Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2015 | Aug. 10, 2015 | |
Document And Entity Information | ||
Entity Registrant Name | Black Ridge Oil & Gas, Inc. | |
Entity Central Index Key | 1,490,161 | |
Document Type | 10-Q | |
Document Period End Date | Jun. 30, 2015 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Is Entity a Well-known Seasoned Issuer? | No | |
Is Entity a Voluntary Filer? | No | |
Is Entity's Reporting Status Current? | Yes | |
Entity Filer Category | Smaller Reporting Company | |
Entity Common Stock, Shares Outstanding | 47,979,990 | |
Document Fiscal Period Focus | Q2 | |
Document Fiscal Year Focus | 2,015 |
CONDENSED BALANCE SHEETS
CONDENSED BALANCE SHEETS - USD ($) | Jun. 30, 2015 | Dec. 31, 2014 |
Current assets: | ||
Cash and cash equivalents | $ 214,583 | $ 94,682 |
Derivative instruments, current | 3,007,135 | 3,571,803 |
Accounts receivable | 4,091,371 | 5,740,171 |
Prepaid expenses | 46,351 | 41,387 |
Total current assets | 7,359,440 | 9,448,043 |
Oil and natural gas properties, full cost method of accounting: | ||
Proved properties | 124,205,553 | 112,418,105 |
Unproved properties | 1,258,138 | 591,121 |
Other property and equipment | 139,004 | 139,004 |
Total property and equipment | 125,602,695 | 113,148,230 |
Less, accumulated depreciation, amortization, depletion and allowance for impairment | (46,117,576) | (18,902,524) |
Total property and equipment, net | 79,485,119 | 94,245,706 |
Derivative instruments, long-term | 2,983,784 | 4,007,942 |
Debt issuance costs, net | 510,239 | 701,019 |
Total assets | 90,338,582 | 108,402,710 |
Current liabilities: | ||
Accounts payable | 10,166,181 | 10,291,262 |
Accrued expenses | 91,155 | 57,435 |
Total current liabilities | 10,257,336 | 10,348,697 |
Asset retirement obligations | 344,360 | 286,804 |
Revolving credit facilities and long term debt, net of discounts of $1,665,862 and $2,072,483, respectively | 60,026,143 | 51,834,603 |
Deferred tax liability | 0 | 6,593,040 |
Total liabilities | $ 70,627,839 | $ 69,063,144 |
Commitments and contingencies (See note 15) | ||
Stockholders' equity: | ||
Preferred stock, $0.001 par value, 20,000,000 shares authorized, no shares issued and outstanding | $ 0 | $ 0 |
Common stock, $0.001 par value, 500,000,000 shares authorized, 47,979,990 shares issued and outstanding | 47,980 | 47,980 |
Additional paid-in capital | 33,965,465 | 33,651,714 |
Retained earnings | (14,302,702) | 5,639,872 |
Total stockholders' equity | 19,710,743 | 39,339,566 |
Total liabilities and stockholders' equity | $ 90,338,582 | $ 108,402,710 |
CONDENSED BALANCE SHEETS (Paren
CONDENSED BALANCE SHEETS (Parenthetical) - USD ($) | Jun. 30, 2015 | Dec. 31, 2014 |
Stockholders' equity: | ||
Discounts on long term debt | $ 1,665,862 | $ 2,072,483 |
Preferred stock, par value (in Dollars per share) | $ 0.001 | $ 0.001 |
Preferred stock, shares authorized | 20,000,000 | 20,000,000 |
Preferred stock, shares issued | 0 | 0 |
Preferred stock, shares outstanding | 0 | 0 |
Common stock, par value (in Dollars per share) | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 500,000,000 | 500,000,000 |
Common stock, shares issued | 47,979,990 | 47,979,990 |
Common stock, shares outstanding | 47,979,990 | 47,979,990 |
CONDENSED STATEMENTS OF OPERATI
CONDENSED STATEMENTS OF OPERATIONS - USD ($) | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Income Statement [Abstract] | ||||
Oil and gas sales | $ 5,050,080 | $ 5,553,997 | $ 7,936,536 | $ 9,584,417 |
Gain (loss) on settled derivatives | 847,198 | (262,719) | 1,980,619 | (378,882) |
Loss on the mark-to-market of derivatives | (1,956,155) | (881,124) | (1,588,826) | (1,095,159) |
Total revenues | 3,941,123 | 4,410,154 | 8,328,329 | 8,110,376 |
Operating expenses: | ||||
Production expenses | 1,153,663 | 595,591 | 2,143,520 | 1,103,054 |
Production taxes | 555,152 | 591,525 | 841,344 | 996,832 |
General and administrative | 730,445 | 634,109 | 1,540,453 | 1,404,882 |
Depletion of oil and gas properties | 2,937,744 | 2,131,545 | 5,567,776 | 3,718,477 |
Impairment of oil and gas properties | 21,639,000 | 0 | 21,639,000 | 0 |
Accretion of discount on asset retirement obligations | 7,932 | 5,148 | 15,861 | 9,653 |
Depreciation and amortization | 4,009 | 8,188 | 8,276 | 16,113 |
Total operating expenses | 27,027,945 | 3,966,106 | 31,756,230 | 7,249,011 |
Net operating income (loss) | (23,086,822) | 444,048 | (23,427,901) | 861,365 |
Other income (expense): | ||||
Other income | 6,707 | 0 | 6,707 | 0 |
Interest (expense) | (1,547,172) | (1,293,123) | (3,114,420) | (2,376,023) |
Total other income (expense) | (1,540,465) | (1,293,123) | (3,107,713) | (2,376,023) |
Loss before provision for income taxes | (24,627,287) | (849,075) | (26,535,614) | (1,514,658) |
Provision for income taxes | 5,957,649 | 305,715 | 6,593,040 | 589,738 |
Net loss | $ (18,669,638) | $ (543,360) | $ (19,942,574) | $ (924,920) |
Weighted average common shares outstanding - basic | 47,979,990 | 47,979,990 | 47,979,990 | 47,979,990 |
Weighted average common shares outstanding - fully diluted | 47,979,990 | 47,979,990 | 47,979,990 | 47,979,990 |
Net loss per common share - basic | $ (.39) | $ (.01) | $ (.42) | $ (.02) |
Net loss per common share - fully diluted | $ (0.39) | $ (0.01) | $ (0.42) | $ (0.02) |
CONDENSED STATEMENTS OF CASH FL
CONDENSED STATEMENTS OF CASH FLOWS - USD ($) | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
Net loss | $ (19,942,574) | $ (924,920) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||
Depletion of oil and gas properties | 5,567,776 | 3,718,477 |
Depreciation and amortization | 8,276 | 16,113 |
Amortization of debt issuance costs | 190,780 | 145,307 |
Accretion of discount on asset retirement obligations | 15,861 | 9,653 |
Loss on the mark-to-market of derivatives | 1,588,826 | 1,095,159 |
Accrued payment in kind interest applied to long term debt | 634,919 | 472,712 |
Amortization of original issue discount on debt | 84,858 | 60,288 |
Amortization of debt discounts, warrants | 321,763 | 310,042 |
Common stock options issued to employees and directors | 313,751 | 288,961 |
Deferred income taxes | (6,593,040) | (589,738) |
Impairment of oil and natural gas properties | 21,639,000 | 0 |
Decrease (increase) in current assets: | ||
Accounts receivable | 1,648,800 | (2,835,328) |
Prepaid expenses | (4,964) | (15,812) |
Increase (decrease) in current liabilities: | ||
Accounts payable | 36,328 | 203,177 |
Accrued expenses | 33,720 | 58,040 |
Net cash provided by operating activities | 5,544,080 | 2,012,131 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Proceeds from sale or swap of oil and gas properties | 103,000 | 1,360,920 |
Purchases of oil and gas properties and development capital expenditures | (12,677,179) | (11,731,981) |
Advances to operators | 0 | (3,491,089) |
Purchases of other property and equipment | 0 | (11,131) |
Net cash used in investing activities | (12,574,179) | (13,873,281) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Advances from revolving credit facilities and long term debt | 10,600,000 | 18,700,000 |
Repayments on revolving credit facilities | (3,450,000) | (7,850,000) |
Debt issuance costs | 0 | (54,782) |
Net cash provided by financing activities | 7,150,000 | 10,795,218 |
NET CHANGE IN CASH | 119,901 | (1,065,932) |
CASH AT BEGINNING OF PERIOD | 94,682 | 1,150,347 |
CASH AT END OF PERIOD | 214,583 | 84,415 |
SUPPLEMENTAL INFORMATION: | ||
Interest paid | 2,174,153 | 1,457,540 |
Income taxes paid | 0 | 0 |
NON-CASH INVESTING AND FINANCING ACTIVITIES: | ||
Net change in accounts payable for purchase of oil and gas properties | (161,409) | (98,778) |
Advances to operators applied to development of oil and gas properties | 0 | 2,131,043 |
Capitalized asset retirement costs, net of revision in estimate | $ 41,695 | $ 40,712 |
1. Organization and Nature of B
1. Organization and Nature of Business | 6 Months Ended |
Jun. 30, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Nature of Business | Effective April 2, 2012, Ante5, Inc. changed its corporate name to Black Ridge Oil & Gas, Inc., and continues to be quoted on the OTCQB under the trading symbol ANFC. Black Ridge Oil & Gas, Inc. (formerly Ante5, Inc.) (the Company) became an independent company in April 2010. We became a publicly traded company when our shares began trading on July 1, 2010. Since October 2010, we have been engaged in the business of acquiring oil and gas leases and participating in the drilling of wells in the Bakken and Three Forks trends in North Dakota and Montana. Our strategy is to participate in the exploration, development and production of oil and gas reserves as a non-operating working interest owner with a growing, diversified portfolio of oil and gas wells. We aggressively seek to accumulate mineral rights and participate in the drilling of new wells on a continuous basis. Occasionally, we also purchase working interests in producing wells. The Companys focus is the acquisition, exploration, development and production of crude oil and natural gas properties, primarily in the Bakken and Three Forks trends in North Dakota and Montana. We believe that our prospective success revolves around our ability to acquire mineral rights and participate in drilling activities by virtue of our ownership of such rights and through the relationships we have developed with our operating partners. As a non-operating working interest partner, we participate in drilling activities primarily on a heads-up basis. Before a well is spud, an operator is required to offer all mineral lease owners in the designated well spacing unit the right to participate in the drilling and production of the well. Drilling costs and revenues from oil and gas sales are split pro-rata based on acreage ownership in the designated drilling unit. We rely on our operator partners to identify specific drilling sites, permit wells, and engage in the drilling process. As a non-operator we are focused on maintaining a low overhead structure. |
2. Basis of Presentation and Si
2. Basis of Presentation and Significant Accounting Policies | 6 Months Ended |
Jun. 30, 2015 | |
Accounting Policies [Abstract] | |
Basis of Presentation and Significant Accounting Policies | Basis of Presentation and Significant Accounting Policies The interim condensed financial statements included herein, presented in accordance with United States generally accepted accounting principles and stated in US dollars, have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (the SEC). Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to not make the information presented misleading. These statements reflect all adjustments, which in the opinion of management, are necessary for fair presentation of the information contained therein. Except as otherwise disclosed, all such adjustments are of a normal recurring nature. It is suggested that these interim condensed financial statements be read in conjunction with the audited financial statements for the year ended December 31, 2014, which were included in our Annual Report on Form 10-K filed with the SEC. The Company follows the same accounting policies in the preparation of interim reports. