Document And Entity Information
Document And Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Apr. 11, 2016 | Jun. 30, 2015 | |
Document Information [Line Items] | |||
Document Type | 10-K | ||
Amendment Flag | true | ||
Document Period End Date | Dec. 31, 2015 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | EnerJex Resources, Inc. | ||
Entity Central Index Key | 8,504 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Smaller Reporting Company | ||
Entity Public Float | $ 6 | ||
Trading Symbol | ENRJ | ||
Entity Common Stock, Shares Outstanding | 8,423,936 | ||
Amendment Description | This Amendment No. 1 on Form 10-K hereby amends the Annual Report on Form 10-K for the fiscal year ended December 31, 2015, which EnerJex Resources, Inc. (the “Company”) previously filed with the Securities and Exchange Commission on April 11, 2016. We are filing this amendment to include additional and expanded information required by regulations S-X and S-K in so far as it related to disclosures of the Company’s estimated quantities of proved reserves, previously reported in Form 10-K. The Company is also filing the XBRL files to reflect these changes in the Notes to Financial Statements, Part I – Items 1 and 2 Business and Properties, Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations. Except as expressly set forth herein, this Amendment No. 1 to Form 10-K does not reflect events occurring after the date of the original filing of the Form 10-K or modify or update any of the disclosures contained therein in any way. Accordingly, this Amendment No. 1 to Form 10-K should be read in conjunction with the original filing on Form 10-K and the Company’s other filings with the Securities and Exchange Commission. |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) | Dec. 31, 2015 | Dec. 31, 2014 |
Current Assets: | ||
Cash | $ 3,101,682 | $ 805,524 |
Accounts receivable | 977,488 | 1,278,509 |
Derivative receivable | 2,531,401 | 3,736,005 |
Inventory | 144,327 | 248,218 |
Marketable securities | 210,990 | 1,018,573 |
Deposits and prepaid expenses | 247,325 | 324,339 |
Total current assets | 7,213,213 | 7,411,168 |
Non-current assets: | ||
Fixed assets, net of accumulated depreciation of $1,658,073 and $1,945,607 | 1,995,010 | 2,404,703 |
Oil & gas properties using full cost accounting, net of accumulated DD&A of $14,935,386 and $13,827,347 | 11,706,939 | 64,263,272 |
Derivative receivable | 0 | 985,746 |
Other non-current assets | 919,239 | 993,207 |
Total non-current assets | 14,621,188 | 68,646,928 |
Total assets | 21,834,401 | 76,058,096 |
Current liabilities: | ||
Accounts payable | 1,142,842 | 3,042,835 |
Accrued liabilities | 1,131,057 | 1,060,926 |
Current portion of long term debt | 1,986,660 | 35,595 |
Total current liabilities | 4,260,559 | 4,139,356 |
Non-Current Liabilities: | ||
Asset retirement obligation | 3,091,478 | 2,906,093 |
Long-term debt | 16,625,000 | 23,011,660 |
Other long-term liabilities | 390,937 | 0 |
Total non-current liabilities | 20,107,415 | 25,917,753 |
Total liabilities | 24,367,974 | 30,057,109 |
Commitments and Contingencies | ||
Stockholders’ (Deficit) Equity: | ||
Common stock, $0.001 par value, 250,000,000 shares authorized; shares issued and outstanding - 8,423,936 at December 31, 2015 and 7,643,114 at December 31, 2014 | 8,424 | 7,643 |
Accumulated other comprehensive income | 0 | (552,589) |
Paid in capital | 68,848,944 | 63,825,998 |
Accumulated deficit | (71,391,881) | (17,280,817) |
Total stockholders’ (deficit) equity | (2,533,573) | 46,000,987 |
Total liabilities and stockholders’ (deficit) equity | 21,834,401 | 76,058,096 |
10% Series A Cumulative Redeemable Perpetual Preferred Stock [Member] | ||
Stockholders’ (Deficit) Equity: | ||
Preferred Stock Value | 938 | 752 |
Series B Convertible Preferred stock [Member] | ||
Stockholders’ (Deficit) Equity: | ||
Preferred Stock Value | $ 2 | $ 0 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) | Dec. 31, 2015 | Dec. 31, 2014 |
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | $ 1,658,073 | $ 1,945,607 |
Properties using full-cost accounting | $ 14,935,386 | $ 13,827,347 |
Common stock, par value | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 250,000,000 | 250,000,000 |
Common stock, shares issued | 8,423,936 | 7,643,114 |
Common stock, shares outstanding | 8,423,936 | 7,643,114 |
10% Series A Cumulative Redeemable Perpetual Preferred Stock [Member] | ||
Preferred stock, par value | $ 0.001 | $ 0.001 |
Preferred stock, shares authorized | 25,000,000 | 25,000,000 |
Preferred stock, shares issued | 938,248 | 751,815 |
Preferred Stock Shares Outstanding | 938,248 | 751,815 |
Series B Convertible Preferred stock [Member] | ||
Preferred stock, par value | $ 0.001 | |
Preferred stock, shares authorized | 1,764 | |
Preferred stock, shares issued | 1,764 | |
Preferred Stock Shares Outstanding | 1,764 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Crude oil revenues | $ 4,525,089 | $ 13,257,608 |
Natural gas revenues | 353,633 | 1,035,759 |
Total revenues | 4,878,722 | 14,293,367 |
Expenses: | ||
Direct operating costs | 4,501,940 | 6,762,248 |
Depreciation, depletion and amortization | 1,311,446 | 3,549,245 |
Impairment of oil and gas assets | 48,930,087 | 0 |
Professional fees | 680,860 | 987,229 |
Salaries | 1,927,552 | 1,479,688 |
Administrative expense | 636,459 | 790,572 |
Total expenses | 57,988,344 | 13,568,982 |
Income from operations | (53,109,622) | 724,385 |
Other income (expense): | ||
Interest expense | (1,293,407) | (1,305,194) |
Gain (loss) on mark to market of derivative contracts | (2,194,679) | 6,073,960 |
Other income (loss) | 4,675,854 | (919,527) |
Total other income (expense) | 1,187,768 | 3,849,239 |
(Loss) income before provision for income taxes | (51,921,854) | 4,573,624 |
Provision for income taxes | 0 | 0 |
Net (loss) income | (51,921,854) | 4,573,624 |
Net (loss) income | (51,921,854) | 4,573,624 |
Preferred dividends | (1,798,274) | (1,392,035) |
Net (loss) income attributable to common stockholders | $ (53,720,128) | $ 3,181,589 |
Net (loss) income per common share basic and diluted | $ (6.50) | $ 0.42 |
Weighted Average Shares | 8,265,716 | 7,492,007 |
Consolidated Statement of Stock
Consolidated Statement of Stockholders' Equity - USD ($) | Total | 10% Series A Preferred Stock [Member] | Series B Preferred Stock [Member] | Preferred Stock [Member] | Common Stock [Member] | Accumulated Other Comprehensive Income [Member] | Paid-in Capital [Member] | Retained Deficit [Member] |
Balance at Dec. 31, 2013 | $ 28,910,601 | $ 4,780 | $ 7,307 | $ (552,589) | $ 49,913,509 | $ (20,462,406) | ||
Balance (in shares) at Dec. 31, 2013 | 4,779,460 | 7,307,158 | ||||||
Stock issued for services | 234,654 | $ 17 | 234,637 | |||||
Stock issued for services (in shares) | 17,332 | |||||||
Stock based compensation | 326,579 | 326,579 | ||||||
Issuance of 10% series A cumulative preferred stock and retirement of legacy preferred stock | 13,347,564 | $ 752 | $ (4,780) | $ 319 | 13,351,273 | |||
Issuance of 10% series A cumulative preferred stock and retirement of legacy preferred stock (in shares) | 751,815 | (4,779,460) | 318,624 | |||||
Preferred stock dividends | (1,392,035) | (1,392,035) | ||||||
Net loss for the year | 4,573,624 | 4,573,624 | ||||||
Balance at Dec. 31, 2014 | 46,000,987 | $ 752 | $ 0 | $ 7,643 | (552,589) | 63,825,998 | (17,280,817) | |
Balance (in shares) at Dec. 31, 2014 | 751,815 | 0 | 7,643,114 | |||||
Dividend received from Oakridge Energy | 552,589 | 552,589 | ||||||
Stock issued for services | 24,000 | $ 3 | $ 18 | 23,979 | ||||
Stock issued for services (in shares) | 3,000 | 17,500 | ||||||
Stock based compensation | 396,124 | 396,124 | ||||||
Sale of common stock | 825,506 | $ 763 | 824,643 | |||||
Sale of common stock (in shares) | 763,322 | |||||||
Sale of series A preferred stock | 2,014,593 | $ 183 | 2,014,410 | |||||
Sale of series A preferred stock (in shares) | 183,433 | |||||||
Sale of series B preferred stock | 1,763,792 | $ 2 | 1,763,790 | |||||
Sale of series B preferred stock (in shares) | 1,764 | |||||||
Preferred stock dividends | (2,189,210) | (2,189,210) | ||||||
Net loss for the year | (51,921,854) | (51,921,854) | ||||||
Balance at Dec. 31, 2015 | $ (2,533,573) | $ 938 | $ 2 | $ 0 | $ 8,424 | $ 0 | $ 68,848,944 | $ (71,391,881) |
Balance (in shares) at Dec. 31, 2015 | 938,248 | 1,764 | 0 | 8,423,936 |
Consolidated Statement of Stoc6
Consolidated Statement of Stockholders' Equity (Parenthetical) | 12 Months Ended |
Dec. 31, 2014 | |
10% Series A Preferred Stock [Member] | |
Preferred Stock, Dividend Rate, Percentage | 10.00% |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Cash flows from operating activities | ||
Net (loss) income | $ (51,921,854) | $ 4,573,624 |
Depreciation, depletion and amortization | 1,311,446 | 3,549,245 |
Impairment of oil and gas assets | 48,930,087 | 0 |
