfer of asset retirement and other obligations | 0 | 0 | ' | ' | ' | ' |
Unevaluated oil and gas properties not subject to amortization [Abstract] | ' | ' | ' | ' | ' | ' |
Leasehold acquisition costs | 1,234,888 | 972,005 | ' | ' | ' | ' |
Geological, geophysical, screening and evaluation costs | 777,618 | 880 | ' | ' | ' | ' |
Total | 2,012,506 | 972,885 | ' | ' | ' | ' |
South America [Member] | ' | ' | ' | ' | ' | ' |
Computation of gain on sale of oil and gas properties [Abstract] | ' | ' | ' | ' | ' | ' |
Add: Transfer of asset retirement and other obligations | 0 | -34,471 | ' | ' | ' | ' |
Unevaluated oil and gas properties not subject to amortization [Abstract] | ' | ' | ' | ' | ' | ' |
Leasehold acquisition costs | 131,335 | 2,015,850 | ' | ' | ' | ' |
Geological, geophysical, screening and evaluation costs | 1,658,201 | 2,820,562 | ' | ' | ' | ' |
Total | 1,789,536 | 4,836,412 | ' | ' | ' | ' |
Pro Forma [Member] | ' | ' | ' | ' | ' | ' |
Pro-Forma Information [Abstract] | ' | ' | ' | ' | ' | ' |
Oil and gas revenue | ' | 148,163 | ' | ' | ' | ' |
Loss from operations | ' | -56,566,181 | ' | ' | ' | ' |
Net loss | ' | ($56,847,211) | ' | ' | ' | ' |
Basic and diluted loss per common share (in dollars per share) | ' | ($1.47) | ' | ' | ' | ' |
ASSET_RETIREMENT_OBLIGATION_De
ASSET RETIREMENT OBLIGATION (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
Changes in our asset retirement liability [Roll Forward] | ' | ' |
Accretion expense | $552 | $924 |
Liabilities settled-assets sold | 34,471 | ' |
North America [Member] | ' | ' |
Changes in our asset retirement liability [Roll Forward] | ' | ' |
ARO liability at January 1 | 7,872 | 7,320 |
Accretion expense | 552 | 552 |
Liabilities incurred from drilling | 0 | 0 |
Liabilities settled-assets sold | 0 | 0 |
Changes in estimates | 0 | 0 |
ARO liability at December 31 | 8,424 | 7,872 |
South America [Member] | ' | ' |
Changes in our asset retirement liability [Roll Forward] | ' | ' |
ARO liability at January 1 | 0 | 34,099 |
Accretion expense | 0 | 372 |
Liabilities incurred from drilling | 0 | 0 |
Liabilities settled-assets sold | 0 | -34,471 |
Changes in estimates | 0 | 0 |
ARO liability at December 31 | $0 | $0 |
COMMON_STOCK_Details
COMMON STOCK (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
Class of Stock [Line Items] | ' | ' |
Gross proceeds from issuance of common stock units | $0 | $23,144,000 |
May 2012 Offering [Member] | ' | ' |
Class of Stock [Line Items] | ' | ' |
Gross proceeds from issuance of common stock units | 13,140,000 | ' |
Agent fees and estimated offering expenses | 527,000 | ' |
Units at purchase price (in dollars per share) | $2.12 | ' |
Number of shares called by warrants (in shares) | 6,200,000 | ' |
Exercise price (in dollars per share) | $2.68 | ' |
Exercise price of warrants expressed as percentage of closing price (in hundredths) | 120.00% | ' |
October 2012 Offering [Member] | ' | ' |
Class of Stock [Line Items] | ' | ' |
Gross proceeds from issuance of common stock units | 10,000,000 | ' |
Agent fees and estimated offering expenses | $828,000 | ' |
Units at purchase price (in dollars per share) | $0.68 | ' |
Number of shares called by warrants (in shares) | 7,407,407 | ' |
Warrant [Member] | May 2012 Offering [Member] | ' | ' |
Class of Stock [Line Items] | ' | ' |
Number of warrants to purchase one common share (in shares) | 1 | ' |
Warrant Class A [Member] | ' | ' |
Class of Stock [Line Items] | ' | ' |
Term of warrant | '6 months | ' |
Number of shares called by each warrant (in shares) | 1.5 | ' |
Warrant Class A [Member] | October 2012 Offering [Member] | ' | ' |
Class of Stock [Line Items] | ' | ' |
Number of warrants to purchase one common share (in shares) | 1 | ' |
Exercise price (in dollars per share) | $0.81 | ' |
Warrant Class B [Member] | ' | ' |
Class of Stock [Line Items] | ' | ' |
Term of warrant | '3 years | ' |
Number of shares called by each warrant (in shares) | 1.5 | ' |
Warrant Class B [Member] | October 2012 Offering [Member] | ' | ' |
Class of Stock [Line Items] | ' | ' |
Number of warrants to purchase one common share (in shares) | 1 | ' |