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. Environmental Liabilities The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs. At this time, management knows of no substantial losses from environmental accidents or events which would have a material effect on the Company. Cash and Cash Equivalents Cash equivalents include money market accounts which have maturities of three months or less. For the purpose of the statements of cash flows, all highly liquid investments with an original maturity of three months or less are considered to be cash equivalents. Cash equivalents are stated at cost plus accrued interest, which approximates market value. No cash equivalents were on hand at June 30, 2015 and December 31, 2014. Cash in Excess of FDIC Insured Limits The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (FDIC) and the Securities Investor Protection Corporation (SIPC) up to $250,000 and $500,000, respectively, under current regulations. The Company had approximately $-0- and $-0- in excess of FDIC and SIPC insured limits at June 30, 2015 and December 31, 2014, respectively. The Company has not experienced any losses in such accounts. Advances to Operators The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of the drilling operations within 120 days from when the advance is paid. Debt Issuance Costs Costs relating to obtaining our revolving credit facilities are capitalized and amortized over the term of the related debt using the straight-line method. The unamortized balance of debt issuance costs at June 30, 2015, and December 31, 2014, was $510,239 and $701,019, respectively. Amortization of debt issuance costs charged to interest expense were $190,780 and $145,307 for the six months ended June 30, 2015 and 2014, respectively. When a loan is paid in full, any unamortized financing costs are removed from the related accounts and charged to interest expense. Website Development Costs The Company accounts for website development costs in accordance with ASC 350-50, Accounting for Website Development Costs (ASC 350-50), wherein website development costs are segregated into three activities: 1) Initial stage (planning), whereby the related costs are expensed. 2) Development (web application, infrastructure, graphics), whereby the related costs are capitalized and amortized once the website is ready for use. Costs for development content of the website may be expensed or capitalized depending on the circumstances of the expenditures. 3) Post-implementation (after site is up and running: security, training, admin), whereby the related costs are expensed as incurred. Upgrades are usually expensed, unless they add additional functionality. We have capitalized a total of $56,660 of website development costs from inception through June 30, 2015. We depreciate our website development costs on a straight line basis over the estimated useful life of the assets, which is currently three years. We have recognized depreciation expense on these website costs of $257 and $9,443 for the six months ended June 30, 2015 and 2014, respectively. As of June 30, 2015, all website development costs have been fully depreciated. Income Taxes The Company recognizes deferred tax assets and liabilities based on differences between the financial reporting and tax basis of assets and liabilities using the enacted tax rates and laws that are expected to be in effect when the differences are expected to be recovered. The Company provides a valuation allowance for deferred tax assets for which it does not consider realization of such assets to be more likely than not. Basic and Diluted Loss Per Share The basic net loss per share is computed by dividing the net loss (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted net loss per common share is computed by dividing the net loss by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options, warrants and restricted stock. The number of potential common shares outstanding relating to stock options, warrants and restricted stock is computed using the treasury stock method. For the periods presented, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share. Fair Value of Financial Instruments Under FASB ASC 820-10-05, the Financial Accounting Standards Board establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. This Statement reaffirms that fair value is the relevant measurement attribute. The adoption of this standard did not have a material effect on the Companys financial statements as reflected herein. The carrying amounts of cash, accounts payable and accrued expenses reported on the balance sheets are estimated by management to approximate fair value primarily due to the short term nature of the instruments. The Company had no items that required fair value measurement on a recurring basis. Non-Oil & Gas Property and Equipment Property and equipment that are not oil and gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than oil and gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non-oil and gas long-lived assets. Depreciation expense was $8,276 and $16,113 for the six months ended June 30, 2015 and 2014, respectively. Revenue Recognition The Company recognizes oil and gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for gas balancing of gas production and would recognize a liability if the existing proven reserves were not adequate to cover an imbalance situation. Asset Retirement Obligations The Company records the fair value of a liability for an asset retirement obligation in the period in which the well is spud or the asset is acquired and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its 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, a gain or loss is recognized. Full Cost Method The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center ("full cost pool"). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the six months ended June 30, 2015 and 2014, respectively: Six Months Ended June 30, 2015 2014 Capitalized Certain Payroll and Other Internal Costs $ $ 23,944 Capitalized Interest Costs 295,331 105,555 Total $ 295,331 $ 129,499 Proceeds from sales of proved properties will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 20% or more of the proved reserves related to a single full cost pool. The Company assesses all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. Capitalized costs associated with impaired properties and properties having proved reserves, estimated future development costs, and asset retirement costs under FASB ASC 410-20-25 are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. Capitalized costs of oil and gas properties (net of related deferred income taxes) may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved oil and gas reserves plus the cost of unproved properties (adjusted for related income tax effects). Should capitalized costs exceed this ceiling, impairment is recognized. The present value of estimated future net cash flows is computed by applying the arithmetic average first day price of oil and natural gas for the preceding twelve months to estimated future production of proved oil and gas reserves as of the end of the period, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. Such present value of proved reserves' future net cash flows excludes future cash outflows associated with settling asset retirement obligations. Should this comparison indicate an excess carrying value, the excess is charged to earnings as an impairment expense. As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, we recorded a non-cash ceiling test impairment of $21,639,000 in the six months ended June 30, 2015. The Company did not have any impairment of its proved oil and gas properties for the six months ended June 30, 2014. The impairment charge affected our reported net income but did not reduce our cash flow. Continued write downs of oil and natural gas properties are expected to occur until such time as commodity prices have recovered, and remain at recovered levels, so as to meaningfully increase the trailing 12-month average price used in the ceiling calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods. Stock-Based Compensation The Company adopted FASB guidance on stock based compensation upon inception at April 9, 2010. Under FASB ASC 718-10-30-2, all share-based payments to employees, including grants of employee stock options, are recognized in the income statement based on their fair values. Expense related to common stock and stock options issued for services and compensation totaled $313,751 and $288,961 for the six months ended June 30, 2015 and 2014, respectively, using the Black-Scholes options pricing model and an effective term of 6 to 6.5 years based on the weighted average of the vesting periods and the stated term of the option grants and the discount rate on 5 to 7 year U.S. Treasury securities at the grant date. In addition, $321,763 and $310,042 of warrant related debt discounts were amortized during the six months ended June 30, 2015 and 2014, respectively, and treated as interest expense. The fair value of warrants is determined similar to the method used in determining the fair value of employee stock options and the fair value is amortized over the life of the related credit facility and accelerated in the event of termination of the related credit facility. Uncertain Tax Positions Effective upon inception at April 9, 2010, the Company adopted standards for accounting for uncertainty in income taxes. These standards prescribe a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. These standards also provide guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. Various taxing authorities may periodically audit the Companys income tax returns. These audits include questions regarding the Companys tax filing positions, including the timing and amount of deductions and the allocation of income to various tax jurisdictions. In evaluating the exposures connected with these various tax filing positions, including state and local taxes, the Company records allowances for probable exposures. A number of years may elapse before a particular matter, for which an allowance has been established, is audited and fully resolved. Black Ridge Oil & Gas, Inc. has not yet undergone an examination by any taxing authorities. The assessment of the Companys tax position relies on the judgment of management to estimate the exposures associated with the Companys various filing positions. Derivative Instruments and Price Risk Management The Company enters into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of crude oil without the exchange of underlying volumes. The notional amounts of these financial instruments are based on a portion of the expected production from existing wells. The Company has, and may continue to use exchange traded futures contracts and option contracts to hedge the delivery price of crude oil at a future date. Any realized gains and losses are recorded to gain (loss) on settled derivatives and unrealized gains or losses as a result of mark-to market valuations are recorded to gain (loss) on the mark-to-market of derivatives on the statements of operations. Recent Accounting Pronouncements New accounting pronouncements are issued by the Financial Accounting Standards Board (FASB) that are adopted by the Company as of the specified effective date. If not discussed below, management believes there have been no developments to recently issued accounting standards, including expected dates of adoption and estimated effects on our financial statements, from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2014. In April 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2015-03, InterestImputation of Interest (Subtopic 835-30) In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40) In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers |
3. Dahl Federal Recognition
3. Dahl Federal Recognition | 6 Months Ended |
Jun. 30, 2015 | |
Dahl Federal Recognition | |