Stock, options and warrants issued for services | 420,103 | 638,171 |
Accretion of asset retirement obligation | 257,712 | 255,836 |
Settlement of asset retirement obligations | (2,244) | (102,930) |
(Gain) loss on derivatives | 2,190,350 | (6,073,101) |
Loss on sale of fixed assets | 13,661 | 9,738 |
Adjustments to reconcile net (loss) income (used in) provided by operating activities: | ||
Accounts receivable | 301,021 | 1,183,237 |
Inventory | 103,891 | (9,424) |
Deposits and prepaid expenses | 77,014 | (27,282) |
Accounts payable | (1,899,993) | 618,826 |
Accrued liabilities | 70,131 | (1,973,941) |
Cash flows (used in) provided by operating activities | (148,675) | 2,641,999 |
Cash flows from investing activities | ||
Purchase of fixed assets | (7,876) | (298,903) |
Oil and gas properties additions | (251,821) | (7,095,865) |
Sale of oil and gas properties | 2,867,305 | 987,939 |
Proceeds from sale of fixed assets | 33,142 | 1,250 |
Dividend received from Oakridge Energy | 1,360,172 | 0 |
Cash flows provided by (used in) investing activities | 4,000,922 | (6,405,579) |
Cash flows from financing activities | ||
Proceeds from sale of stock | 4,603,812 | 13,347,564 |
Repayments of long-term debt | (4,935,595) | (14,035,595) |
Borrowings on long-term debt | 500,000 | 5,500,000 |
Preferred stock dividends paid | (1,798,274) | (1,392,035) |
Deferred financing costs | 73,968 | (159,026) |
Cash flows (used in) provided by financing activities | (1,556,089) | 3,260,908 |
Increase (decrease) in cash and cash equivalents | 2,296,158 | (502,672) |
Cash and cash equivalents, beginning | 805,524 | 1,308,196 |
Cash and cash equivalents, end | 3,101,682 | 805,524 |
Supplemental disclosures: | ||
Interest paid | 840,513 | 741,757 |
Income taxes paid | 0 | 0 |
Non-cash investing and financing activities: | ||
Share-based payments issued for services | 420,103 | 638,171 |
Preferred dividends payable | $ 390,936 | $ 0 |
Summary of Accounting Policies
Summary of Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Summary of Accounting Policies | Note 1 - Summary of Accounting Policies Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States. Our operations are considered to fall within a single industry segment, which are the acquisition, development, exploitation and production of crude oil and natural gas properties in the United States. Our consolidated financial statements include our wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated upon consolidation. Certain reclassifications have been made to the prior year financial statements to conform to the current year presentation. We are an independent energy company engaged in the business of producing and selling crude oil and natural gas. The crude oil and natural gas is obtained primarily by the acquisition and subsequent exploration and development of mineral leases. Development and exploration may include drilling new exploratory or development wells on these leases. These operations are conducted primarily in Kansas, Colorado, Nebraska and Texas. The preparation of consolidated 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates included in the consolidated financial statements are: (1) oil and gas revenues and reserves; (2) depreciation, depletion and amortization; (3) valuation allowances associated with income taxes (4) accrued assets and liabilities; (5) stock-based compensation; (6) asset retirement obligations, (7) valuation of derivative instruments and (8) impairment of oil and gas assets. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates. Actual results could differ from those estimates. Trade accounts receivable are recorded at the invoiced amount and do not bear any interest. We regularly review receivables to insure that the amounts will be collected and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Inventory Inventories are comprised of crude oil held in storage and materials and supplies used in field operations. Crude oil inventories are valued at lower of cost or market, on a first-in, first out basis. Material and supplies are valued at lower of cost or market, based upon specific cost or by using a weighted average cost. Share-Based Payments The value we assign to the options and warrants that we issue is based on the fair market value as calculated by the Black-Scholes pricing model. To perform a calculation of the value of our options and warrants, we determine an estimate of the volatility of our stock. We need to estimate volatility because there has not been enough trading of our stock to determine an appropriate measure of volatility. We believe our estimate of volatility is reasonable, and we review the assumptions used to determine this whenever we issue new equity instruments. Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax returns or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted. We routinely assess the reliability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset is reduced by a valuation allowance. In addition we routinely assess uncertain tax positions, and accrue for tax positions that are not more-likely-than-not to be sustained upon examination by taxing authorities. We follow guidance in Topic 740 of the Codification for its accounting for uncertain tax positions. Topic 740 prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, we determine whether it is more-likely-than-not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based solely on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. We have no liability for unrecognized tax benefits recorded as of December 31, 2015 and 2014. Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statement of operations or consolidated balance sheet as of December 31, 2015. In addition, we do not believe that there are any positions for which it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease within the next twelve months. We recognize related interest and penalties as a component of income tax expense. Tax years open for audit by federal tax authorities as of December 31, 2015 are the years ended December 31, 2012, 2013 and 2014. Tax years ending prior to 2012 are open for audit to the extent that net operating losses generated in those years are being carried forward or utilized in an open year. Accounting guidance establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop those assumptions. Additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy. We incorporate a credit risk assumption into the measurement of certain assets and liabilities. We consider all highly liquid investment instruments purchased with original maturities of three months or less to be cash equivalents for purposes of the consolidated statements of cash flows and other statements. We maintain cash on deposit, which, can exceeds federally insured limits. We have not experienced any losses on such accounts and believe we are not exposed to any significant credit risk on cash and equivalents. Oil and gas revenues are recognized net of royalties when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collection of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met. Property and equipment are recorded at cost. At December 31, 2015, Fixed Assets consisted of vehicles of $ 354,886 552,288 23,069 2,722,839 328,659 478,578 13,342 837,494 At December 31, 2014, Fixed Assets consisted of vehicles $ 967,483 608,061 23,069 2,751,697 697,042 494,333 9,386 744,846 Depreciation is determined by the use of the straight-line method of accounting using the estimated lives of the assets ( 3 15 Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt utilizing the straight-line method of amortization over the estimated life of the debt. We follow the full cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities. Proved properties are amortized using the units of production method (UOP). Currently we only have operations in the United States of America. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the cost of these reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A), estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs, less related salvage value. The cost of unproved properties are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed into service. Geological and geophysical costs not associated with specific properties are recorded as proved property immediately. Unproved properties are reviewed for impairment quarterly. Impairment of long-lived assets is recorded when indications of impairment are present. Impairment is indicated when the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying value. The carrying value of the assets is then reduced to their estimated fair value that is measured based on an estimate of future discounted cash flows. Under the full-cost-method of accounting, the net book value of oil and gas properties, less deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is (a) the present value of future net revenues computed by applying current prices of oil & gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil & gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of 10 percent and assuming continuation of existing economic conditions plus plus less Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the statement of operations. The ceiling calculation is performed quarterly. For the year ended December 31, 2015 impairments of $ 16,401,376 11,421,613 9,720,983 11,386,115 Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25%) of our reserve quantities are sold, in which case a gain or loss is recognized in income. In 2015 the Company sold its Cherokee project assets located in Eastern Kansas for net proceeds of $ 2,867,305 6.7 The asset retirement obligation relates to the plug and abandonment costs when our wells are no longer useful. We determine the value of the liability by obtaining quotes for this service and estimate the increase we will face in the future. We then discount the future value based on an intrinsic interest rate that is appropriate for us. If costs rise more than what we have expected there could be additional charges in the future, however, we monitor the costs of the abandoned wells and we will adjust this liability if necessary. For the years ended December 31, 2015, and 2014 we sold our produced crude oil to ARM Energy Management, LLC, Coffeyville Resources Inc., Plains Marketing, L.P., MV Purchasing and Sunoco Logistics Inc. on a month-to-month basis and we sold our produced natural gas to United Energy Trading and Western Operating Company. The Company classifies its marketable equity securities as available-for-sale and they are carried at fair market value, with the unrealized gains and losses included in accumulated other comprehensive income and reported in stockholders’ equity. The difference between historical cost and market totaled $ 552,589 1,360,172 210,990 Basic net income per share is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect, in periods in which they have a dilutive effect, the impact of common shares issuable upon exercise of stock options and warrants and conversion of convertible debt that are not deemed to be anti-dilutive. The dilutive effect of the outstanding stock options and warrants is computed using the treasury stock method. For the year ended December 31, 2015, diluted n et loss per share did not include the effect of 298,664 For the year ended December 31, 2014, diluted net income per share did not include the effect of 231,332 Certain reclassifications have been made to prior periods to conform to current presentations. The Company does not believe there are any recently issued, but not yet effective; accounting standards that would have a significant impact on the Company’s financial position or results of operations. |
Going Concern
Going Concern | 12 Months Ended |
Dec. 31, 2015 | |
Going Concern Disclosure [Abstract] | |
Going Concern Disclosure [Text Block] | Note 2 - Going Concern The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. On October 3, 2011, the Company, entered into an Amended and Restated Credit Agreement with Texas Capital Bank, and other financial institutions and banks (“TCB” or “Bank”) that may become a party to the Credit Agreement from time to time. The facilities provided under the Amended and Restated Credit Agreement was to be used to refinance a prior outstanding revolving loan facility with TCB dated July 3, 2008, and for working capital and general corporate purposes. On August 15, 2014 the Company entered into an Eighth Amendment to the Amended and Restated Credit Agreement. Among other things the Eighth Amendment extended the maturity of the Agreement by three years to October 3, 2018. On August 12, 2015, the Company entered into a Tenth Amendment to the Amended and Restated Credit Agreement. Among other things the Tenth Amendment established the requirement of monthly borrowing base reductions commencing September 1, 2015 and continuing on the first of each month thereafter. On April 1, 2016 the Company informed the Bank that it would cease making the mandatory monthly borrowing base reduction payments and did not make the required April 1, 2016 payment. The Company made its mandatory quarterly interest payment on April 6, 2016 and on April 7, 2016 entered into a Forbearance Agreement whereby the Bank agreed to not exercise remedies and rights afforded it under the Amended and Restated Credit Agreement for thirty days. The thirty day period will be used by the Company to pursue strategic alternatives. The Company accesses a number of data bases and utilizes several consultants to monthly prepare commodity price projections used in its cash forecasting models. The models indicate it will have sufficient cash to satisfy obligation as they become due through the end of the first quarter of 2017, if it ceases to make the principle reduction called for by the Tenth Amendment entered into by the Company on August 12, 2015. If actual commodity prices are less than forecasted the Company would not have enough cash to meet obligations as they become due. Should this occur the Company could suspend quarterly interest payments, restructure, amend or refinance existing debt through private options or seek a protected reorganization under chapter 11 of the U.S. federal bankruptcy code. This factor raises substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. |
Equity Transactions
Equity Transactions | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Equity Transactions | Note 3 - Equity Transactions Stock transactions in fiscal year ended December 31, 2015 On March 13, 2015, the Company issued in a registered offering 763,547 709,812 521.62076 298,069 1,771,428 9.99 The Preferred Stock has a liquidation preference of $ 1,000 571 2.75 On May 13, 2015, the Company sold 183,433 10 12.50 2.3 The offering was made pursuant to a registration statement on Form S-3 (File No. 333-199030) previously filed and declared effective by the U.S. Securities and Exchange Commission (SEC). Stock transactions in fiscal year ended December 31, 2014 In 2014, 7,707 59,298 9,625 17,500 175,356 Effective after the close of trading in EnerJex common stock on May 30, 2014, the Company affected a 1-for-15 reverse stock split, by which each share of EnerJex common stock was reclassified, and changed into 1/15th of a fully paid and non-assessable share of common stock. In lieu of fractions of a share, the Company paid to holders of fractions of a share cash equal to $11.25 per share On June 16, 2014, we adopted the Amended and Restated Certificate of Designation modifying the terms of our then-existing Series A preferred stock. Concurrently with filing of that Amended and Restated Certificate of Designation, the holders of our existing Series A preferred stock exchanged each outstanding share of such existing Series A preferred stock for (i) a number of shares of our common stock into which such Series A preferred stock was then convertible immediately prior to the exchange (318,630 shares in the aggregate), and (ii) 112,658 shares of Series A preferred stock which was equal to the quotient determined by dividing (x) that portion of the holder’s original Series A preferred stock purchase price that had not yet been paid in dividends, by (y) $23.75. On June 20, 2014, we closed an underwritten initial public offering of 639,157 23.75 15,179,938 1,832,374 13,347,564 Effective September 30, 2014 the Board of Directors approved the retirement of 383,333 2,551,000 Option transactions Officers (including officers who are members of the Board of Directors), directors, employees and consultants are eligible to receive options under our stock option plans. We administer the stock option plans and we determine those persons to whom options will be granted, the number of options to be granted, the provisions applicable to each grant and the time periods during which the options may be exercised. No options may be granted more than ten years after the date of the adoption of the stock option plans. Each option granted under the stock option plans will be exercisable for a term of not more than ten years after the date of grant. Certain other restrictions will apply in connection with the plans when some awards may be exercised. In the event of a change of control (as defined in the stock option plans), the vesting date on which all options outstanding under the stock option plans may first be exercised will be accelerated. Generally, all options terminate 90 days after a change of control. Stock Incentive Plan The Board of Directors approved the EnerJex Resources, Inc. Stock Option Plan on August 1, 2002 (the “2002-2003 Stock Option Plan”). Originally, the total number of options that could be granted under the 2002-2003 Stock Option Plan was not to exceed 26,666 66,666 83,333 On December 31, 2010 we granted 60,000 6.00 5 307,751 76,938 2013 Stock Incentive Plan The Board and stockholders approved the adoption of the 2013 Stock Incentive Plan (“Plan”). The Plan reserves 333,300 In 2015, we granted 67,332 295,932 9.85 2.00 70 72 0 1.41 In 2014, we granted 2,367 12,178 10.50 7.95 72 0 We expensed $ 374,433 420,103 76,938 A summary of stock options is as follows: Weighted Ave. Weighted Ave. Options Exercise Price Warrants Exercise Price Outstanding January 1, 2014 231,133 $ 9.36 $ Granted 2,367 10.50 Cancelled (2,168) (10.50) Exercised - - - - Outstanding December 31, 2014 231,332 $ 9.33 - $ - Granted 67,332 1,904,286 2.75 Cancelled (10,333) (10.50) - - Exercised - - Outstanding December 31, 2015 288,331 $ 10.17 1,904,286 $ 2.75 The number of options that were vested at December 31, 2015 was 231,629 56,702 |