Exercise price (in dollars per share) | $0.90 | ' |
Common Stock [Member] | May 2012 Offering [Member] | ' | ' |
Class of Stock [Line Items] | ' | ' |
Number of units sold (in shares) | 6,200,000 | ' |
Number of shares per unit of stock sold (in shares) | 1 | ' |
Common Stock [Member] | October 2012 Offering [Member] | ' | ' |
Class of Stock [Line Items] | ' | ' |
Number of units sold (in shares) | 14,814,815 | ' |
Number of shares per unit of stock sold (in shares) | 1 | ' |
STOCKBASED_COMPENSATION_Detail
STOCK-BASED COMPENSATION (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | |
Options granted (in shares) | 2,215,525 | [1] | 609,475 | ' |
Exercise price of options granted (in dollars per share) | $0.86 | [1] | $1.63 | ' |
Stock compensation amortized expense | $1,513,779 | $2,023,175 | ' | |
Options [Roll Forward] | ' | ' | ' | |
Outstanding at beginning of the period (in shares) | 2,443,057 | 1,833,582 | ' | |
Granted (in shares) | 2,215,525 | [1] | 609,475 | ' |
Exercised (in shares) | 0 | 0 | ' | |
Forfeited (in shares) | -2,065,750 | 0 | ' | |
Outstanding at end of the period (in shares) | 2,592,832 | 2,443,057 | ' | |
Weighted-Average Exercise Price [Roll Forward] | ' | ' | ' | |
Outstanding at beginning of the period (in dollars per share) | $5.68 | $7.02 | ' | |
Granted (in dollars per share) | $0.86 | [1] | $1.63 | ' |
Exercised (in dollars per share) | $0 | $0 | ' | |
Forfeited (in dollars per share) | $2.53 | $0 | ' | |
Outstanding at end of the period (in dollars per share) | $4.07 | $5.68 | ' | |
Weighted Average Remaining Contractual Term [Abstract] | ' | ' | ' | |
Weighted average remaining contractual term of the outstanding options | '6 years 11 months 19 days | ' | ' | |
Aggregate Intrinsic Value [Abstract] | ' | ' | ' | |
Outstanding at end of the period | 0 | ' | ' | |
Options granted subject to shareholder approval (in shares) | ' | 915,525 | ' | |
Weighted average remaining contractual term of the outstanding options | '6 years 11 months 19 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) | 1,200,000 | 1,200,000 | ' | |
Stock option vesting percentage (in hundredths) | 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) | $0.31 | $1.65 | ' | |
Total value of options granted | 294,085 | 354,098 | ' | |
Risk free interest rate (in hundredths) | 1.26% | 0.35% | ' | |
Stock option expected life | '5 years 7 months 6 days | '2 years 9 months 29 days | ' | |
Expected stock volatility (in hundredths) | 105.00% | 84.60% | ' | |
Expected dividend yield (in hundredths) | 0.00% | 1.21% | ' | |
Options [Roll Forward] | ' | ' | ' | |
Granted (in shares) | 1,200,000 | 1,200,000 | ' | |
Weighted-Average Exercise Price [Roll Forward] | ' | ' | ' | |
Granted (in dollars per share) | $0.31 | $1.65 | ' | |
Aggregate Intrinsic Value [Abstract] | ' | ' | ' | |
Option exercisable (in shares) | ' | 429,000 | ' | |
Vesting period of restricted stock award granted to officers | '10 years | '10 years | ' | |
New non-employee director [Member] | ' | ' | ' | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | |
Options granted (in shares) | ' | 25,000 | ' | |
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) | ' | $1.18 | ' | |
Total value of options granted | ' | 19,375 | ' | |
Risk free interest rate (in hundredths) | ' | 0.82% | ' | |
Stock option expected life | ' | '5 years 10 months 1 day | ' | |
Expected stock volatility (in hundredths) | ' | 91.70% | ' | |
Expected dividend yield (in hundredths) | ' | 1.70% | ' | |
Options [Roll Forward] | ' | ' | ' | |
Granted (in shares) | ' | 25,000 | ' | |
Weighted-Average Exercise Price [Roll Forward] | ' | ' | ' | |
Granted (in dollars per share) | ' | $1.18 | ' | |
Aggregate Intrinsic Value [Abstract] | ' | ' | ' | |
Vesting period of restricted stock award granted to officers | ' | '10 years | ' | |
Non-employee directors [Member] | ' | ' | ' | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | |
Options granted (in shares) | 100,000 | 325,000 | ' | |
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 | 325,000 | ' | |