Dahl Federal Recognition | During the second quarter of 2015, we recognized well costs, revenues and expenses related to the Dahl Federal 2-15H (Dahl Federal) back to the inception of the well in 2012. The Company acquired the lease for mineral rights for the acreage related to the Dahl Federal from the State of North Dakota on February 7, 2012 for 110 acres or an 8.7% working interest in the Dahl Federal well that spud on January 6, 2012. The acreage we purchased lies within the riverbed of the Missouri River and there had been third-party litigation ongoing in the State of North Dakota pertaining to the states ownership claim to similar riparian acreage. We had signed an AFE for the well and the operator agreed to retroactively honor the AFE if the state was successful in defending its ownership claim. As the ownership of our acreage was not certain, we determined we could not recognize the well costs, revenues and expenses until the ownership questions were resolved. In April of 2015, after a North Dakota Supreme Court ruling in favor of the State and subsequent consensus by numerous parties as to the proper survey to be used in determining the high water mark of the Missouri River, the State of North Dakota began requesting payment of royalties for wells under similar circumstances from other operators. Because we believe the ownership questions have now been resolved, we capitalized all well costs since the wells inception, and have recognized revenues and expenses from the Dahl Federals first production in May of 2012. We have capitalized $927,312 of well costs related to the original AFE and subsequent improvements. We recognized oil and gas revenues of $1,295,966, production expenses of $87,063 and production taxes of $143,948 in the second quarter of 2015, of which $23,012 of oil and gas revenues, $8,088 of operating expenses and $2,522 of production taxes relate to production from the first quarter of 2015 and $1,241,214 of oil and gas revenues, $75,359 of operating expenses and $137,860 of production taxes relate to production prior to 2015. |
4. Property and Equipment
4. Property and Equipment | 6 Months Ended |
Jun. 30, 2015 | |
Property and equipment: | |
Property and Equipment | Property and equipment at June 30, 2015 and December 31, 2014, consisted of the following: June 30, December 31, 2015 2014 Oil and gas properties, full cost method: Evaluated costs $ 124,205,553 $ 112,418,105 Unevaluated costs, not subject to amortization or ceiling test 1,258,138 591,121 125,463,691 113,009,226 Other property and equipment 139,004 139,004 125,602,695 113,148,230 Less: Accumulated depreciation, amortization, depletion and impairments (46,117,576 ) (18,902,524 ) Total property and equipment, net $ 79,485,119 $ 94,245,706 The following table shows depreciation, depletion, and amortization expense by type of asset: Six Months Ended June 30, 2015 2014 Depletion of costs for evaluated oil and gas properties $ 5,567,776 $ 3,718,477 Depreciation and amortization of other property and equipment 8,276 16,113 Total depreciation, amortization and depletion $ 5,576,052 $ 3,734,590 Impairment of Oil and Gas Properties As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, we recorded a non-cash ceiling test impairment of $21,639,000 in the six months ended June 30, 2015. The Company did not have any impairment of its proved oil and gas properties for the six months ended June 30, 2014. The impairment charge affected our reported net income but did not reduce our cash flow. Continued write downs of oil and natural gas properties are expected to occur until such time as commodity prices have recovered, and remain at recovered levels, so as to meaningfully increase the trailing 12-month average price used in the ceiling calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods. |
5. Oil and Gas Properties
5. Oil and Gas Properties | 6 Months Ended |
Jun. 30, 2015 | |
Extractive Industries [Abstract] | |
Oil and Gas Properties | The following table summarizes gross and net productive oil wells by state at June 30, 2015 and 2014. A net well represents our percentage ownership of a gross well. The following table does not include wells in which our interest is limited to royalty and overriding royalty interests. The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation. June 30, 2015 June 30, 2014 Gross Net Gross Net North Dakota 286 8.59 206 6.20 Montana 5 0.37 1 0.08 Total 291 8.96 207 6.28 The Companys oil and gas properties consist of all acreage acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs. As of June 30, 2015 and 2014, our principal oil and gas assets included approximately 8,566 and 9,800 net acres, respectively, located in North Dakota and Montana. The following table summarizes our capitalized costs for the purchase and development of our oil and gas properties for the six months ended June 30, 2015 and 2014, respectively: Six Months Ended June 30, 2015 2014 Purchases of oil and gas properties and development costs for cash $ 12,677,179 $ 11,731,981 Purchase of oil and gas properties accrued at period-end 9,203,387 7,855,023 Purchase of oil and gas properties accrued at beginning of period (9,364,796 ) (7,953,801 ) Advances to operators applied to purchase of oil and gas properties 2,131,043 Capitalized asset retirement costs, net of revision in estimate 41,695 40,712 Total purchase and development costs, oil and gas properties $ 12,557,465 $ 13,804,958 2015 Acquisitions During the six months ended June 30, 2015, we purchased approximately nine net leasehold acres of oil and gas properties. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $102,928. 2015 Divestitures During the six months ended June 30, 2015, we sold a total of approximately nine net leasehold acres of oil and gas properties and two wellbores for total proceeds of $103,000. No gain or loss was recorded pursuant to the sales. 2014 Acquisitions During the six months ended June 30, 2014, we purchased approximately 200 net leasehold acres of oil and gas properties. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $1,652,551. 2014 Divestitures During the six months ended June 30, 2014, we sold a total of approximately 490 net leasehold acres of oil and gas properties for total proceeds of $1,340,920. No gain or loss was recorded pursuant to the sales. 2014 Swap Transactions During the six months ended June 30, 2014, we traded approximately 52 net leasehold acres of oil and gas properties for 40 net mineral acres and $20,000 in cash. No gain or loss was recorded pursuant to the transaction. Undeveloped Acreage Expirations During the six months ended June 30, 2015, we had leases encompassing 1,403 net acres expire with carrying costs of $1,355,794 that had been reserved and transferred to the full cost pool subject to depletion. We estimate that approximately 461 additional net acres with carrying costs of approximately $644,097 will expire prior to the commencement of production activities on the related leased property during 2015. The carrying costs of leases we estimate will expire during the remainder of 2015 had been reserved and transferred to the full cost pool subject to depletion in 2014. |
6. Asset Retirement Obligation
6. Asset Retirement Obligation | 6 Months Ended |
Jun. 30, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligation | The Company has asset retirement obligations (ARO) associated with the future plugging and abandonment of proved properties and related facilities. Under the provisions of FASB ASC 410-20-25, the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long lived asset. The liability is accreted to its 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, a gain or loss is recognized. The Company has no assets that are legally restricted for purposes of settling ARO. The following table summarizes the Companys asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410-20-25 during the six months ended June 30, 2015 and 2014: Six Months Ended June 30, 2015 2014 Beginning ARO $ 286,804 $ 160,665 Liabilities incurred for new wells placed in production 41,695 40,712 Accretion of discount on ARO 15,861 9,653 Ending ARO $ 344,360 $ 211,030 |
7. Related Party
7. Related Party | 6 Months Ended |
Jun. 30, 2015 | |
Related Party Transactions [Abstract] | |
Related Party | We currently lease office space on a month to month basis where the lessor is an entity owned by our former CEO and current Chairman of the Board of Directors, Bradley Berman. Pursuant to the lease, we occupy approximately 2,813 square feet of office space. In accordance with this lease, our lease term remains on a month-to-month basis, provided that either party may provide ninety (90) day notice to terminate the lease, with base rents of $2,110 per month, plus common area operations and maintenance charges, and monthly parking fees of $240 per month, for the period from November 15, 2013 to October 31, 2014, and subject to increases of $117 per month beginning November 1, 2014 and for each of the subsequent three year periods. We have paid a total of $35,128 and $35,501 to this entity during the six months ended June 30, 2015 and 2014, respectively. |
8. Derivative Instruments
8. Derivative Instruments | 6 Months Ended |
Jun. 30, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | The Company is required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its derivative instruments as cash flow hedges for accounting purposes and, as such, marks its derivative instruments to fair value and recognizes the realized and unrealized changes in fair value in its statements of operations under the captions Loss on settled derivatives and Loss on the mark-to-market of derivatives. The Company has utilized swap and collar derivative contracts. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits the upside revenue potential of upward price movements. For a fixed price swap contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price and the Company is required to make a payment to the counterparty if the settlement price for any period is greater than the swap price. For a collar contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price and no payment is required by either party if the settlement price for any settlement period is between the floor price and the ceiling price. The Companys derivative contracts are settled based on reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate (WTI) pricing. As of June 30, 2015, the Company had outstanding derivative contracts with respect to future production as follows: Crude Oil Swaps Settlement Period Oil (Barrels) Fixed Price July 1, 2015 December 31, 2015 12,000 $ 88.28 July 1, 2015 December 31, 2015 10,500 $ 89.70 July 1, 2015 December 31, 2015 6,000 $ 92.38 July 1, 2015 December 31, 2015 15,000 $ 90.16 October 1, 2015 December 31, 2015 36,000 $ 61.87 January 1, 2016 June 30, 2016 45,000 $ 62.88 January 1, 2016 December 31, 2016 60,000 $ 90.36 January 1, 2016 December 31, 2016 24,000 $ 88.15 January 1, 2017 December 31, 2017 78,000 $ 87.18 Crude Oil Costless Collars Floor/Ceiling Settlement Period Oil (Barrels) Price Basis July 1, 2015 December 31, 2015 18,000 $75.00/$95.60 NYMEX January 1, 2016 June 30, 2016 10,002 $80.00/$89.50 NYMEX As of June 30, 2015, the Company had total volume on open commodity swaps of 286,500 barrels at a weighted average price of approximately $81.33 per barrel. Derivative Gains and Losses The following table presents realized and unrealized gains and losses on derivative instruments for the periods presented: Six Months Ended June 30, 2015 2014 Realized gain (loss) on derivatives: Crude oil fixed price swaps $ 1,589,818 $ (378,882 ) Crude oil collars 390,801 Realized gain (loss) on derivatives, net $ 1,980,619 $ (378,882 ) Gain (loss) on the mark-to-market of derivatives: Crude oil fixed price swaps $ (1,161,398 ) $ (912,071 ) Crude oil collars (427,428 ) (183,088 ) Gain (loss) on the mark-to-market of derivatives, net $ (1,588,826 ) $ (1,095,159 ) Balance Sheet Offsetting of Derivative Assets and Liabilities In accordance with FASB issued ASU No. 2011-11, Balance Sheet (Topic 210)-Disclosures about Offsetting Assets and Liabilities, all of the Companys derivative contracts are carried at their fair value in the condensed balance sheets under the captions Derivative instruments and Noncurrent derivative instruments. Derivative instruments from the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the condensed balance sheets. The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under the netting arrangements with counterparties, and the resulting net amounts presented in the condensed balance sheets for the periods presented, all at fair value. June 30, 2015 December 31, 2014 Gross amounts of recognized assets Gross amounts offset on balance sheet Net amounts of assets on balance sheet Gross amounts of recognized assets Gross amounts offset on balance sheet Net amounts of assets on balance sheet Commodity derivative assets $ 5,998,159 $ (7,240 ) $ 5,990,919 $ 7,620,896 $ (41,151 ) $ 7,579,745 June 30, 2015 December 31, 2014 Gross amounts of recognized liabilities Gross amounts offset on balance sheet Net amounts of liabilities on balance sheet Gross amounts of recognized liabilities Gross amounts offset on balance sheet Net amounts of liabilities on balance sheet Commodity derivative liabilities $ $ $ $ $ $ The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed balance sheets: June 30, December 31, 2015 2014 Derivative assets $ 3,007,135 $ 3,571,803 Noncurrent derivative assets 2,983,784 4,007,942 Net amount of assets on the balance sheet 5,990,919 7,579,745 Current portion of derivative liabilities Derivative liabilities Net amount of liabilities on the balance sheet Total derivative assets (liabilities), net $ 5,990,919 $ 7,579,745 |