Asset Retirement Obligation
Asset Retirement Obligation | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligation | Note 4 - Asset Retirement Obligation Asset retirement obligations, January 1, 2014 $ 2,687,801 Liabilities incurred during the period 65,385 Liabilities settled during the year (102,929) Accretion 255,836 Asset retirement obligations, December 31, 2014 $ 2,906,093 Release of liabilities associated with the sale of oil properties (70,083) Liabilities settled during the year (2,244) Accretion 257,712 Asset retirement obligations, December 31, 2015 $ 3,091,478 |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2015 | |
Long-Term Debt [Abstract] | |
Long-Term Debt | Note 5 - Long-Term Debt Senior Secured Credit Facility On October 3, 2011, the Company, DD Energy, Inc., EnerJex Kansas, Inc., Black Sable Energy, LLC and Working Interest, LLC (“Borrowers”) entered into an Amended and Restated Credit Agreement with Texas Capital Bank, and other financial institutions and banks that may become a party to the Credit Agreement from time to time. The facilities provided under the Amended and Restated Credit Agreement are to be used to refinance Borrowers prior outstanding revolving loan facility with Bank, dated July 3, 2008, and for working capital and general corporate purposes. At our option, loans under the facility will bear stated interest based on the Base Rate plus Base Rate Margin, or Floating Rate plus Floating Rate Margin (as those terms are defined in the Credit Agreement). The Base Rate will be, for any day, a fluctuating rate per annum equal to the higher of (a) the Federal Funds Rate plus 0.50 0.00 0.75 2.25 3.00 We entered into a First Amendment to Amended and Restated Credit Agreement and Second Amended and Restated Promissory Note in the amount of $ 50,000,000 On August 31, 2012, we entered into a Second Amendment to Amended and Restated Credit Agreement with Texas Capital Bank. The Second Amendment: (i) increased the borrowing base to $ 7,000,000 3.75 On November 2, 2012, we entered into a Third Amendment to Amended and Restated Credit Agreement with Texas Capital Bank. The Third Amendment (i) increased the borrowing base to $ 12,150,000 On January 24, 2013, we entered into a Fourth Amendment to Amended and Restated Credit Agreement, which was made effective as of December 31, 2012 with Texas Capital Bank. The Fourth Amendment reflects the following changes: (i) the Bank consented to the restructuring transactions related to the dissolution of Rantoul Partners, and (ii) the Bank terminated a Limited Guaranty, as defined in the Credit Agreement, executed by Rantoul Partners in favor of the Bank On April 16, 2013, the Bank increased our borrowing base to $ 19.5 On September 30, 2013, the Company entered into a Fifth Amendment to the Amended and Restated Credit Agreement. The Fifth Amendment reflects the following changes: (i) an expanded principal commitment amount of the Bank to $ 100,000,000 38,000,000 3.30 On November 19, 2013, we entered into a Sixth Amendment to the Amended and Restated Credit Agreement. The Sixth Amendment reflects the following changes: (i) the addition of Iberia Bank as a participant in our credit facility, and (ii) a technical correction to our covenant calculations. On May 22, 2014, we entered into a Seventh Amendment to the Amended and Restated Credit Agreement. The Seventh Amendment reflects the Bank’s consent to our issuance of up to 850,000 10 On August 15, 2014 we entered into an Eighth Amendment to the Amended and Restated Credit Agreement. The Eighth Amendment reflects the following changes: (i) the borrowing base was increased from $ 38 40 On April 29, 2015, we entered into a Ninth Amendment to the Amended and Restated Credit Agreement. In the Ninth Amendment, the Banks (i) re-determined the Borrowing Base based upon the recent Reserve Report dated January 1, 2015, (ii) imposed affirmative obligations on the Company to use a portion of proceeds received with regard to future sales of securities or certain assets to repay the loan, (iii) consented to non-compliance by the Company with certain terms of the Credit Agreement, (iv) waived certain provisions of the Credit Agreement, and (v) agreed to certain other amendments to the Credit Agreement. On May 1, 2015, the Borrowers and the Banks entered into a Letter Agreement to clarify that up to $ 1,000,000 On August 12, 2015, we entered into a Tenth Amendment to the Amended and Restated Credit Agreement. The Tenth Amendment reflects the following changes: (i) allow the Company to sell certain oil assets in Kansas, (ii) allow for approximately $ 1,300,000 1,500,000 On November 13, 2015, the Company entered into a Eleventh Amendment to the Amended and Restated Credit Agreement. The Eleventh Amendment reflects the following changes: (i) waived certain provisions of the Credit Agreement, (ii) suspend certain hedging requirements, and (iii) to make certain other amendments to the Credit Agreement. 18,600,000 18,600,000 4.3 3.3 October 3, 2018 |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Note 6 - Commitments and Contingencies Rent expense for the years ended December 31, 2015 and 2014 was approximately $ 149,000 159,000 147,000 145,000 91,000 77,000 We, as a lessee and operator of oil and gas properties, are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject to the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. As of December 31, 2015, we have no reserve for environmental remediation and are not aware of any environmental claims. As of December 31, 2015, the Company has an outstanding irrevocable letter of credit in the amount of $ 50,000 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Tax | Note 7 - Income Taxes There was no current or deferred income tax expense (benefit) for the years ended December 31, 2015 and December 31, 2014. Year Ended December 31, 2015 2014 Statutory tax rate 35.00 % 35.00 % State tax rate, net of federal tax 1.90 % 1.37 % Other permanent items 0.00 % 0.05 % Change in valuation allowance (36.90) % (36.42) % Effective tax rate 0.00 % 0.00 % Year Ended December 31, 2015 2014 Non-current deferred tax asset: Oil and gas costs and long-lived assets $ 14,513,571 $ (1,038,092) Derivative instruments 934,340 (1,717,301) Net operating loss carry-forward 29,532,954 25,915,146 Valuation allowance (44,980,865) (23,159,753) Net deferred tax asset (liability) $ - $ - At December 31, 2015, we have a net operating loss carry forward of approximately $ 81 2021-2036 The Company incurred a change of control as defined by the Internal Revenue Code. Accordingly, the rules will limit the utilization of the Company’s net operating losses. The limitation is determined by multiplying the value of the stock immediately before the ownership change by the applicable long-term exempt rate. It is estimated that approximately $ 40.9 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Measurements [Abstract] | |
Fair Value Measurements | Note 8 - Fair Value Measurements We hold certain financial assets which are required to be measured at fair value on a recurring basis in accordance with the Statement of Financial Accounting Standard No. 157, “Fair Value Measurements” Level 1. Valuations based on quoted prices in active markets for identical assets or liabilities that an entity has the ability to access. We believe receivables, payables and our debt approximate fair value at December 31, 2015. Level 2. Valuations based on quoted prices for similar assets or liabilities, quoted prices for identical assets or liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable data for substantially the full term of the assets or liabilities. We consider the derivative liability to be Level 2. We determine the fair value of the derivative liability utilizing various inputs, including NYMEX price quotations and contract terms. Level 3. Valuations based on inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. We consider the marketable securities to be a Level 3. Fair Value Measurement Level 1 Level 2 Level 3 Crude oil contracts $ - $ 2,531,401 $ - Marketable securities $ - $ - $ 210,990 |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments [Abstract] | |