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 | ' | ' | |
Previous non employee director [Member] | ' | ' | ' | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | |
Options granted (in shares) | ' | 300,000 | ' | |
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) | ' | $1.65 | ' | |
Total value of options granted | ' | 128,328 | ' | |
Risk free interest rate (in hundredths) | ' | 0.35% | ' | |
Stock option expected life | ' | '2 years 9 months 29 days | ' | |
Expected stock volatility (in hundredths) | ' | 84.60% | ' | |
Expected dividend yield (in hundredths) | ' | 1.21% | ' | |
Options [Roll Forward] | ' | ' | ' | |
Granted (in shares) | ' | 300,000 | ' | |
Weighted-Average Exercise Price [Roll Forward] | ' | ' | ' | |
Granted (in dollars per share) | ' | $1.65 | ' | |
Aggregate Intrinsic Value [Abstract] | ' | ' | ' | |
Option exercisable (in shares) | ' | 155,475 | ' | |
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 | ' | ' | |
Total value of options granted | 164,377 | ' | ' | |
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% | ' | ' | |
Amendments to 2008 Equity Incentive Plan [Member] | Employee [Member] | ' | ' | ' | |
Aggregate Intrinsic Value [Abstract] | ' | ' | ' | |
Option exercisable (in shares) | ' | 771,000 | ' | |
Amendments to 2008 Equity Incentive Plan [Member] | Previous non employee director [Member] | ' | ' | ' | |
Aggregate Intrinsic Value [Abstract] | ' | ' | ' | |
Option exercisable (in shares) | ' | 144,525 | ' | |
Options [Member] | ' | ' | ' | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | |
Stock compensation amortized expense | 1,513,779 | 1,775,753 | ' | |
Weighted Average Remaining Contractual Term [Abstract] | ' | ' | ' | |
Weighted average remaining contractual term of the outstanding options | '6 years 11 months 19 days | ' | ' | |
Aggregate Intrinsic Value [Abstract] | ' | ' | ' | |
Unvested options outstanding (in shares) | 530,000 | ' | ' | |
Weighted average period for recognition of compensation expense | '0 years 5 months 12 days | ' | ' | |
Weighted average remaining contractual term of the outstanding options | '6 years 11 months 19 days | ' | ' | |
Weighted average remaining contractual term of the exercisable options | '7 years 2 months 26 days | ' | ' | |
Unrecognized stock-based compensation expense related to non-vested stock options | 353,555 | ' | ' | |
Shares available for issuance (in shares) | 3,907,168 | ' | ' | |
Restricted Stock [Member] | ' | ' | ' | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | |
Stock compensation amortized expense | 157,140 | 247,422 | ' | |
Aggregate Intrinsic Value [Abstract] | ' | ' | ' | |
Weighted average period for recognition of compensation expense | '0 years 5 months 12 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 | $37,001 | ' | ' | |
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 | |
[1] | Includes 915,525 options granted in 2012, the exercise of which was subject to shareholder approval of an amendment to the Companybs 2008 Equity Incentive Plan to increase the shares reserved for issuance there under, which approval was obtained during 2013. |
STOCKBASED_COMPENSATION_Alloca
STOCK-BASED COMPENSATION, Allocation of Recognized Period Costs (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
Share-based compensation expense [Abstract] | ' | ' |
Share-based compensation expense included in general and administrative expense | $1,513,779 | $2,023,175 |
General and administrative expense [Member] | ' | ' |
Share-based compensation expense [Abstract] | ' | ' |
Share-based compensation expense included in general and administrative expense | $1,513,779 | $2,023,175 |
Earnings per share effect of share based compensation expense (in dollars per share) | ($0.03) | ($0.05) |
TAXES_Details
TAXES (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
Reconciliation of the statutory federal income tax [Abstract] | ' | ' |
Income (loss) before income taxes | ($3,185,755) | ($56,540,526) |
Income tax expense (benefit) computed at statutory rates | -1,115,014 | -19,223,779 |
Permanent differences, nondeductible expenses | -1,177,769 | 282,547 |