9. Fair Value of Financial Inst
9. Fair Value of Financial Instruments | 6 Months Ended |
Jun. 30, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments | The Company adopted FASB ASC 820-10 upon inception at April 9, 2010. Under FASB ASC 820-10-5, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). The standard outlines a valuation framework and creates a fair value hierarchy in order to increase the consistency and comparability of fair value measurements and the related disclosures. Under GAAP, certain assets and liabilities must be measured at fair value, and FASB ASC 820-10-50 details the disclosures that are required for items measured at fair value. The Company has revolving credit facilities that must be measured under the new fair value standard. The Companys financial assets and liabilities are measured using inputs from the three levels of the fair value hierarchy. The three levels are as follows: Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date. Level 2 - Inputs include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates, yield curves, etc.), and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs). Level 3 - Unobservable inputs that reflect our assumptions about the assumptions that market participants would use in pricing the asset or liability. The following schedule summarizes the valuation of financial instruments at fair value on a recurring basis in the balance sheets as of June 30, 2015 and December 31, 2014: Fair Value Measurements at June 30, 2015 Level 1 Level 2 Level 3 Assets Cash and cash equivalents $ 214,583 $ $ Derivative Instruments (crude oil swaps and collars) 5,990,919 Total assets 214,583 5,990,919 Liabilities Revolving credit facilities and long term debt, net of discounts 60,026,143 Total Liabilities 60,026,143 $ 214,583 $ (54,035,224 ) $ Fair Value Measurements at December 31, 2014 Level 1 Level 2 Level 3 Assets Cash and cash equivalents $ 94,682 $ $ Derivative Instruments (crude oil swaps and collars) 7,579,745 Total assets 94,682 7,579,745 Liabilities Revolving credit facilities and long term debt, net of discounts 51,834,603 Total Liabilities 51,834,603 $ 94,682 $ (44,254,858 ) $ There were no transfers of financial assets or liabilities between Level 1 and Level 2 inputs for the six months ended June 30, 2015 and 2014. Level 2 liabilities include Revolving credit facilities. No fair value adjustment was necessary during the six months ended June 30, 2015 and 2014. |
10. Revolving Credit Facilities
10. Revolving Credit Facilities and Long Term Debt | 6 Months Ended |
Jun. 30, 2015 | |
Debt Disclosure [Abstract] | |
Revolving Credit Facilities and Long Term Debt | The Company, as borrower, entered into a Credit Agreement dated August 8, 2013 and amendments thereto dated December 13, 2013, March 24, 2014, April 21, 2014, September 11, 2014, March 30, 2015 and August 10, 2015 (as amended, the Senior Credit Agreement Availability under the Senior Credit Facility is at all times subject to the then-applicable borrowing base, determined by Cadence in a manner consistent with the normal and customary oil and gas lending practices of Cadence. Availability was initially set at $7 million and is subject to periodic redeterminations. The availability was $35 million as of December 31, 2014, and subsequently amended to $34 million on March 30, 2015. The availability remains at $34 million as of June 30, 2015. Subject to availability under the borrowing base, the Company may borrow, repay and re-borrow funds in amounts of $250,000 or more. At the Companys election, the unpaid principal balance of any borrowings under the Senior Credit Facility may bear interest at either (i) the Base Rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 1.00% to 1.50% or (ii) the LIBOR rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 3.00% to 3.50%. Interest is payable for Base Rate loans on the last business day of the month and for LIBOR loans on the last LIBOR business day of each LIBOR interest period. The Company is also required to pay a quarterly fee of 0.50% on any unused portion of the borrowing base, as well as a facility fee of 0.90% of the initial and any subsequent additions to the borrowing base. The Senior Credit Facilitys maturity date of August 8, 2016, was subsequently amended to January 15, 2017 pursuant to the amendment on March 30, 2015. The Company may prepay the entire amount of Base Rate loans at any time, and may prepay the entire amount of LIBOR loans upon at least three business days notice to Cadence. The Senior Credit Facility is secured by first priority interests in mortgages on substantially all of the Companys assets, including but not limited to the Companys mineral interests in North Dakota and Montana. The Company had borrowings of $29.75 million and $22.6 million outstanding under the Senior Credit Agreement as of June 30, 2015 and December 31, 2014, respectively. Subordinated Credit Facility The Company, as borrower, entered into a Second Lien Credit Agreement dated August 8, 2013 and amendments thereto dated December 13, 2013, March 24, 2014, April 21, 2014, September 11, 2014, March 30, 2015, and August 10, 2015 (as amended, the Subordinated Credit Agreement) by and among the Company, as borrower, Chambers Energy Management, LP, as administrative agent (Chambers), and the several other lenders named therein (the Subordinated Credit Facility). Under the Subordinated Credit Facility, term loans in the aggregate principal amount of up to $75 million are available from time to time (i) to repay the Previous Credit Facility, (ii) for fees and closing costs in connection with both the Senior Credit Facility and the Subordinated Credit Facility (together, the Credit Facilities), and (iii) general corporate purposes. The Subordinated Credit Agreement provided initial commitment availability of $25 million, which was subsequently amended to the current availability of $30 million, with the remaining commitments subject to the approval of Chambers and other customary conditions. The Company may borrow the available commitments in amounts of $5 million or more and shall not request borrowings of such loans more than once a month, provided that the initial draw was at least $15 million. Loans under the Subordinated Credit Facility shall be funded net of a 2% OID. The unpaid principal balance of borrowings under the Subordinated Credit Facility bears interest at the Cash Interest Rate plus the PIK Interest Rate. The Cash Interest Rate is 9.00% per annum plus a rate per annum equal to the greater of (i) 1.00% and (ii) the offered rate for three-month deposits in U.S. dollars that appears on Reuters Screen LIBOR 01 as of 11:00 a.m. (London time) on the second full LIBOR business day preceding the first day of each calendar quarter. The PIK Interest Rate is equal to 4.00% per annum. Interest is payable on the last day of each month. The Company is also required to pay an annual nonrefundable administration fee of $50,000 and a monthly availability fee computed at a rate of 0.50% per annum on the average daily amount of any unused portion of the available amount under the commitment. The Subordinated Credit Facility matures on June 30, 2017. Upon at least three business days written notice, the Company may prepay the entire amount under the loans, together with accrued interest. Each prepayment made prior to the second anniversary of the funding date, as defined in the Subordinated Credit Facility, shall be accompanied by a make-whole amount, as defined in the Subordinated Credit Agreement. Prepayments made on or after the second anniversary of the funding date shall be accompanied by an applicable premium, as set forth in the Subordinated Credit Agreement. The Subordinated Credit Facility is secured by second priority interests on substantially all of the Companys assets, including but not limited to second priority mortgages on the Companys mineral interests in North Dakota and Montana. The first funding from the Subordinated Credit Facility occurred on September 9, 2013 at which time we drew $14.7 million, net of a $300,000 original issue discount, from the Subordinated Credit Agreement and used $10,226,057 of those proceeds to repay and terminate a previously outstanding revolving credit facility. We have drawn an additional $14.7 million, net of $300,000 original issue discounts, through June 30, 2015. The Company had borrowings of $30 million and $30 million outstanding under the Subordinated Credit Facility as of June 30, 2015 and December 31, 2014, respectively. Intercreditor Agreements and Covenants Cadence and Chambers have entered into an Intercreditor Agreement dated August 8, 2013 (the Intercreditor Agreement). The Intercreditor Agreement provides that any liens on the assets of the Company securing indebtedness under the Subordinated Credit Facility are subordinate to liens on the assets securing indebtedness under the Senior Credit Facility and sets forth the respective rights, obligations and remedies of the lenders under the Senior Credit Facility with respect to their first priority liens and the lenders under the Subordinated Credit Facility with respect to their second priority liens. The Credit Facilities, as amended, require customary affirmative and negative covenants for credit facilities of the respective types and sizes for companies operating in the oil and gas industry, as well as customary events of default. Furthermore, the Credit Facilities contain financial covenants that require the Company to satisfy certain specified financial ratios. The Senior Credit Agreement requires the Company to maintain, as of the last day of each fiscal quarter of the Company, (i) a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 0.65 to 1.00 through the quarter ending June 30, 2014, 0.70 to 1.00 for the quarters ending September 30, 2014 and December 31, 2014, was waived for the quarters ending March 31, 2015 and June 30, 2015, and 0.70 to 1.00 for the quarter ending September 30, 2015, and 0.80 to 1.00 for the quarter ending December 31, 2015 and thereafter, (ii) a ratio of current assets, including debt facility available to be drawn, to current liabilities of a minimum of 1.0 to 1.0, except for the quarter ending June 30, 2014, which was waived, (iii) a net debt to EBITDAX, as defined in the Senior Credit Agreement, ratio of 3.75 to 1.00 for the quarter ended March 31, 2014, 4.25 to 1.00 for the quarters ended June 30, 2014 and September 30, 2014, 4.00 to 1.00 for the quarter ended December 31, 2014, was waived for the quarters ended March 31, 2015 and June 30, 2015, and 3.50 to 1.00 for the quarter ending September 30, 2015, and 3.65 to 1.00 for the quarter ending December 31, 2015, and 3.50 to 1.00 for the quarter ending March 31, 2016 and thereafter, in each case calculated on a modified trailing four quarter basis, (iv) a maximum senior leverage ratio of not more than 2.5 to 1.0 calculated on a modified trailing four quarter basis, and (v) a minimum interest coverage ratio of not less than 3.0 to 1.0. The Subordinated Credit Agreement requires the Company to maintain, as of the last day of each fiscal quarter of the Company, (i) a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 0.65 to 1.00 through the quarter ending