Derivative Instruments | Note 9 - Derivative Instruments We have entered into certain derivative or physical arrangements with respect to portions of our crude oil production to reduce our sensitivity to volatile commodity prices and/or to meet hedging requirements under our Credit Facility. We believe that these derivative arrangements, although not free of risk, allow us to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of crude oil. Moreover, our derivative arrangements apply only to a portion of our production. We have an Inter-creditor Agreement in place between the Company; our counterparties, BP Corporation North America, Inc. and Cargill Incorporated and our agent, Texas Capital Bank, N.A., which allows Texas Capital Bank to also act as agent for the counterparties for the purpose of holding and enforcing any liens or security interests resulting from our derivative arrangements. Therefore, we generally are not required to post additional collateral, including cash. Term Monthly Volumes (1) Price/Bbl Fair Value Deferred premium put 1/16-6/16 9,000 Bbls $ 85.00 $ 2,170,912 Deferred premium put 7/16-12/16 5,000 Bbls $ 60.00 360,489 $ 2,531,401 (1) The total fair value of derivative contracts is shown in both current and non-current assets on the balance sheet. We recorded a loss related to our derivative contracts for the year ended December 31, 2015 of $ 2,194,679 6,073,960 |
Net Income Per Common Share
Net Income Per Common Share | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | Note 10 - Net Income Per Common Share The Company reports earnings per share in accordance with ASC Topic 260-10, “ Earnings per Share.” |
Impairment of Oil and Gas Prope
Impairment of Oil and Gas Properties | 12 Months Ended |
Dec. 31, 2015 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Impairment of Oil and Gas Properties | Note 11 - Impairment of Oil and Gas Properties Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter on its proved oil and natural gas assets within each separate cost center. All of the Company’s costs are included in one cost center because all of the Company’s operations are located in the United States. 52.73 2.76 59.21 3.06 71.68 3.39 78.82 3.74 9.7 11.4 16.4 |
Other Income
Other Income | 12 Months Ended |
Dec. 31, 2015 | |
Other Income and Expenses [Abstract] | |
Other Income and Other Expense Disclosure | Note 12 - Other Income Year ended Year ended December 31, December 31, 2015 2014 Realized gain (loss) clearing of derivative contracts $ 4,662,012 $ (914,694) Loss on sale of fixed assets (13,661) (9,738) Miscellaneous income 27,105 4,004 Interest income 398 901 Other Income $ 4,675,854 $ (919,527) |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2015 | |
Subsequent Events [Abstract] | |
Subsequent Events | Note 13 - Subsequent Events On October 3, 2011, the Company, entered into an Amended and Restated Credit Agreement with Texas Capital Bank, and other financial institutions and banks (“TCB” or “Bank”) that may become a party to the Credit Agreement from time to time. The facilities provided under the Amended and Restated Credit Agreement was to be used to refinance a prior outstanding revolving loan facility with TCB dated July 3, 2008, and for working capital and general corporate purposes. On August 15, 2014 the Company entered into an Eighth Amendment to the Amended and Restated Credit Agreement. Among other things the Eighth Amendment extended the maturity of the Agreement by three years to October 3, 2018. On August 12, 2015, the Company entered into a Tenth Amendment to the Amended and Restated Credit Agreement. Among other things the Tenth Amendment established the requirement of monthly borrowing base reductions commencing September 1, 2015 and continuing on the first of each month thereafter. On April 1, 2016 the Company informed the Bank that it would cease making the mandatory monthly borrowing base reduction payments and did not make the required April 1, 2016 payment. The Company made its mandatory quarterly interest payment on April 6, 2016 and on April 7, 2016 entered into a Forbearance Agreement whereby the Bank agreed to not exercise remedies and rights afforded it under the Amended and Restated Credit Agreement for thirty days. The thirty day period will be used by the Company to pursue strategic alternatives. The Company accesses a number of data bases and utilizes several consultants to monthly prepare commodity price projections used in its cash forecasting models. The models indicate it will have sufficient cash to satisfy obligation as they become due through the end of the first quarter of 2017, if it ceases to make the principle reduction called for by the Tenth Amendment entered into by the Company on August 12, 2015. If actual commodity prices are less than forecasted the Company would not have enough cash to meet obligations as they become due. Should this occur the Company could suspend quarterly interest payments, restructure, amend or refinance existing debt through private options or seek a protected reorganization under chapter 11 of the U.S. federal bankruptcy code. |
Supplemental Oil and Gas Reserv
Supplemental Oil and Gas Reserve Information (Unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Oil Reserve Information [Abstract] | |
Supplemental Oil and gas Reserve Information (Unaudited) | Note 14 - Supplemental Oil and Gas Reserve Information (Unaudited) Results of operations from oil and gas producing activities The following table shows the results of operations from the Company’s oil and gas producing activities. Results of operations from these activities are determined using historical revenues, production costs and depreciation and depletion. The results of operations from the Company’s oil and gas producing activities below exclude non-oil and gas revenues, general and administrative expenses, interest income and interest expense. Year Ended Year Ended December 31, December 31, 2015 2014 Production revenues $ 4,878,722 $ 14,293,368 Production costs (4,501,940) (6,762,248) Depletion and depreciation (1,108,039) (3,259,442) Income tax 255,940 (1,495,087) Results of operations for producing activities $ (475,317) $ 2,776,591 Capitalized costs Year Ended Year Ended December 31, December 31, 2015 2014 Properties subject to amortization $ 26,642,325 $ 78,090,619 Accumulated depletion (14,935,386) (13,827,347) Net capitalized costs $ 11,706,939 $ 64,263,272 Year Ended Year Ended December 31, December 31, 2015 2014 Acquisition of properties $ 85,895 $ 1,017,698 Exploration costs - - Development costs 165,926 6,078,167 Net capitalized costs $ 251,821 $ 7,095,865 Estimated quantities of proved reserves Our ownership interests in estimated quantities of proved oil and gas reserves and changes in net proved reserves all of which are located in the United States are summarized below. Proved reserves are estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those that are expected to be recovered through existing wells with existing equipment and operating methods. Reserves are stated in barrels of oil equivalent. Geological and engineering estimates by Cobb & Associates, Inc. of proved oil and gas reserves at one point in time are highly interpretive, inherently imprecise and subject to ongoing revisions that may be substantial in amount. Proved Reserves (1) Total Proved Developed Proved Undeveloped Total Proved Total Proved Developed Proved Undeveloped Total Proved Beginning Crude Oil BBL’s 2,214,038 740,700 2,954,738 3,084,238 1,368,600 4,452,838 Natural Gas Liquids BBL’s 89,250 - 89,250 38,950 - 38,950 Natural Gas MCF’s 4,469,845 3,667,314 8,137,159 3,818,065 4,059,900 7,877,965 Oil Equivalents BOE’s 3,048,261 1,351,919 4,400,180 3,759,412 2,045,188 5,804,600 Revisions of previous estimates Crude Oil BBL’s (629,480) (522,070) (1,151,550) (724,191) (627,900) (1,352,091) Natural Gas Liquids BBL’s (35,860) - (35,860) 56,919 - 56,919 Natural Gas MCF’s (1,085,542) (637,800) (1,723,342) 977,674 (392,586) 585,088 Oil Equivalents BOE’s (846,264) (628,370) (1,474,634) (504,326) (693,331) (1,197,657) Purchases of minerals in place Crude Oil BBL’s - - - 2,234 - 2,234 Natural Gas Liquids BBL’s - - - - Natural Gas MCF’s - - - - Oil Equivalents BOE’s - - - 2,234 - 2,234 Extensions and discoveries Crude Oil BBL’s - - - 2,226 - 2,226 Sales of minerals in place Crude Oil BBL’s (201,286) (15,746) (217,032) - - Production Crude Oil BBL’s (96,244) - (96,244) (150,469) - (150,469) Natural Gas Liquids BBL’s (6,045) - (6,045) (6,619) - (6,619) Natural Gas MCF’s (188,408) - (188,408) (325,894) - (325,894) Oil