Current Colombian tax expense | 8,880 | 216,923 |
Increase (decrease) in valuation allowance | -902,498 | 22,026,880 |
Valuation allowance (decrease) related to carryback | 0 | -3,345,683 |
Change in tax rate | -79,409 | 0 |
Return to accrual items | 127,913 | 0 |
Foreign tax credit | 3,649,259 | 0 |
Other adjustment | -21,156 | 260,035 |
NOL adjustment | -502,480 | 0 |
State (net of federal benefit) | 0 | 0 |
Tax provision (benefit) | -12,274 | 216,923 |
Total Provision [Abstract] | ' | ' |
Current Federal | 0 | -3,195,583 |
Current State | 0 | 0 |
Deferred Federal | 0 | 3,195,583 |
Deferred State | ' | 0 |
Permanent True-up | -21,154 | 0 |
Foreign | 8,880 | 216,923 |
Tax provision (benefit) | -12,274 | 216,923 |
Federal tax loss carry forward | 48,582,039 | ' |
Foreign tax credit carry forward | 484,697 | ' |
Non-Current Deferred tax assets [Abstract] | ' | ' |
Net operating loss carry forwards | 17,003,714 | 12,964,068 |
Foreign tax credit carry forwards | 484,697 | 4,133,956 |
Deferred state tax | 23,277 | 66,505 |
Stock compensation | 3,618,643 | 3,000,568 |
Book in excess of tax depreciation, depletion, and capitalization methods on oil and gas properties | -2,151,329 | -271,419 |
Other | -83,560 | -95,738 |
Colombia future tax obligations | 0 | 0 |
Total Non-Current Deferred tax assets | 18,895,442 | 19,797,940 |
Valuation Allowance | -18,895,442 | -19,797,940 |
Net deferred tax asset | 0 | 0 |
Foreign Income Taxes [Member] | ' | ' |
Income Tax Contingency [Line Items] | ' | ' |
Colombia's current income tax rate (in hundredths) | 33.00% | ' |
Colombian tax liability | ' | $1,689,039 |
RELATED_PARTIES_Details
RELATED PARTIES (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
John F. Terwilliger [Member] | ' | ' |
Related Party Transaction [Line Items] | ' | ' |
Overriding royalty interests owned (in hundredths) | 1.50% | ' |
Royalty payments | $20,305 | $16,594 |
Orrie L. Tawes [Member] | ' | ' |
Related Party Transaction [Line Items] | ' | ' |
Overriding royalty interests owned (in hundredths) | 1.50% | ' |
Royalty payments | $20,305 | $16,594 |
COMMITMENTS_AND_CONTINGENCIES_1
COMMITMENTS AND CONTINGENCIES (Details) (USD $) | 1 Months Ended | 12 Months Ended | |||||
Aug. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2010 | Dec. 31, 2009 | Dec. 02, 2010 | Nov. 05, 2009 | |
Claim | |||||||
Lease Commitment [Abstract] | ' | ' | ' | ' | ' | ' | ' |
Operating lease agreement expiration date | ' | 31-May-17 | ' | ' | ' | ' | ' |
Future payments under lease agreement [Abstract] | ' | ' | ' | ' | ' | ' | ' |
2014 | ' | $91,432 | ' | ' | ' | ' | ' |
2015 | ' | 93,793 | ' | ' | ' | ' | ' |
2016 | ' | 96,162 | ' | ' | ' | ' | ' |
2017 | ' | 40,479 | ' | ' | ' | ' | ' |
Total | ' | 321,866 | ' | ' | ' | ' | ' |
Total rental expense | ' | 97,220 | 90,194 | ' | ' | ' | ' |
Standby Letter of Credit - CPO 4 Block [Abstract] | ' | ' | ' | ' | ' | ' | ' |
Letter of credit issued by JP Morgan to Banco de Bogota | ' | ' | ' | ' | ' | 3,056,250 | 2,037,500 |
Percentage of ownership interest acquired in CPO 4 Block (in hundredths) | ' | 1.60% | 1.60% | ' | ' | 37.50% | 25.00% |
Deposit with J.P Morgan Chase | ' | ' | ' | ' | ' | 3,056,250 | 2,037,500 |
Standby letter of credit fee, percentage (in hundredths) | ' | ' | ' | 1.00% | 1.00% | ' | ' |
Standby letter of credit fee | ' | ' | ' | 32,070 | 20,375 | ' | ' |
Legal Contingencies [Abstract] | ' | ' | ' | ' | ' | ' | ' |
Settlement of claim | ' | ' | $490,850 | ' | ' | ' | ' |
New claims filed number | ' | ' | 2 | ' | ' | ' | ' |
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 | ' | ' | ' | ' | ' | ' |
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% | ' | ' | ' | ' | ' | ' |
SUBSEQUENT_EVENTS_Details
SUBSEQUENT EVENTS (Details) (Subsequent Events [Member], HDC LLC and HL LLC Escrow [Member], USD $) | 1 Months Ended |
Jan. 31, 2014 | |
Subsequent Events [Member] | HDC LLC and HL LLC Escrow [Member] | ' |
Subsequent Event [Line Items] | ' |
Proceeds from settlement of escrow account | $1,614,290 |
Escrow receivable uncollected balance | $306,927 |
GEOGRAPHICAL_INFORMATION_Detai