June 30, 2014, 0.70 to 1.00 for the quarters ending September 30, 2014 and December 31, 2014, was waived for the quarters ending March 31, 2015 and June 30, 2015, and 0.70 to 1.00 for the quarter ending September 30, 2015, and 0.80 to 1.00 for the quarter ending December 31, 2015 and thereafter, (ii) a consolidated net leverage ratio (adjusted total indebtedness less the amount of unrestricted cash equivalents to consolidated EBITDA) of no more than 3.75 to 1.00 for the quarter ending March 31, 2014, 4.25 to 1.00 for the quarters ending June 30, 2014 and September 30, 2014, 4.00 to 1.00 for the quarter ending December 31, 2014, was waived for the quarters ending March 31, 2015 and June 30, 2015, and 3.50 to 1.00 for the quarter ending September 30, 2015, and 3.65 to 1.00 for the quarter ending December 31, 2015, and 3.50 to 1.00 for the quarter ending March 31, 2016 and thereafter, calculated on a modified trailing four quarter basis, (iii) a consolidated cash interest coverage ratio (consolidated EBITDA to consolidated cash interest expense) of no less than 2.5 to 1.0, calculated on a modified trailing four quarter basis and (iv) a ratio of consolidated current assets to consolidated current liabilities of at least 1.0 to 1.0, except for the quarter ending June 30, 2015 when the covenant was waived. In addition, each of the Credit Facilities requires that the Company enter into hedging agreements based on anticipated oil production from currently producing wells as agreed to by the lenders. The Company is in compliance with all covenants, as amended, for the period ending June 30, 2015. Debt Discount, Detachable Warrants In connection with the Subordinated Credit Facility, the Company agreed to issue to the lenders detachable warrants to purchase up to 5,000,000 shares of the Companys common stock at an exercise price of $0.65 per share. The warrants expire on August 8, 2018. Proceeds from the loan were allocated between the debt and equity based on the relative fair values at the time of issuance, resulting in a debt discount of $2,473,576 at issuance that is presented as a debt discount on the balance sheet and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. A total of $321,763 and $310,042 was amortized during the six months ended June 30, 2015 and 2014, respectively. The remaining unamortized balance of the debt discount attributable to the warrants is $1,323,986 as of June 30, 2015. Amounts outstanding under revolving credit facilities and long term debts consisted of the following as of June 30, 2015 and December 31, 2014, respectively: June 30, December 31, 2015 2014 Senior Revolving Credit Facility, Cadence Bank, N.A. $ 29,750,000 $ 22,600,000 Subordinated Credit Agreement, Chambers 30,000,000 30,000,000 PIK Interest on Subordinated Credit Agreement, Chambers 1,942,005 1,307,086 Total credit facilities and long term debts 61,692,005 53,907,086 Less: Unamortized OID (341,876 ) (426,734 ) Less: Unamortized debt discount attributable to warrants (1,323,986 ) (1,645,749 ) Total credit facilities and long term debts, net of discounts 60,026,143 51,834,603 Less: current maturities Long term portion of credit facilities and long term debts $ 60,026,143 $ 51,834,603 Net proceeds of $29.4 million was received from our $30 million in advances due to $600,000 of OID pursuant to the Subordinated Credit Agreement at issuance that is presented as a debt discount on the balance sheet and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. A total of $84,858 and $60,288 was amortized during the six months ended June 30, 2015 and 2014, respectively. The remaining unamortized balance of the debt discount attributable to the OID is $341,876 as of June 30, 2015. The following presents components of interest expense for the six months ended June 30, 2015 and 2014, respectively: Six Months Ended June 30, 2015 2014 Accrued PIK interest $ 634,919 $ 472,712 Amortization of OID 84,858 60,288 Interest and commitment fees 2,177,431 1,493,229 Amortization of debt issuance costs 190,780 145,307 Amortization of warrant costs 321,763 310,042 Less interest capitalized to the full cost pool of our proved oil & gas properties (295,331 ) (105,555 ) $ 3,114,420 $ 2,376,023 |
11. Changes in Stockholders' Eq
11. Changes in Stockholders' Equity | 6 Months Ended |
Jun. 30, 2015 | |
Equity [Abstract] | |
Changes in Stockholders' Equity | Preferred Stock The Company has 20,000,000 authorized shares of $0.001 par value preferred stock. No shares have been issued to date. Common Stock The Company has 500,000,000 authorized shares of $0.001 par value common stock. |
12. Options
12. Options | 6 Months Ended |
Jun. 30, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Options | Options Granted No options were granted during the six months ended June 30, 2015. The Company recognized a total of $313,751, and $288,961 of compensation expense during the six months ended June 30, 2015 and 2014, respectively, on common stock options issued to Employees and Directors that are being amortized over the implied service term, or vesting period, of the options. The remaining unamortized balance of these options is $1,658,790 as of June 30, 2015. Options Exercised No options were exercised during the six months ended June 30, 2015 and 2014. Options Expired/Forfeited No options expired or were forfeited during the six months ended June 30, 2015 and 2014. |
13. Warrants
13. Warrants | 6 Months Ended |
Jun. 30, 2015 | |
Warrants and Rights Note Disclosure [Abstract] | |
Warrants | Warrants Granted No warrants were granted during the six months ended June 30, 2015 and 2014. We recognized a total of $321,763 and $310,042 of finance expense during the six months ended June 30, 2015 and 2014, respectively, on common stock warrants issued to lenders, respectively. All warrants granted pursuant to debt financings are amortized over the remaining life of the respective loan. Warrants Exercised No warrants were exercised during the six months ended June 30, 2015 and 2014. |
14. Income Taxes
14. Income Taxes | 6 Months Ended |
Jun. 30, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | The Company accounts for income taxes under ASC Topic 740, Income Taxes, We currently estimate that our effective tax rate for the year ending December 31, 2015 will be approximately 25%. Losses incurred during the period from April 9, 2011 (inception) to June 30, 2015 could be used to offset future tax liabilities. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is more likely than not that some component or all of the benefits of deferred tax assets will not be realized. As of June 30, 2015, net deferred tax assets were $3,918,360, after an offsetting reduction in deferred tax liabilities of $13,000,127, primarily related to differences in the book and tax basis amounts of the Companys oil and gas properties resulting from the expensing of intangible drilling costs and the accelerated depreciation utilized for tax purposes, was applied. A valuation allowance of approximately $3,918,360 was applied to the remaining net deferred tax assets. This valuation allowance reflects an allowance on only a portion of the Companys deferred tax assets which the Company believes it is more likely than not that the benefit of these assets will not be realized. We have not provided any valuation allowance against our deferred tax liabilities, which were netted against our deferred tax assets. The tax benefit for the six months ended June 30, 2015 of $6,593,040 was primarily driven by the Companys loss before provision for income taxes. In accordance with FASB ASC 740, the Company has evaluated its tax positions and determined there are no significant uncertain tax positions as of any date on, or before June 30, 2015. |
15. Commitments and Contingenci
15. Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | The Company from time to time may be involved in various inquiries, administrative proceedings and litigation relating to matters arising in the normal course of business. The Company is not aware of any inquiries or administrative proceedings and is not currently a defendant in any material litigation and is not aware of any threatened litigation that could have a material effect on the Company. The Company periodically maintains cash balances at banks in excess of federally insured amounts. The extent of loss, if any, to be sustained as a result of any future failure of a bank or other financial institution is not subject to estimation at this time. The Company commits to its participation in upcoming well development by signing an Authorization for Expenditure (AFE). As of June 30, 2015, the Company had committed to AFEs of approximately $4.4 million beyond amounts previously paid or accrued. |
16. Subsequent Events
16. Subsequent Events | 6 Months Ended |
Jun. 30, 2015 | |
Subsequent Events [Abstract] | |
Subsequent Events | Debt Facilities During the period from July 1, 2015 to August 12, 2015, the Company drew an additional $0.45 million, net of repayments, on the senior secured facility. Crude Oil Swaps Between July 1, 2015 and August 12, 2015, the Company entered into crude oil swap contracts with crude oil settlements based on NYMEX WTI pricing as follows: Settlement Period Oil (Barrels) Fixed Price July 1, 2016 December 31, 2016 18,000 $ 55.55 January 1, 2017 December 31, 2017 42,000 $ 57.95 January 1, 2018 June 30, 2018 96,000 $ 60.67 Joint Venture with Merced Capital On July 23, 2015, the Company signed a definitive agreement with an affiliate of Merced Capital (Merced) to form a joint venture that will acquire and develop Williston Basin non-operated assets. The joint venture will be funded by Merced with an initial investment target of $50 Million. Investments will be subject to Merced approval, and will be managed by the Company. The joint venture assets will be managed by the Company in exchange for a management fee and reimbursement of third party expenses, and, after certain investor hurdles are met, The Company will receive a share of profits in the joint venture. The Company will also have the option to co-invest up to 25% on acquisitions and capital expenditures alongside the venture and any such co-investments will reside directly with the Company. Upon the sale of joint venture assets, the Company will also have the option to bid and acquire the assets. |
2. Basis of Presentation and 22
2. Basis of Presentation and Significant Accounting Policies (Policies) | 6 Months Ended |
Jun. 30, 2015 | |
Accounting Policies [Abstract] | |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. |
Environmental Liabilities | Environmental Liabilities The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs. At this time, management knows of no substantial losses from environmental accidents or events which would have a material effect on the Company. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash equivalents include money market accounts which have maturities of three months or less. For the purpose of the statements of cash flows, all highly liquid investments with an original maturity of three months or less are considered to be cash equivalents. Cash equivalents are stated at cost plus accrued interest, which approximates market value. No cash equivalents were on hand at March 31, 2015 and December 31, 2014. |
Cash in Excess of FDIC Insured Limits | Cash in Excess of FDIC Insured Limits The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (FDIC) and the Securities Investor Protection Corporation (SIPC) up to $250,000 and $500,000, respectively, under current regulations. The Company had approximately $-0- and $-0- in excess of FDIC and SIPC insured limits at June 30, 2015 and December 31, 2014, respectively. The Company has not experienced any losses in such accounts. |
Advances to Operators | Advances to Operators The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of the drilling operations within 120 days from when the advance is paid. |