Equivalents BOE’s (133,690) - (133,690) (211,403) - (211,403) Ending Crude Oil BBL’s 1,287,028 202,884 1,489,912 2,214,038 740,700 2,954,738 Natural Gas Liquids BBL’s 47,345 - 47,345 89,250 - 89,250 Natural Gas MCF’s 3,195,895 3,029,514 6,225,409 4,469,845 3,667,314 8,137,159 Oil Equivalents BOE’s 1,867,041 707,819 2,574,860 3,048,261 1,351,919 4,400,180 (1) Proved developed reserves at December 31, 2015 consisted of approximately 71 29 1,867.0 76 24 3,048.3 707.8 1,351.9 The Company annually reviews its proved undeveloped reserves to ensure an appropriate plan for development exists. The Company books proved undeveloped reserves only if it plans to convert these reserves to proved developed producing reserves within five years from the date they were first booked. At December 31, 2015 proved undeveloped reserves were approximately 707.8 644.1 47.6 5.9 The calculation of proved undeveloped reserves requires the Company to make predictions regarding future acquisitions and discoveries and the impact they may have on the Company’s overall development plan of properties it currently owns. The development plan is revised to reflect changes in the oil and gas industry, including changing markets and prices, and new investment opportunities, and such revisions will result in changes to our proved undeveloped reserves. Consequently, the exact timing of capital expenditures will be heavily dependent upon the Company’s interpretation of market opportunities which are deeply influenced by projections of future commodity prices. Each year we will review our five year development plan to maximize the value of our investment in oil and gas assets and in turn maximize shareholder value. Estimated Conversion of CAPEX ($MM) MBOE’s 2016 0.0 0.0 2017 1,120.0 112.5 2018 1,162.8 89.6 2019 3,057.2 131.4 2020 561.7 374.3 For the year ended December 31, 2015 proved reserves decreased 1,825.3 133.7 7.3 1,691.6 40.00 46.1 42.2 1.37 586.6 42.9 522.1 65.6 1,347.9 637.8 29.7 262.4 For the year ended December 31, 2014 proved reserves decreased 1,404.4 211.4 15.1 1,193.0 724,000 628,000 1,352,091 163,000 57,000 65,000 In 2015 the Company invested approximately $ 250,000 These reduced expenditures were primarily in response to extremely low commodity prices. The Company has $ 7.4 3.7 5 Standardized measure of discounted future net cash flows Year Ended Year Ended December 31, December 31, 2015 2014 Future production revenue $ 74,087,130 $ 282,557,900 Future production costs (46,015,320) (101,119,500) Future development costs (5,901,660) (13,736,500) Future cash flows before income tax 22,170,150 167,701,900 Future income taxes - (4,211,005) Future net cash flows 22,170,150 163,490,895 10% annual discount for estimating of future cash flows (13,400,180) (100,787,044) Standardized measure of discounted net cash flows $ 8,769,970 $ 62,703,851 Changes in standardized measure of discounted future net cash flows The following is a summary of a standardized measure of discounted net future cash flows related to the Company’s proved oil and gas reserves. The information presented is based on a calculation of estimated proved reserves using discounted cash flows based on the 12-month average price for oil and gas calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period. The additions to estimated proved reserves from new discoveries and extensions could vary significantly from year to year. Year Ended Year Ended December 31, December 31, 2015 2014 Balance beginning of year $ 62,703,851 $ 81,447,656 Sales, net of production costs (491,055) (7,531,119) Net change in pricing and production costs (51,184,718) (19,087,068) Net change in future estimated development costs 7,834,840 6,281,385 Purchase of minerals in place - 190,502 Extensions and discoveries - 35,203 Sale of minerals in place (2,746,550) - Revisions (8,448,569) (25,498,141) Accretion of discount 16,770,190 27,098,964 Change in income tax (15,668,019) (233,531) Balance end of year $ 8,769,970 $ 62,703,851 |
Summary of Accounting Policies
Summary of Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States. Our operations are considered to fall within a single industry segment, which are the acquisition, development, exploitation and production of crude oil and natural gas properties in the United States. Our consolidated financial statements include our wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated upon consolidation. Certain reclassifications have been made to the prior year financial statements to conform to the current year presentation. |
Nature of Business | We are an independent energy company engaged in the business of producing and selling crude oil and natural gas. The crude oil and natural gas is obtained primarily by the acquisition and subsequent exploration and development of mineral leases. Development and exploration may include drilling new exploratory or development wells on these leases. These operations are conducted primarily in Kansas, Colorado, Nebraska and Texas. |
Use of Estimates in the Preparation of Financial Statements | Use of Estimates in the Preparation of Financial Statements The preparation of consolidated 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates included in the consolidated financial statements are: (1) oil and gas revenues and reserves; (2) depreciation, depletion and amortization; (3) valuation allowances associated with income taxes (4) accrued assets and liabilities; (5) stock-based compensation; (6) asset retirement obligations, (7) valuation of derivative instruments and (8) impairment of oil and gas assets. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates. Actual results could differ from those estimates. |
Trade Accounts Receivable | Trade Accounts Receivable Trade accounts receivable are recorded at the invoiced amount and do not bear any interest. We regularly review receivables to insure that the amounts will be collected and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. |
Inventory | Inventory Inventories are comprised of crude oil held in storage and materials and supplies used in field operations. Crude oil inventories are valued at lower of cost or market, on a first-in, first out basis. Material and supplies are valued at lower of cost or market, based upon specific cost or by using a weighted average cost. |
Share-Based Payments | Share-Based Payments The value we assign to the options and warrants that we issue is based on the fair market value as calculated by the Black-Scholes pricing model. To perform a calculation of the value of our options and warrants, we determine an estimate of the volatility of our stock. We need to estimate volatility because there has not been enough trading of our stock to determine an appropriate measure of volatility. We believe our estimate of volatility is reasonable, and we review the assumptions used to determine this whenever we issue new equity instruments. |
Income Taxes | Income Taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax returns or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted. We routinely assess the reliability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset is reduced by a valuation allowance. In addition we routinely assess uncertain tax positions, and accrue for tax positions that are not more-likely-than-not to be sustained upon examination by taxing authorities. |
Uncertain Tax Positions | Uncertain Tax Positions We follow guidance in Topic 740 of the Codification for its accounting for uncertain tax positions. Topic 740 prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, we determine whether it is more-likely-than-not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based solely on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. We have no liability for unrecognized tax benefits recorded as of December 31, 2015 and 2014. Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statement of operations or consolidated balance sheet as of December 31, 2015. In addition, we do not believe that there are any positions for which it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease within the next twelve months. We recognize related interest and penalties as a component of income tax expense. Tax years open for audit by federal tax authorities as of December 31, 2015 are the years ended December 31, 2012, 2013 and 2014. Tax years ending prior to 2012 are open for audit to the extent that net operating losses generated in those years are being carried forward or utilized in an open year. |
Fair Value Measurements | Fair Value Measurements Accounting guidance establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop those assumptions. Additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy. We incorporate a credit risk assumption into the measurement of certain assets and liabilities. |