GEOGRAPHICAL INFORMATION (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||||||||
Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | |
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 | $142,573 | $170,311 | $19,223 | $15,032 | $23,740 | $30,752 | $36,347 | $320,510 | $347,139 | $411,349 |
Long Lived Assets, Net | 3,862,804 | ' | ' | ' | 5,886,969 | ' | ' | ' | 3,862,804 | 5,886,969 |
North America [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revenues and long-lived assets attributable to each geographical area [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating revenue | ' | ' | ' | ' | ' | ' | ' | ' | 347,139 | 148,163 |
Long Lived Assets, Net | 2,073,268 | ' | ' | ' | 1,050,557 | ' | ' | ' | 2,073,268 | 1,050,557 |
South America [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revenues and long-lived assets attributable to each geographical area [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating revenue | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 263,186 |
Long Lived Assets, Net | $1,789,536 | ' | ' | ' | $4,836,412 | ' | ' | ' | $1,789,536 | $4,836,412 |
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, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 02, 2010 | Nov. 05, 2009 | |
bbl | bbl | bbl | bbl | bbl | |||||||||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating revenue | $142,573 | $170,311 | $19,223 | $15,032 | $23,740 | $30,752 | $36,347 | $320,510 | $347,139 | $411,349 | ' | ' | ' |
Production Cost | ' | ' | ' | ' | ' | ' | ' | ' | 81,774 | 195,381 | ' | ' | ' |
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unproved properties not being amortized | 3,802,042 | ' | ' | ' | 5,809,297 | ' | ' | ' | 3,802,042 | 5,809,297 | ' | ' | ' |
Proved properties being amortized | 50,320,591 | ' | ' | ' | ' | ' | ' | ' | 50,320,591 | ' | ' | ' | ' |
Accumulated depreciation, depletion, amortization and impairment | -50,274,501 | ' | ' | ' | ' | ' | ' | ' | -50,274,501 | ' | ' | ' | ' |
Net capitalized costs | 3,848,132 | ' | ' | ' | ' | ' | ' | ' | 3,848,132 | ' | ' | ' | ' |
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] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proved developed reserves | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 94,619 | ' | ' |
Total proved undeveloped reserve | 0 | ' | ' | ' | 0 | ' | ' | ' | 0 | 0 | ' | ' | ' |
Percentage ownership interest in La Cuerva and LLA 62 blocks in Colombia (in hundredths) | 1.60% | ' | ' | ' | 1.60% | ' | ' | ' | 1.60% | 1.60% | ' | 37.50% | 25.00% |
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 | ' | ' | ' | ' | ' | ' | ' | ' | 1,306,020 | 921,070 | ' | ' | ' |
Future production cost | ' | ' | ' | ' | ' | ' | ' | ' | -357,970 | -392,430 | ' | ' | ' |
Future development cost | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Future income tax | ' | ' | ' | ' | ' | ' | ' | ' | -14,525 | 0 | ' | ' | ' |
Future net cash flows | ' | ' | ' | ' | ' | ' | ' | ' | 933,525 | 528,640 | ' | ' | ' |
10% annual discount for timing of cash flow | ' | ' | ' | ' | ' | ' | ' | ' | -214,490 | -230,570 | ' | ' | ' |
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves | ' | ' | ' | ' | ' | ' | ' | ' | 719,035 | 298,070 | ' | ' | ' |
Changes in standardized measure [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Change due to current year operations Sales, net of production costs | ' | ' | ' | ' | ' | ' | ' | ' | -265,365 | -215,968 | ' | ' | ' |
Change due to revisions in standardized variables [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | -14,525 | -12,911 | ' | ' | ' |
Accretion of discount | ' | ' | ' | ' | ' | ' | ' | ' | 29,807 | 49,238 | ' | ' | ' |
Net change in sales and transfer price, net of production costs | ' | ' | ' | ' | ' | ' | ' | ' | 48,603 | -62,724 | ' | ' | ' |
Previously estimated development costs incurred during the period | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Changes in estimated future development costs | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Revision and others | ' | ' | ' | ' | ' | ' | ' | ' | 30,997 | 35,781 | ' | ' | ' |