Debt Issuance Costs | Debt Issuance Costs Costs relating to obtaining our revolving credit facilities are capitalized and amortized over the term of the related debt using the straight-line method. The unamortized balance of debt issuance costs at June 30, 2015, and December 31, 2014, was $510,239 and $701,019, respectively. Amortization of debt issuance costs charged to interest expense were $190,780 and $145,307 for the six months ended June 30, 2015 and 2014, respectively. When a loan is paid in full, any unamortized financing costs are removed from the related accounts and charged to interest expense. |
Website Development Costs | Website Development Costs The Company accounts for website development costs in accordance with ASC 350-50, Accounting for Website Development Costs (ASC 350-50), wherein website development costs are segregated into three activities: 1) Initial stage (planning), whereby the related costs are expensed. 2) Development (web application, infrastructure, graphics), whereby the related costs are capitalized and amortized once the website is ready for use. Costs for development content of the website may be expensed or capitalized depending on the circumstances of the expenditures. 3) Post-implementation (after site is up and running: security, training, admin), whereby the related costs are expensed as incurred. Upgrades are usually expensed, unless they add additional functionality. We have capitalized a total of $56,660 of website development costs from inception through June 30, 2015. We depreciate our website development costs on a straight line basis over the estimated useful life of the assets, which is currently three years. We have recognized depreciation expense on these website costs of $257 and $9,443 for the six months ended June 30, 2015 and 2014, respectively. As of June 30, 2015, all website development costs have been fully depreciated. |
Income Taxes | Income Taxes The Company recognizes deferred tax assets and liabilities based on differences between the financial reporting and tax basis of assets and liabilities using the enacted tax rates and laws that are expected to be in effect when the differences are expected to be recovered. The Company provides a valuation allowance for deferred tax assets for which it does not consider realization of such assets to be more likely than not. |
Basic and Diluted Loss Per Share | Basic and Diluted Loss Per Share The basic net loss per share is computed by dividing the net loss (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted net loss per common share is computed by dividing the net loss by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options, warrants and restricted stock. The number of potential common shares outstanding relating to stock options, warrants and restricted stock is computed using the treasury stock method. For the periods presented, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share. |
Fair Value of Financial Instruments | Fair Value of Financial Instruments Under FASB ASC 820-10-05, the Financial Accounting Standards Board establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. This Statement reaffirms that fair value is the relevant measurement attribute. The adoption of this standard did not have a material effect on the Companys financial statements as reflected herein. The carrying amounts of cash, accounts payable and accrued expenses reported on the balance sheets are estimated by management to approximate fair value primarily due to the short term nature of the instruments. The Company had no items that required fair value measurement on a recurring basis. |
Non-Oil and Gas Property and Equipment | Non-Oil & Gas Property and Equipment Property and equipment that are not oil and gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than oil and gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non-oil and gas long-lived assets. Depreciation expense was $8,276 and $16,113 for the six months ended June 30, 2015 and 2014, respectively. |
Revenue Recognition | Revenue Recognition The Company recognizes oil and gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for gas balancing of gas production and would recognize a liability if the existing proven reserves were not adequate to cover an imbalance situation. |
Asset Retirement Obligations | Asset Retirement Obligations The Company records the fair value of a liability for an asset retirement obligation in the period in which the well is spud or the asset is acquired and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its 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, a gain or loss is recognized. |
Full Cost Method | Full Cost Method The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center ("full cost pool"). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the six months ended June 30, 2015 and 2014, respectively: Six Months Ended June 30, 2015 2014 Capitalized Certain Payroll and Other Internal Costs $ $ 23,944 Capitalized Interest Costs 295,331 105,555 Total $ 295,331 $ 129,499 Proceeds from sales of proved properties will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 20% or more of the proved reserves related to a single full cost pool. The Company assesses all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. Capitalized costs associated with impaired properties and properties having proved reserves, estimated future development costs, and asset retirement costs under FASB ASC 410-20-25 are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. Capitalized costs of oil and gas properties (net of related deferred income taxes) may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved oil and gas reserves plus the cost of unproved properties (adjusted for related income tax effects). Should capitalized costs exceed this ceiling, impairment is recognized. The present value of estimated future net cash flows is computed by applying the arithmetic average first day price of oil and natural gas for the preceding twelve months to estimated future production of proved oil and gas reserves as of the end of the period, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. Such present value of proved reserves' future net cash flows excludes future cash outflows associated with settling asset retirement obligations. Should this comparison indicate an excess carrying value, the excess is charged to earnings as an impairment expense. As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, we recorded a non-cash ceiling test impairment of $21,639,000 in the six months ended June 30, 2015. The Company did not have any impairment of its proved oil and gas properties for the six months ended June 30, 2014. The impairment charge affected our reported net income but did not reduce our cash flow. Continued write downs of oil and natural gas properties are expected to occur until such time as commodity prices have recovered, and remain at recovered levels, so as to meaningfully increase the trailing 12-month average price used in the ceiling calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods. |
Stock-Based Compensation | Stock-Based Compensation The Company adopted FASB guidance on stock based compensation upon inception at April 9, 2010. Under FASB ASC 718-10-30-2, all share-based payments to employees, including grants of employee stock options, are recognized in the income statement based on their fair values. Expense related to common stock and stock options issued for services and compensation totaled $160,924 and $144,240 for the three months ended March 31, 2015 and 2014, respectively, using the Black-Scholes options pricing model and an effective term of 6 to 6.5 years based on the weighted average of the vesting periods and the stated term of the option grants and the discount rate on 5 to 7 year U.S. Treasury securities at the grant date. In addition, $160,428 and $153,522 of warrant related debt discounts were amortized during the three months ended March 31, 2015 and 2014, respectively, and treated as interest expense. The fair value of warrants is determined similar to the method used in determining the fair value of employee stock options and the fair value is amortized over the life of the related credit facility and accelerated in the event of termination of the related credit facility. |
Uncertain Tax Positions | Uncertain Tax Positions Effective upon inception at April 9, 2010, the Company adopted standards for accounting for uncertainty in income taxes. These standards prescribe a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. These standards also provide guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. Various taxing authorities may periodically audit the Companys income tax returns. These audits include questions regarding the Companys tax filing positions, including the timing and amount of deductions and the allocation of income to various tax jurisdictions. In evaluating the exposures connected with these various tax filing positions, including state and local taxes, the Company records allowances for probable exposures. A number of years may elapse before a particular matter, for which an allowance has been established, is audited and fully resolved. Black Ridge Oil & Gas, Inc. has not yet undergone an examination by any taxing authorities. The assessment of the Companys tax position relies on the judgment of management to estimate the exposures associated with the Companys various filing positions. |
Derivative Instruments and Price Risk Management | Derivative Instruments and Price Risk Management The Company enters into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of crude oil without the exchange of underlying volumes. The notional amounts of these financial instruments are based on a portion of the expected production from existing wells. The Company has, and may continue to use exchange traded futures contracts and option contracts to hedge the delivery price of crude oil at a future date. Any realized gains and losses are recorded to gain (loss) on settled derivatives and unrealized gains or losses as a result of mark-to market valuations are recorded to gain (loss) on the mark-to-market of derivatives on the statements of operations. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements New accounting pronouncements are issued by the Financial Accounting Standards Board (FASB) that are adopted by the Company as of the specified effective date. If not discussed below, management believes there have been no developments to recently issued accounting standards, including expected dates of adoption and estimated effects on our financial statements, from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2014. In April 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2015-03, InterestImputation of Interest (Subtopic 835-30) In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40) In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers |
2. Basis of Presentation and 23
2. Basis of Presentation and Significant Accounting Policies (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Accounting Policies [Abstract] | |
Schedule of Capitalized Costs | Six Months Ended June 30, 2015 2014 Capitalized Certain Payroll and Other Internal Costs $ $ 23,944 Capitalized Interest Costs 295,331 105,555 Total $ 295,331 $ 129,499 |
4. Property and Equipment (Tabl
4. Property and Equipment (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Property and equipment: | |
Property and equipment | June 30, December 31, 2015 2014 Oil and gas properties, full cost method: Evaluated costs $ 124,205,553 $ 112,418,105 Unevaluated costs, not subject to amortization or ceiling test 1,258,138 591,121 125,463,691 113,009,226 Other property and equipment 139,004 139,004 125,602,695 113,148,230 Less: Accumulated depreciation, amortization, depletion and impairments (46,117,576 ) (18,902,524 ) Total property and equipment, net $ 79,485,119 $ 94,245,706 |
Depreciation, depletion, and amortization expense | Six Months Ended June 30, 2015 2014 Depletion of costs for evaluated oil and gas properties $ 5,567,776 $ 3,718,477 Depreciation and amortization of other property and equipment 8,276 16,113 Total depreciation, amortization and depletion $ 5,576,052 $ 3,734,590 |