Cash and Cash Equivalents | Cash and Cash Equivalents We consider all highly liquid investment instruments purchased with original maturities of three months or less to be cash equivalents for purposes of the consolidated statements of cash flows and other statements. We maintain cash on deposit, which, can exceeds federally insured limits. We have not experienced any losses on such accounts and believe we are not exposed to any significant credit risk on cash and equivalents. |
Revenue Recognition | Revenue Recognition Oil and gas revenues are recognized net of royalties when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collection of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met. |
Fixed Assets | Fixed Assets Property and equipment are recorded at cost. At December 31, 2015, Fixed Assets consisted of vehicles of $ 354,886 552,288 23,069 2,722,839 328,659 478,578 13,342 837,494 At December 31, 2014, Fixed Assets consisted of vehicles $ 967,483 608,061 23,069 2,751,697 697,042 494,333 9,386 744,846 Depreciation is determined by the use of the straight-line method of accounting using the estimated lives of the assets ( 3 15 |
Debt issue costs | Debt issue costs Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt utilizing the straight-line method of amortization over the estimated life of the debt. |
Oil & Gas Properties and Long-Lived Assets | Oil & Gas Properties and Long-Lived Assets We follow the full cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities. Proved properties are amortized using the units of production method (UOP). Currently we only have operations in the United States of America. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the cost of these reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A), estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs, less related salvage value. The cost of unproved properties are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed into service. Geological and geophysical costs not associated with specific properties are recorded as proved property immediately. Unproved properties are reviewed for impairment quarterly. Impairment of long-lived assets is recorded when indications of impairment are present. Impairment is indicated when the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying value. The carrying value of the assets is then reduced to their estimated fair value that is measured based on an estimate of future discounted cash flows. Under the full-cost-method of accounting, the net book value of oil and gas properties, less deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is (a) the present value of future net revenues computed by applying current prices of oil & gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil & gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of 10 percent and assuming continuation of existing economic conditions plus plus less Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the statement of operations. The ceiling calculation is performed quarterly. For the year ended December 31, 2015 impairments of $ 16,401,376 11,421,613 9,720,983 11,386,115 Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25%) of our reserve quantities are sold, in which case a gain or loss is recognized in income. In 2015 the Company sold its Cherokee project assets located in Eastern Kansas for net proceeds of $ 2,867,305 6.7 |
Asset Retirement Obligations | Asset Retirement Obligations The asset retirement obligation relates to the plug and abandonment costs when our wells are no longer useful. We determine the value of the liability by obtaining quotes for this service and estimate the increase we will face in the future. We then discount the future value based on an intrinsic interest rate that is appropriate for us. If costs rise more than what we have expected there could be additional charges in the future, however, we monitor the costs of the abandoned wells and we will adjust this liability if necessary. |
Major Purchasers | Major Purchasers For the years ended December 31, 2015, and 2014 we sold our produced crude oil to ARM Energy Management, LLC, Coffeyville Resources Inc., Plains Marketing, L.P., MV Purchasing and Sunoco Logistics Inc. on a month-to-month basis and we sold our produced natural gas to United Energy Trading and Western Operating Company. |
Marketable Securities Available for Sale | Marketable Securities Available for Sale The Company classifies its marketable equity securities as available-for-sale and they are carried at fair market value, with the unrealized gains and losses included in accumulated other comprehensive income and reported in stockholders’ equity. The difference between historical cost and market totaled $ 552,589 1,360,172 210,990 |
Net Income Per Common Share | Net Income Per Common Share Basic net income per share is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect, in periods in which they have a dilutive effect, the impact of common shares issuable upon exercise of stock options and warrants and conversion of convertible debt that are not deemed to be anti-dilutive. The dilutive effect of the outstanding stock options and warrants is computed using the treasury stock method. For the year ended December 31, 2015, diluted n et loss per share did not include the effect of 298,664 For the year ended December 31, 2014, diluted net income per share did not include the effect of 231,332 |
Reclassifications | Reclassifications Certain reclassifications have been made to prior periods to conform to current presentations. |
Recent Accounting Pronouncements Applicable to the Company | Recent Accounting Pronouncements Applicable to the Company The Company does not believe there are any recently issued, but not yet effective; accounting standards that would have a significant impact on the Company’s financial position or results of operations. |
Equity Transactions (Tables)
Equity Transactions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract] | |
Summary of Stock Options | A summary of stock options is as follows: Weighted Ave. Weighted Ave. Options Exercise Price Warrants Exercise Price Outstanding January 1, 2014 231,133 $ 9.36 $ Granted 2,367 10.50 Cancelled (2,168) (10.50) Exercised - - - - Outstanding December 31, 2014 231,332 $ 9.33 - $ - Granted 67,332 1,904,286 2.75 Cancelled (10,333) (10.50) - - Exercised - - Outstanding December 31, 2015 288,331 $ 10.17 1,904,286 $ 2.75 |
Asset Retirement Obligation (Ta
Asset Retirement Obligation (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation [Abstract] | |
Changes in Asset Retirement Obligations | The following shows the changes in asset retirement obligations: Asset retirement obligations, January 1, 2014 $ 2,687,801 Liabilities incurred during the period 65,385 Liabilities settled during the year (102,929) Accretion 255,836 Asset retirement obligations, December 31, 2014 $ 2,906,093 Release of liabilities associated with the sale of oil properties (70,083) Liabilities settled during the year (2,244) Accretion 257,712 Asset retirement obligations, December 31, 2015 $ 3,091,478 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Reconciliation of the Provision For Income Taxes to the Statutory Federal Rate | The following table sets forth a reconciliation of the provision for income taxes to the statutory federal rate: Year Ended December 31, 2015 2014 Statutory tax rate 35.00 % 35.00 % State tax rate, net of federal tax 1.90 % 1.37 % Other permanent items 0.00 % 0.05 % Change in valuation allowance (36.90) % (36.42) % Effective tax rate 0.00 % 0.00 % |
Significant Components of the Deferred Tax Assets and Liabilities | Significant components of the deferred tax assets and liabilities are as follows: Year Ended December 31, 2015 2014 Non-current deferred tax asset: Oil and gas costs and long-lived assets $ 14,513,571 $ (1,038,092) Derivative instruments 934,340 (1,717,301) Net operating loss carry-forward 29,532,954 25,915,146 Valuation allowance (44,980,865) (23,159,753) Net deferred tax asset (liability) $ - $ - |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Measurements [Abstract] | |
Variable to Fixed Price Commodity Swaps Derivative Instruments | Our derivative instruments consist of fixed price commodity swaps. Fair Value Measurement Level 1 Level 2 Level 3 Crude oil contracts $ - $ 2,531,401 $ - Marketable securities $ - $ - $ 210,990 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments [Abstract] | |
Derivative Contracts | The following derivative contracts were in place at December 31, 2015: Term Monthly Volumes (1) Price/Bbl Fair Value Deferred premium put 1/16-6/16 9,000 Bbls $ 85.00 $ 2,170,912 Deferred premium put 7/16-12/16 5,000 Bbls $ 60.00 360,489 $ 2,531,401 (1) |
Other Income (Tables)
Other Income (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Other Income and Expenses [Abstract] | |