Discoveries | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Sales of reserves in place | ' | ' | ' | ' | ' | ' | ' | ' | 0 | -2,505,431 | ' | ' | ' |
Changes in production rates and other | ' | ' | ' | ' | ' | ' | ' | ' | 591,447 | -42,954 | ' | ' | ' |
Net | ' | ' | ' | ' | ' | ' | ' | ' | 420,965 | -2,754,969 | ' | ' | ' |
Beginning of year | ' | ' | ' | 298,070 | ' | ' | ' | 3,053,039 | 298,070 | 3,053,039 | ' | ' | ' |
End of year | 719,035 | ' | ' | ' | 298,070 | ' | ' | ' | 719,035 | 298,070 | ' | ' | ' |
Gas [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Total proved reserves [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Balance at beginning of the period | ' | ' | ' | 85,280 | ' | ' | ' | 86,800 | 85,280 | 86,800 | ' | ' | ' |
Extensions and discoveries | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' |
Purchase of minerals in place | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' |
Revisions of prior estimates | ' | ' | ' | ' | ' | ' | ' | ' | -39,011 | 10,546 | ' | ' | ' |
Sales of minerals in place | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' |
Production | ' | ' | ' | ' | ' | ' | ' | ' | -9,459 | -12,066 | ' | ' | ' |
Balance at end of the period | 36,810 | ' | ' | ' | 85,280 | ' | ' | ' | 36,810 | 85,280 | ' | ' | ' |
Proved developed reserves | 36,810 | ' | ' | ' | 85,280 | ' | ' | ' | 36,810 | 85,280 | ' | ' | ' |
Proved undeveloped reserves | 0 | ' | ' | ' | 0 | ' | ' | ' | 0 | 0 | ' | ' | ' |
Oil [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Total proved reserves [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Balance at beginning of the period | ' | ' | ' | 6,170,000,000 | ' | ' | ' | 101,159,000,000 | 6,170,000,000 | 101,159,000,000 | ' | ' | ' |
Extensions and discoveries | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' |
Purchase of minerals in place | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' |
Revisions of prior estimates | ' | ' | ' | ' | ' | ' | ' | ' | 7,943,000,000 | 915,000,000 | ' | ' | ' |
Sales of minerals in place | ' | ' | ' | ' | ' | ' | ' | ' | ' | -93,117,000,000 | ' | ' | ' |
Production | ' | ' | ' | ' | ' | ' | ' | ' | -2,963,000,000 | -2,787,000,000 | ' | ' | ' |
Balance at end of the period | 11,150,000,000 | ' | ' | ' | 6,170,000,000 | ' | ' | ' | 11,150,000,000 | 6,170,000,000 | ' | ' | ' |
Proved developed reserves | 11,150,000,000 | ' | ' | ' | 6,170,000,000 | ' | ' | ' | 11,150,000,000 | 6,170,000,000 | ' | ' | ' |
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 | ' | ' | ' | ' | ' | ' | ' | ' | 347,139 | 148,163 | ' | ' | ' |
Production Cost | ' | ' | ' | ' | ' | ' | ' | ' | 81,774 | 76,593 | ' | ' | ' |
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unproved properties not being amortized | 2,012,506 | ' | ' | ' | 972,885 | ' | ' | ' | 2,012,506 | 972,885 | ' | ' | ' |
United States [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unproved properties not being amortized | 2,012,506 | ' | ' | ' | ' | ' | ' | ' | 2,012,506 | ' | ' | ' | ' |
Proved properties being amortized | 865,889 | ' | ' | ' | ' | ' | ' | ' | 865,889 | ' | ' | ' | ' |
Accumulated depreciation, depletion, amortization and impairment | -819,799 | ' | ' | ' | ' | ' | ' | ' | -819,799 | ' | ' | ' | ' |
Net capitalized costs | 2,058,596 | ' | ' | ' | ' | ' | ' | ' | 2,058,596 | ' | ' | ' | ' |
Amortization Expense Per Equivalent Unit of Production or Per Dollar of Gross Revenue [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amortization rate per unit (in dollars per share) | $2.67 | ' | ' | ' | ' | ' | ' | ' | $2.67 | ' | ' | ' | ' |
Property acquisition costs [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proved | ' | ' | ' | ' | ' | ' | ' | ' | 8,640 | 0 | ' | ' | ' |
Unproved | ' | ' | ' | ' | ' | ' | ' | ' | 262,883 | 110,836 | ' | ' | ' |
Exploration costs | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Development costs | ' | ' | ' | ' | ' | ' | ' | ' | 776,142 | 6,488 | ' | ' | ' |
Total costs incurred | ' | ' | ' | ' | ' | ' | ' | ' | 1,047,665 | 117,324 | ' | ' | ' |