5. Oil and Gas Properties (Tabl
5. Oil and Gas Properties (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Extractive Industries [Abstract] | |
Gross and net productive oil wells | June 30, 2015 June 30, 2014 Gross Net Gross Net North Dakota 286 8.59 206 6.20 Montana 5 0.37 1 0.08 Total 291 8.96 207 6.28 |
Capitalized costs | Six Months Ended June 30, 2015 2014 Purchases of oil and gas properties and development costs for cash $ 12,677,179 $ 11,731,981 Purchase of oil and gas properties accrued at period-end 9,203,387 7,855,023 Purchase of oil and gas properties accrued at beginning of period (9,364,796 ) (7,953,801 ) Advances to operators applied to purchase of oil and gas properties 2,131,043 Capitalized asset retirement costs, net of revision in estimate 41,695 40,712 Total purchase and development costs, oil and gas properties $ 12,557,465 $ 13,804,958 |
6. Asset Retirement Obligation
6. Asset Retirement Obligation (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset retirement obligation | Six Months Ended June 30, 2015 2014 Beginning ARO $ 286,804 $ 160,665 Liabilities incurred for new wells placed in production 41,695 40,712 Accretion of discount on ARO 15,861 9,653 Ending ARO $ 344,360 $ 211,030 |
8. Derivative Instruments (Tabl
8. Derivative Instruments (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Outstanding derivative contracts with respect to future production | As of June 30, 2015, the Company had outstanding derivative contracts with respect to future production as follows: Crude Oil Swaps Settlement Period Oil (Barrels) Fixed Price July 1, 2015 December 31, 2015 12,000 $ 88.28 July 1, 2015 December 31, 2015 10,500 $ 89.70 July 1, 2015 December 31, 2015 6,000 $ 92.38 July 1, 2015 December 31, 2015 15,000 $ 90.16 October 1, 2015 December 31, 2015 36,000 $ 61.87 January 1, 2016 June 30, 2016 45,000 $ 62.88 January 1, 2016 December 31, 2016 60,000 $ 90.36 January 1, 2016 December 31, 2016 24,000 $ 88.15 January 1, 2017 December 31, 2017 78,000 $ 87.18 Crude Oil Costless Collars Floor/Ceiling Settlement Period Oil (Barrels) Price Basis July 1, 2015 December 31, 2015 18,000 $75.00/$95.60 NYMEX January 1, 2016 June 30, 2016 10,002 $80.00/$89.50 NYMEX |
Realized and unrealized gains and losses on derivative instruments | Six Months Ended June 30, 2015 2014 Realized gain (loss) on derivatives: Crude oil fixed price swaps $ 1,589,818 $ (378,882 ) Crude oil collars 390,801 Realized gain (loss) on derivatives, net $ 1,980,619 $ (378,882 ) Gain (loss) on the mark-to-market of derivatives: Crude oil fixed price swaps $ (1,161,398 ) $ (912,071 ) Crude oil collars (427,428 ) (183,088 ) Gain (loss) on the mark-to-market of derivatives, net $ (1,588,826 ) $ (1,095,159 ) |
Gross amounts of recognized derivative assets and liabilities | June 30, 2015 December 31, 2014 Gross amounts of recognized assets Gross amounts offset on balance sheet Net amounts of assets on balance sheet Gross amounts of recognized assets Gross amounts offset on balance sheet Net amounts of assets on balance sheet Commodity derivative assets $ 5,998,159 $ (7,240 ) $ 5,990,919 $ 7,620,896 $ (41,151 ) $ 7,579,745 June 30, 2015 December 31, 2014 Gross amounts of recognized liabilities Gross amounts offset on balance sheet Net amounts of liabilities on balance sheet Gross amounts of recognized liabilities Gross amounts offset on balance sheet Net amounts of liabilities on balance sheet Commodity derivative liabilities $ $ $ $ $ $ |
Reconciliation of derivative assets and liabilities | June 30, December 31, 2015 2014 Derivative assets $ 3,007,135 $ 3,571,803 Noncurrent derivative assets 2,983,784 4,007,942 Net amount of assets on the balance sheet 5,990,919 7,579,745 Current portion of derivative liabilities Derivative liabilities Net amount of liabilities on the balance sheet Total derivative assets (liabilities), net $ 5,990,919 $ 7,579,745 |
9. Fair Value of Financial In28
9. Fair Value of Financial Instruments (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Fair Value Disclosures [Abstract] | |
Valuation of financial instruments at fair value | Fair Value Measurements at June 30, 2015 Level 1 Level 2 Level 3 Assets Cash and cash equivalents $ 214,583 $ $ Derivative Instruments (crude oil swaps and collars) 5,990,919 Total assets 214,583 5,990,919 Liabilities Revolving credit facilities and long term debt, net of discounts 60,026,143 Total Liabilities 60,026,143 $ 214,583 $ (54,035,224 ) $ Fair Value Measurements at December 31, 2014 Level 1 Level 2 Level 3 Assets Cash and cash equivalents $ 94,682 $ $ Derivative Instruments (crude oil swaps and collars) 7,579,745 Total assets 94,682 7,579,745 Liabilities Revolving credit facilities and long term debt, net of discounts 51,834,603 Total Liabilities 51,834,603 $ 94,682 $ (44,254,858 ) $ |
10. Revolving Credit Faciliti29
10. Revolving Credit Facilities and Long Term Debt (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Debt Disclosure [Abstract] | |
Revolving credit facility | June 30, December 31, 2015 2014 Senior Revolving Credit Facility, Cadence Bank, N.A. $ 29,750,000 $ 22,600,000 Subordinated Credit Agreement, Chambers 30,000,000 30,000,000 PIK Interest on Subordinated Credit Agreement, Chambers 1,942,005 1,307,086 Total credit facilities and long term debts 61,692,005 53,907,086 Less: Unamortized OID (341,876 ) (426,734 ) Less: Unamortized debt discount attributable to warrants (1,323,986 ) (1,645,749 ) Total credit facilities and long term debts, net of discounts 60,026,143 51,834,603 Less: current maturities Long term portion of credit facilities and long term debts $ 60,026,143 $ 51,834,603 |
Components of interest expense | Six Months Ended June 30, 2015 2014 Accrued PIK interest $ 634,919 $ 472,712 Amortization of OID 84,858 60,288 Interest and commitment fees 2,177,431 1,493,229 Amortization of debt issuance costs 190,780 145,307 Amortization of warrant costs 321,763 310,042 Less interest capitalized to the full cost pool of our proved oil & gas properties (295,331 ) (105,555 ) $ 3,114,420 $ 2,376,023 |
2. Basis of Presentation and 30
2. Basis of Presentation and Significant Accounting Policies (Details-Capitalized costs) - USD ($) | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
Total capitalized costs | $ 295,331 | $ 129,499 |
Certain Payroll and Other Internal Costs | ||
Total capitalized costs | 0 | 23,944 |
Capitalized Interest Costs | ||
Total capitalized costs | $ 295,331 | $ 105,555 |
2. Basis of Presentation and 31
2. Basis of Presentation and Significant Accounting Policies (Details Narrative) - USD ($) | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | |
Accounting Policies [Abstract] | |||||
Cash in excess of insured limits | $ 0 | $ 0 | $ 0 | ||
Unamortized balance of debt issuance costs | 510,239 | 510,239 | $ 701,019 | ||
Amortization of debt issuance costs charged to interest expense | 190,780 | $ 145,307 | |||
Website development costs capitalized | 56,660 | 56,660 | |||
Depreciation expense on website development costs | 257 | 9,443 | |||
Depreciation of Non-Oil and Gas Property and Equipment | 8,276 | 16,113 | |||
Impairment of oil and gas properties | $ 21,639,000 | $ 0 | 21,639,000 | 0 | |
Share-based compensation expense | 313,751 | 288,961 | |||
Amortization of warrant costs | $ 321,763 | $ 310,042 |
3. Dahl Federal Recognition (De
3. Dahl Federal Recognition (Details Narrative) - USD ($) | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Oil and gas revenues | $ 5,050,080 | $ 5,553,997 | $ 7,936,536 | $ 9,584,417 |
Production expenses | 1,153,663 | 595,591 | 2,143,520 | 1,103,054 |
Production taxes | 555,152 | $ 591,525 | 841,344 | $ 996,832 |
Dahl Federal | ||||
Capitalized well costs | 927,312 | 927,312 | ||
Oil and gas revenues | 1,295,966 | 1,295,966 | ||
Production expenses | 87,063 | 87,063 | ||
Production taxes | 143,948 | 143,948 | ||
Dahl Federal | Production prior to 2015 | ||||
Oil and gas revenues | 1,241,214 | 1,241,214 | ||
Production expenses | 75,359 | 75,359 | ||
Production taxes | 137,860 | 137,860 | ||
Dahl Federal | Dahl Federal production from Q1 2015. | ||||
Oil and gas revenues | 23,012 | 23,012 | ||
Production expenses | 8,088 | 8,088 | ||
Production taxes | $ 2,522 | $ 2,522 |
4. Property and Equipment (Deta
4. Property and Equipment (Details-Property and equipment) - USD ($) | Jun. 30, 2015 | Dec. 31, 2014 |
Oil and gas properties, full cost method: | ||
Evaluated costs | $ 124,205,553 | $ 112,418,105 |
Unevaluated costs, not subject to amortization or ceiling test | 1,258,138 | 591,121 |
Total Oil and Gas properties full cost method | 125,463,691 | 113,009,226 |
Other property and equipment | 139,004 | 139,004 |
Total property plant and equipment gross | 125,602,695 | 113,148,230 |
Less: Accumulated depreciation, amortization and depletion | (46,117,576) | (18,902,524) |
Total property and equipment, net | $ 79,485,119 | $ 94,245,706 |
4. Property and Equipment (De34
4. Property and Equipment (Details-Depreciation) - USD ($) | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Property and equipment: | ||||
Depletion of costs for evaluated oil and gas properties | $ 2,937,744 | $ 2,131,545 | $ 5,567,776 | $ 3,718,477 |
Depreciation and amortization of other property and equipment | 4,009 | 8,188 | 8,276 | 16,113 |
Total depreciation, amortization and depletion | 5,576,052 | 3,734,590 | ||
Impairment of oil and gas | $ 21,639,000 | $ 0 | $ 21,639,000 | $ 0 |
5. Oil and Gas Properties (Deta
5. Oil and Gas Properties (Details-Wells) - Wells | Jun. 30, 2015 | Jun. 30, 2014 |
Productive oil wells, gross | 291 | 207 |
Productive oil wells, net | 8.96 | 6.28 |
North Dakota | ||
Productive oil wells, gross | 286 | 206 |
Productive oil wells, net | 8.59 | 6.20 |
Montana | ||
Productive oil wells, gross | 5 | 1 |
Productive oil wells, net | 0.37 | 0.08 |
5. Oil and Gas Properties (De36
5. Oil and Gas Properties (Details-Development costs) - USD ($) | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
Extractive Industries [Abstract] | ||
Purchases of oil and gas properties and development costs for cash | $ 12,677,179 | $ 11,731,981 |
Purchase of oil and gas properties accrued at year-end | 9,203,387 | 7,855,023 |
Purchase of oil and gas properties accrued at the beginning of the year | (9,364,796) | (7,953,801) |
Advances to operators applied to development of oil and gas properties | 0 | 2,131,043 |
Capitalized asset retirement obligations | 41,695 | 40,712 |
Total purchase and development costs, oil and gas properties | $ 12,557,465 | $ 13,804,958 |
5. Oil and Gas Properties (De37
5. Oil and Gas Properties (Details Narrative) | 6 Months Ended | |
Jun. 30, 2015USD ($)aWells | Jun. 30, 2014USD ($)a | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | ||
Oil and gas acreage acquired | 9 | 200 |
Oil and gas properties acquired, cost | $ | $ 102,928 | $ 1,652,551 |
Oil and gas acreage sold | 9 | 490 |
Wellbores sold | Wells | 2 | |
Proceeds from oil and gas diverstitures | $ | $ 103,000 | $ 1,340,920 |
Oil and gas acres traded | 52 | |
Mineral acres acquired in trade | 40 | |
Cash paid with trade | $ | $ 20,000 | |
Undeveloped acreage expirations | 1,403 | |
Undeveloped agreage expirations carrying costs | $ | $ 1,355,794 |
6. Asset Retirement Obligatio38
6. Asset Retirement Obligation (Details) - USD ($) | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Asset retirement rollforward | ||||
Beginning Asset Retirement Obligation | $ 286,804 | $ 160,665 | ||
Liabilities incurred for new wells placed in production | 41,695 | 40,712 | ||
Accretion of discount on asset retirement obligations | $ 7,932 | $ 5,148 | 15,861 | 9,653 |
Ending asset retirement obligation | $ 344,360 | $ 211,030 | $ 344,360 | $ 211,030 |
7. Related Party (Details Narra
7. Related Party (Details Narrative) - USD ($) | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
Related Party Transactions [Abstract] | ||
Rent expense | $ 35,128 | $ 35,501 |
8. Derivative Instruments (Deta
8. Derivative Instruments (Details-Outstanding derivative contracts) - Jun. 30, 2015 | $ / Boebbl |
Crude Oil Swaps 1 [Member] | |
Outstanding derivative contracts Settlement Period | July 1, 2015 - December 31, 2015 |
Outstanding derivative contracts, amount of oil (in Barrels) | bbl | 12,000 |
Outstanding derivative contract, fixed price | 88.28 |
Crude Oil Swaps 2 [Member] | |
Outstanding derivative contracts Settlement Period | July 1, 2015 - December 31, 2015 |
Outstanding derivative contracts, amount of oil (in Barrels) | bbl | 10,500 |
Outstanding derivative contract, fixed price | 89.70 |
Crude Oil Swaps 3 [Member] | |
Outstanding derivative contracts Settlement Period | July 1, 2015 - December 31, 2015 |
Outstanding derivative contracts, amount of oil (in Barrels) | bbl | 6,000 |
Outstanding derivative contract, fixed price | 92.38 |
Crude Oil Swaps 4 [Member] | |
Outstanding derivative contracts Settlement Period | July 1, 2015 - December 31, 2015 |
Outstanding derivative contracts, amount of oil (in Barrels) | bbl | 15,000 |
Outstanding derivative contract, fixed price | 90.16 |
Crude Oil Swaps 5 [Member] | |
Outstanding derivative contracts Settlement Period | October 1, 2015 - December 31, 2015 |
Outstanding derivative contracts, amount of oil (in Barrels) | bbl | 36,000 |
Outstanding derivative contract, fixed price | 61.87 |
Crude Oil Swaps 6 [Member] | |
Outstanding derivative contracts Settlement Period | January 1, 2016 - June 30, 2016 |
Outstanding derivative contracts, amount of oil (in Barrels) | bbl | 45,000 |
Outstanding derivative contract, fixed price | 62.88 |
Crude Oil Swaps 7 [Member] | |
Outstanding derivative contracts Settlement Period | January 1, 2016 - December 31, 2016 |
Outstanding derivative contracts, amount of oil (in Barrels) | bbl | 60,000 |
Outstanding derivative contract, fixed price | 90.36 |
Crude Oil Swaps 8 [Member] | |
Outstanding derivative contracts Settlement Period | January 1, 2016 - December 31, 2016 |
Outstanding derivative contracts, amount of oil (in Barrels) | bbl | 24,000 |
Outstanding derivative contract, fixed price | 88.15 |
Crude Oil Swaps 9 [Member] | |
Outstanding derivative contracts Settlement Period | January 1, 2017 - December 31, 2017 |
Outstanding derivative contracts, amount of oil (in Barrels) | bbl | 78,000 |
Outstanding derivative contract, fixed price | 87.18 |
Crude Oil Costless Collars1 [Member] | |
Outstanding derivative contracts Settlement Period | July 1, 2015 - December 31, 2015 |
Outstanding derivative contracts, amount of oil (in Barrels) | bbl | 18,000 |
Outstanding derivative contracts Floor/Ceiling basis | NYMEX |
Crude Oil Costless Collars1 [Member] | Minimum [Member] | |
Outstanding derivative contract, fixed price | 75 |
Crude Oil Costless Collars1 [Member] | Maximum [Member] | |
Outstanding derivative contract, fixed price | 95.60 |
Crude Oil Costless Collars2 [Member] | |
Outstanding derivative contracts Settlement Period | January 1, 2016 June 30, 2016 |
Outstanding derivative contracts, amount of oil (in Barrels) | bbl | 10,002 |
Outstanding derivative contracts Floor/Ceiling basis | NYMEX |
Crude Oil Costless Collars2 [Member] | Minimum [Member] | |
Outstanding derivative contract, fixed price | 80 |
Crude Oil Costless Collars2 [Member] | Maximum [Member] | |
Outstanding derivative contract, fixed price | 89.50 |
8. Derivative Instruments (De41
8. Derivative Instruments (Details-Derivative Gains and Losses) - USD ($) | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Realized gain (loss) on derivatives | $ 847,198 | $ (262,719) | $ 1,980,619 | $ (378,882) |
Gain (loss) on the mark-to-market of derivatives | $ (1,956,155) | $ (881,124) | (1,588,826) | (1,095,159) |
Crude Oil Fixed Price Swap [Member] | ||||
Realized gain (loss) on derivatives | 1,589,818 | (378,882) | ||
Gain (loss) on the mark-to-market of derivatives | (1,161,398) | (912,071) | ||
Crude Oil Collars [Member] | ||||
Realized gain (loss) on derivatives | 390,801 | 0 | ||
Gain (loss) on the mark-to-market of derivatives | $ (427,428) | $ (183,088) |
8. Derivative Instruments (De42
8. Derivative Instruments (Details-Balance sheet derivatives) - USD ($) | Jun. 30, 2015 | Dec. 31, 2014 |
Commodity derivative assets | $ 5,990,919 | $ 7,579,745 |
Commodity derivative liabilities | 0 | 0 |
Gross amounts recognized | ||
Commodity derivative assets | 5,998,159 | 7,620,896 |
Commodity derivative liabilities | 0 | 0 |
Gross amounts offset on balance sheet | ||
Commodity derivative assets | (7,240) | (41,151) |
Commodity derivative liabilities | $ 0 | $ 0 |
8. Derivative Instruments (De43
8. Derivative Instruments (Details-Reconciliation of derivatives) - USD ($) | Jun. 30, 2015 | Dec. 31, 2014 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Derivative assets | $ 3,007,135 | $ 3,571,803 |
Noncurrent derivative assets | 2,983,784 | 4,007,942 |
Net amount of assets on the balance sheet | 5,990,919 | 7,579,745 |
Derivative liabilities | 0 | 0 |
Noncurrent derivative liabilities | 0 | 0 |
Net amounts of liabilities on the balance sheet | 0 | 0 |
Total derivative assets (liabilities), net | $ 5,990,919 | $ 7,579,745 |
8. Derivative Instruments (De44
8. Derivative Instruments (Details Narrative) - Jun. 30, 2015 | $ / Boebbl |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Total volume on open commodity swaps, barrels | bbl | 286,500 |
Weighted average price per barrel | 81.33 |
9. Fair Value of Financial In45
9. Fair Value of Financial Instruments (Details-Recurring basis) - USD ($) | Jun. 30, 2015 | Dec. 31, 2014 |
Assets | ||
Derivative Instruments | $ 5,990,919 | $ 7,579,745 |
Fair Value Inputs Level1 [Member] | ||
Assets | ||
Cash and cash Equivalents | 94,682 | |
Derivative Instruments | 0 | |
Total assets | 94,682 | |
Liabilities | ||
Revolving credit facilities | 0 | |
Total Liabilities | 0 | |
Total Assets and Liablilties | 94,682 | |
Fair Value Inputs Level2 [Member] | ||
Assets | ||
Cash and cash Equivalents | 0 | |
Derivative Instruments | 7,579,745 | |
Total assets | 7,579,745 | |
Liabilities | ||
Revolving credit facilities | 51,834,603 | |
Total Liabilities | 51,834,603 | |
Total Assets and Liablilties | (44,254,858) | |
Fair Value Inputs Level3 [Member] | ||
Assets | ||
Cash and cash Equivalents | 0 | |
Derivative Instruments | 0 | |
Total assets | 0 | |
Liabilities | ||
Revolving credit facilities | 0 | |
Total Liabilities | 0 | |
Total Assets and Liablilties | $ 0 | |
Fair Value, Measurements, Recurring [Member] | Fair Value Inputs Level1 [Member] | ||
Assets | ||
Cash and cash Equivalents | 214,583 | |
Derivative Instruments | 0 | |
Total assets | 214,583 | |
Liabilities | ||
Revolving credit facilities | 0 | |
Total Liabilities | 0 | |
Total Assets and Liablilties | 214,583 | |
Fair Value, Measurements, Recurring [Member] | Fair Value Inputs Level2 [Member] | ||
Assets | ||
Cash and cash Equivalents | 0 | |
Derivative Instruments | 5,990,919 | |
Total assets | 5,990,919 | |
Liabilities | ||
Revolving credit facilities | 60,026,143 | |
Total Liabilities | 60,026,143 | |
Total Assets and Liablilties | (54,035,224) | |
Fair Value, Measurements, Recurring [Member] | Fair Value Inputs Level3 [Member] | ||
Assets | ||
Cash and cash Equivalents | 0 | |
Derivative Instruments | 0 | |
Total assets | 0 | |
Liabilities | ||
Revolving credit facilities | 0 | |
Total Liabilities | 0 | |
Total Assets and Liablilties | $ 0 |
10. Revolving Credit Faciliti46
10. Revolving Credit Facilities and Long Term Debt (Details-Debt outstanding) - USD ($) | Jun. 30, 2015 | Dec. 31, 2014 |
Credit facilities outstanding | $ 61,692,005 | $ 53,907,086 |
Less: Unamortized OID | (341,876) | (426,734) |
Less: Unamortized debt discount attributable to warrants | (1,323,986) | (1,645,749) |
Total credit facilities and long term debts, net of discounts | 60,026,143 | 51,834,603 |
Less: current maturities | 0 | 0 |
Long term portion of credit facilities and long term debts | 60,026,143 | 51,834,603 |
Senior Revolving Credit Facility, Cadence Bank | ||
Credit facilities outstanding | 25,950,000 | 22,600,000 |
Subordinated Credit Agreement, Chambers | ||
Credit facilities outstanding | 30,000,000 | 30,000,000 |
PIK Interest on Subordinated Credit Agreement, Chambers | ||
Credit facilities outstanding | $ 1,942,005 | $ 1,307,086 |
10. Revolving Credit Faciliti47
10. Revolving Credit Facilities and Long Term Debt (Details-Interest expense) - USD ($) | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
Interest expense, debt | $ 3,114,420 | $ 2,376,023 |
Accrued PIK interest | ||
Interest expense, debt | 634,919 | 472,712 |
Amortization of OID | ||
Interest expense, debt | 84,858 | 60,288 |
Interest and commitment fees | ||
Interest expense, debt | 2,177,431 | 1,493,229 |
Amortization of debt issuance costs | ||
Interest expense, debt | 190,780 | 145,307 |
Amortization of warrant costs | ||
Interest expense, debt | 321,763 | 310,042 |
Interest capitalized | ||
Interest expense, debt | $ (295,331) | $ (105,555) |
10. Revolving Credit Faciliti48
10. Revolving Credit Facilities and Long Term Debt (Details Narrative) - USD ($) | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | |
Line of credit outstanding | $ 61,692,005 | $ 53,907,086 | |
Amortization of debt discount | 84,858 | $ 60,288 | |
Amortization of debt discounts, warrants | 321,763 | 310,042 | |
Unamortized balance of debt discount | 1,665,862 | 2,072,483 | |
Line of Credit [Member] | Senior Credit Facility | |||
Maximum borrowing capacity | $ 34,000,000 | ||
Line of credit maturity date | Jan. 15, 2017 | ||
Line of credit outstanding | $ 29,750,000 | 22,600,000 | |
Line of Credit [Member] | Subordinated Credit Facility | |||
Maximum borrowing capacity | $ 30,000,000 | ||
Line of credit maturity date | Jun. 30, 2017 | ||
Line of credit outstanding | $ 30,000,000 | 30,000,000 | |
Warrants issued with debt | 5,000,000 | ||
Warrant expiration date | Aug. 8, 2018 | ||
Amortization of debt discount | $ 84,858 | 60,288 | |
Unamortized balance of debt discount | 341,876 | 426,734 | |
Proceeds received from credit facility | 29,400,000 | ||
Line of Credit [Member] | Subordinated Credit Facility | Warrants | |||
Debt discount at time of issuance | 2,473,576 | ||
Amortization of debt discounts, warrants | 321,763 | $ 310,042 | |
Unamortized balance of debt discount | $ 1,323,986 | $ 1,645,749 |
11. Changes in Stockholders' 49
11. Changes in Stockholders' Equity (Details Narrative) - $ / shares | Jun. 30, 2015 | Dec. 31, 2014 |
Equity [Abstract] | ||
Preferred stock, par value (in Dollars per share) | $ 0.001 | $ 0.001 |
Preferred stock, shares authorized | 20,000,000 | 20,000,000 |
Common stock, par value (in Dollars per share) | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 500,000,000 | 500,000,000 |
12. Options (Details Narrative)
12. Options (Details Narrative) - USD ($) | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
Compensation expense | $ 313,751 | $ 288,961 |
Unamortized fair value of options | $ 1,658,790 | |
Options exercised | 0 | |
Options forfeited | 0 | |
Options | ||
Options granted | 0 | 0 |
13. Warrants (Details Narrative
13. Warrants (Details Narrative) - Warrants - USD ($) | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
Finance expense related to warrants | $ 321,763 | $ 310,042 |
Warrants granted | 0 | |
Warrants exercised | 0 |
14. Income Taxes (Details Narra
14. Income Taxes (Details Narrative) - USD ($) | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Income Tax Disclosure [Abstract] | ||||
Deferred tax liabilities | $ 13,000,127 | $ 13,000,127 | ||
Deferred tax assets, net | 3,918,360 | 3,918,360 | ||
Deferred tax assets, valuation allowance | (3,918,360) | (3,918,360) | ||
Net deferred tax assets (liabilities) | 0 | 0 | ||
Tax benefit | 5,957,649 | $ 305,715 | 6,593,040 | $ 589,738 |
Uncertain tax positions | $ 0 | $ 0 | ||
Effective tax rate | 25.00% |
15. Commitments and Contingen53
15. Commitments and Contingencies (Details Narrative) | Jun. 30, 2015USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
Commitment to AFE (approximately) | $ 4,400,000 |