Standardized measure of discounted future net cash flows [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Future cash inflows from sales of oil and gas | ' | ' | ' | ' | ' | ' | ' | ' | 1,306,020 | 921,070 | ' | ' | ' |
Future production cost | ' | ' | ' | ' | ' | ' | ' | ' | -357,970 | -392,430 | ' | ' | ' |
Future development cost | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Future income tax | ' | ' | ' | ' | ' | ' | ' | ' | -14,525 | 0 | ' | ' | ' |
Future net cash flows | ' | ' | ' | ' | ' | ' | ' | ' | 933,525 | 528,640 | ' | ' | ' |
10% annual discount for timing of cash flow | ' | ' | ' | ' | ' | ' | ' | ' | -214,490 | -230,570 | ' | ' | ' |
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves | ' | ' | ' | ' | ' | ' | ' | ' | 719,035 | 298,070 | ' | ' | ' |
Changes in standardized measure [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Change due to current year operations Sales, net of production costs | ' | ' | ' | ' | ' | ' | ' | ' | -265,365 | -71,570 | ' | ' | ' |
Change due to revisions in standardized variables [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | -14,525 | -12,911 | ' | ' | ' |
Accretion of discount | ' | ' | ' | ' | ' | ' | ' | ' | 29,807 | 49,238 | ' | ' | ' |
Net change in sales and transfer price, net of production costs | ' | ' | ' | ' | ' | ' | ' | ' | 48,603 | -62,724 | ' | ' | ' |
Previously estimated development costs incurred during the period | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Changes in estimated future development costs | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Revision and others | ' | ' | ' | ' | ' | ' | ' | ' | 30,997 | 35,781 | ' | ' | ' |
Discoveries | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Sales of reserves in place | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Changes in production rates and other | ' | ' | ' | ' | ' | ' | ' | ' | 591,447 | -42,954 | ' | ' | ' |
Net | ' | ' | ' | ' | ' | ' | ' | ' | 420,965 | -105,140 | ' | ' | ' |
Beginning of year | ' | ' | ' | 298,070 | ' | ' | ' | 403,210 | 298,070 | 403,210 | ' | ' | ' |
End of year | 719,035 | ' | ' | ' | 298,070 | ' | ' | ' | 719,035 | 298,070 | ' | ' | ' |
United States [Member] | Gas [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Total proved reserves [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Balance at beginning of the period | ' | ' | ' | 85,280 | ' | ' | ' | 86,800 | 85,280 | 86,800 | ' | ' | ' |
Extensions and discoveries | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' |
Purchase of minerals in place | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' |
Revisions of prior estimates | ' | ' | ' | ' | ' | ' | ' | ' | -39,011 | 10,546 | ' | ' | ' |
Sales of minerals in place | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' |
Production | ' | ' | ' | ' | ' | ' | ' | ' | -9,459 | -12,066 | ' | ' | ' |
Balance at end of the period | 36,810 | ' | ' | ' | 85,280 | ' | ' | ' | 36,810 | 85,280 | ' | ' | ' |
Proved developed reserves | 36,810 | ' | ' | ' | 85,280 | ' | ' | ' | 36,810 | 85,280 | ' | ' | ' |
Proved undeveloped reserves | 0 | ' | ' | ' | 0 | ' | ' | ' | 0 | 0 | ' | ' | ' |
United States [Member] | Oil [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Total proved reserves [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Balance at beginning of the period | ' | ' | ' | 6,170,000,000 | ' | ' | ' | 6,540,000,000 | 6,170,000,000 | 6,540,000,000 | ' | ' | ' |
Extensions and discoveries | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' |
Purchase of minerals in place | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' |
Revisions of prior estimates | ' | ' | ' | ' | ' | ' | ' | ' | 7,943,000,000 | 662,000,000 | ' | ' | ' |
Sales of minerals in place | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' |
Production | ' | ' | ' | ' | ' | ' | ' | ' | -2,963,000,000 | -1,032,000,000 | ' | ' | ' |
Balance at end of the period | 11,150,000,000 | ' | ' | ' | 6,170,000,000 | ' | ' | ' | 11,150,000,000 | 6,170,000,000 | ' | ' | ' |
Proved developed reserves | 11,150,000,000 | ' | ' | ' | 6,170,000,000 | ' | ' | ' | 11,150,000,000 | 6,170,000,000 | ' | ' | ' |
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 | 263,186 | ' | ' | ' |
Production Cost | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 118,788 | ' | ' | ' |
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unproved properties not being amortized | 1,789,536 | ' | ' | ' | 4,836,412 | ' | ' | ' | 1,789,536 | 4,836,412 | ' | ' | ' |
Proved properties being amortized | 49,454,702 | ' | ' | ' | ' | ' | ' | ' | 49,454,702 | ' | ' | ' | ' |
Accumulated depreciation, depletion, amortization and impairment | -49,454,702 | ' | ' | ' | ' | ' | ' | ' | -49,454,702 | ' | ' | ' | ' |
Net capitalized costs | 1,789,536 | ' | ' | ' | ' | ' | ' | ' | 1,789,536 | ' | ' | ' | ' |
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 | ' | ' | ' | ' | ' | ' | ' | ' | 84,081 | 0 | ' | ' | ' |
Unproved | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Exploration costs | ' | ' | ' | ' | ' | ' | ' | ' | 88,171 | 25,915,741 | ' | ' | ' |
Development costs | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Total costs incurred | ' | ' | ' | ' | ' | ' | ' | ' | 172,252 | 25,915,741 | ' | ' | ' |
Standardized measure of discounted future net cash flows [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Future cash inflows from sales of oil and gas | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Future production cost | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Future development cost | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Future income tax | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Future net cash flows | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' |
10% annual discount for timing of cash flow | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Changes in standardized measure [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Change due to current year operations Sales, net of production costs | ' | ' | ' | ' | ' | ' | ' | ' | 0 | -144,398 | ' | ' | ' |
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 | -2,505,431 | ' | ' | ' |
Changes in production rates and other | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Net | ' | ' | ' | ' | ' | ' | ' | ' | 0 | -2,649,829 | ' | ' | ' |
Beginning of year | ' | ' | ' | 0 | ' | ' | ' | 2,649,829 | 0 | 2,649,829 | ' | ' | ' |
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 | ' | ' | ' |
Purchase of minerals in place | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' |
Revisions of prior estimates | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' |
Sales of minerals in place | ' | ' | ' | ' | ' | ' | ' | ' | 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 | ' | ' | ' | 94,619,000,000 | 0 | 94,619,000,000 | ' | ' | ' |
Extensions and discoveries | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' |
Purchase of minerals in place | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' |
Revisions of prior estimates | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 253,000,000 | ' | ' | ' |
Sales of minerals in place | ' | ' | ' | ' | ' | ' | ' | ' | 0 | -93,117,000,000 | ' | ' | ' |
Production | ' | ' | ' | ' | ' | ' | ' | ' | 0 | -1,755,000,000 | ' | ' | ' |
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, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | |
Summarized quarterly financial information [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating revenue | $142,573 | $170,311 | $19,223 | $15,032 | $23,740 | $30,752 | $36,347 | $320,510 | $347,139 | $411,349 |
Income (loss) from operations | -610,247 | -526,248 | -1,296,227 | -785,191 | -11,269,214 | -5,910,504 | -18,654,298 | -20,633,191 | 3,217,913 | 56,467,207 |
Net income (loss) | ($574,575) | ($526,464) | ($1,266,267) | ($806,175) | ($8,131,562) | ($5,935,713) | ($22,022,079) | ($20,668,095) | ($3,173,481) | ($56,757,449) |
Earnings (loss) per common share - basic (in dollars per share) | ($0.01) | ($0.01) | ($0.02) | ($0.02) | ($0.16) | ($0.16) | ($0.63) | ($0.66) | ' | ' |
Earnings (loss) per common share - diluted (in dollars per share) | ($0.01) | ($0.01) | ($0.02) | ($0.02) | ($0.16) | ($0.16) | ($0.63) | ($0.66) | ' | ' |