Interest and Other Income | The following table depicts the components of other income for the years ended December 31, 2015 and December 31, 2014: Year ended Year ended December 31, December 31, 2015 2014 Realized gain (loss) clearing of derivative contracts $ 4,662,012 $ (914,694) Loss on sale of fixed assets (13,661) (9,738) Miscellaneous income 27,105 4,004 Interest income 398 901 Other Income $ 4,675,854 $ (919,527) |
Supplemental Oil and Gas Rese29
Supplemental Oil and Gas Reserve Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Oil Reserve Information [Abstract] | |
Results of operations from oil and gas producing activities | Income tax expense was determined by applying the statutory rates to pretax operating results. Year Ended Year Ended December 31, December 31, 2015 2014 Production revenues $ 4,878,722 $ 14,293,368 Production costs (4,501,940) (6,762,248) Depletion and depreciation (1,108,039) (3,259,442) Income tax 255,940 (1,495,087) Results of operations for producing activities $ (475,317) $ 2,776,591 |
Summarizes the Company’s Capitalized Costs | The following table summarizes the Company’s capitalized costs of oil and gas properties. Year Ended Year Ended December 31, December 31, 2015 2014 Properties subject to amortization $ 26,642,325 $ 78,090,619 Accumulated depletion (14,935,386) (13,827,347) Net capitalized costs $ 11,706,939 $ 64,263,272 |
Cost incurred in property acquisition, exploration and development activities | Cost incurred in property acquisition, exploration and development activities Year Ended Year Ended December 31, December 31, 2015 2014 Acquisition of properties $ 85,895 $ 1,017,698 Exploration costs - - Development costs 165,926 6,078,167 Net capitalized costs $ 251,821 $ 7,095,865 |
Estimated quantities of proved reserves | Although every reasonable effort is made to ensure that the reserve estimates are accurate, by their nature reserve estimates are generally less precise than other estimates presented in connection with financial statement disclosures. Proved Reserves (1) Total Proved Developed Proved Undeveloped Total Proved Total Proved Developed Proved Undeveloped Total Proved Beginning Crude Oil BBL’s 2,214,038 740,700 2,954,738 3,084,238 1,368,600 4,452,838 Natural Gas Liquids BBL’s 89,250 - 89,250 38,950 - 38,950 Natural Gas MCF’s 4,469,845 3,667,314 8,137,159 3,818,065 4,059,900 7,877,965 Oil Equivalents BOE’s 3,048,261 1,351,919 4,400,180 3,759,412 2,045,188 5,804,600 Revisions of previous estimates Crude Oil BBL’s (629,480) (522,070) (1,151,550) (724,191) (627,900) (1,352,091) Natural Gas Liquids BBL’s (35,860) - (35,860) 56,919 - 56,919 Natural Gas MCF’s (1,085,542) (637,800) (1,723,342) 977,674 (392,586) 585,088 Oil Equivalents BOE’s (846,264) (628,370) (1,474,634) (504,326) (693,331) (1,197,657) Purchases of minerals in place Crude Oil BBL’s - - - 2,234 - 2,234 Natural Gas Liquids BBL’s - - - - Natural Gas MCF’s - - - - Oil Equivalents BOE’s - - - 2,234 - 2,234 Extensions and discoveries Crude Oil BBL’s - - - 2,226 - 2,226 Sales of minerals in place Crude Oil BBL’s (201,286) (15,746) (217,032) - - Production Crude Oil BBL’s (96,244) - (96,244) (150,469) - (150,469) Natural Gas Liquids BBL’s (6,045) - (6,045) (6,619) - (6,619) Natural Gas MCF’s (188,408) - (188,408) (325,894) - (325,894) Oil Equivalents BOE’s (133,690) - (133,690) (211,403) - (211,403) Ending Crude Oil BBL’s 1,287,028 202,884 1,489,912 2,214,038 740,700 2,954,738 Natural Gas Liquids BBL’s 47,345 - 47,345 89,250 - 89,250 Natural Gas MCF’s 3,195,895 3,029,514 6,225,409 4,469,845 3,667,314 8,137,159 Oil Equivalents BOE’s 1,867,041 707,819 2,574,860 3,048,261 1,351,919 4,400,180 (1) |
Schedule of plan for developing undeveloped oil and gas properties | At December 31, 2015 we believe Estimated Conversion of CAPEX ($MM) MBOE’s 2016 0.0 0.0 2017 1,120.0 112.5 2018 1,162.8 89.6 2019 3,057.2 131.4 2020 561.7 374.3 |
Standardized measure of discounted future net cash flows | The standardized measure of discounted future net cash flows from our proved reserves for the periods presented in the financial statements is summarized below. Year Ended Year Ended December 31, December 31, 2015 2014 Future production revenue $ 74,087,130 $ 282,557,900 Future production costs (46,015,320) (101,119,500) Future development costs (5,901,660) (13,736,500) Future cash flows before income tax 22,170,150 167,701,900 Future income taxes - (4,211,005) Future net cash flows 22,170,150 163,490,895 10% annual discount for estimating of future cash flows (13,400,180) (100,787,044) Standardized measure of discounted net cash flows $ 8,769,970 $ 62,703,851 |
Changes in standardized measure of discounted future net cash flows | Additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Year Ended Year Ended December 31, December 31, 2015 2014 Balance beginning of year $ 62,703,851 $ 81,447,656 Sales, net of production costs (491,055) (7,531,119) Net change in pricing and production costs (51,184,718) (19,087,068) Net change in future estimated development costs 7,834,840 6,281,385 Purchase of minerals in place - 190,502 Extensions and discoveries - 35,203 Sale of minerals in place (2,746,550) - Revisions (8,448,569) (25,498,141) Accretion of discount 16,770,190 27,098,964 Change in income tax (15,668,019) (233,531) Balance end of year $ 8,769,970 $ 62,703,851 |
Summary of Accounting Policie30
Summary of Accounting Policies - Additional Information (Detail) - USD ($) | 3 Months Ended | 12 Months Ended | ||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | |
Summary Of Accounting Policies [Line Items] | ||||||||||
Available-for-sale Securities, Gross Unrealized Gain (Loss) | $ 552,589 | |||||||||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 298,664 | 231,332 | ||||||||
Property, Plant and Equipment, Gross, Total | $ 1,995,010 | $ 2,404,703 | $ 1,995,010 | $ 2,404,703 | ||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 1,658,073 | 1,945,607 | 1,658,073 | 1,945,607 | ||||||
Asset Impairment Charges, Total | 11,386,115 | $ 9,720,983 | $ 11,421,613 | $ 16,401,376 | 0 | $ 0 | $ 0 | $ 0 | ||
Proceeds from Sale of Productive Assets | 33,142 | 1,250 | ||||||||
Proceeds from Dividends Received | 1,360,172 | 0 | ||||||||
Cash and Cash Equivalents, at Carrying Value, Total | 3,101,682 | 805,524 | 3,101,682 | 805,524 | ||||||
Available-for-sale Securities [Member] | ||||||||||
Summary Of Accounting Policies [Line Items] | ||||||||||
Proceeds from Dividends Received | 1,360,172 | |||||||||
Cash and Cash Equivalents, at Carrying Value, Total | 210,990 | 210,990 | ||||||||
Vehicles [Member] | ||||||||||
Summary Of Accounting Policies [Line Items] | ||||||||||
Property, Plant and Equipment, Gross, Total | 354,886 | 967,483 | 354,886 | 967,483 | ||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 328,659 | 697,042 | 328,659 | 697,042 | ||||||
Gas Gathering and Processing Equipment [Member] | ||||||||||
Summary Of Accounting Policies [Line Items] | ||||||||||
Property, Plant and Equipment, Gross, Total | 2,722,839 | 2,751,697 | 2,722,839 | 2,751,697 | ||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 837,494 | 744,846 | 837,494 | 744,846 | ||||||
Furniture And Equipment [Member] | ||||||||||
Summary Of Accounting Policies [Line Items] | ||||||||||
Property, Plant and Equipment, Gross, Total | 552,288 | 608,061 | 552,288 | 608,061 | ||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 478,578 | 494,333 | 478,578 | 494,333 | ||||||
Building And leasehold Imrovement [Member] | ||||||||||
Summary Of Accounting Policies [Line Items] | ||||||||||
Property, Plant and Equipment, Gross, Total | 23,069 | 23,069 | 23,069 | 23,069 | ||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | $ 13,342 | $ 9,386 | $ 13,342 | $ 9,386 | ||||||
Cherokee Project Assets [Member] | ||||||||||
Summary Of Accounting Policies [Line Items] | ||||||||||
Percentage Of Sale Reserve Quantity to Total Reserve Quantity | 6.70% | |||||||||
Proceeds from Sale of Productive Assets | $ 2,867,305 | |||||||||
Maximum [Member] | ||||||||||
Summary Of Accounting Policies [Line Items] | ||||||||||
Property, Plant and Equipment, Useful Life | 15 years | |||||||||
Minimum [Member] | ||||||||||
Summary Of Accounting Policies [Line Items] | ||||||||||
Property, Plant and Equipment, Useful Life | 3 years |
Equity Transactions (Summary of
Equity Transactions (Summary of stock options) (Detail) - $ / shares | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Options | ||
Options Outstanding, Beginning Balance | 231,332 | 231,133 |
Options Granted | 67,332 | 2,367 |
Options Cancelled | (10,333) | (2,168) |
Options Exercised | 0 | |
Options Outstanding, Ending Balance | 288,331 | 231,332 |
Weighted Avg. Exercise Price | ||
Weighted Avg. Exercise Price Outstanding, Beginning Balance | $ 9.33 | $ 9.36 |
Weighted Avg. Exercise Price Granted | 10.50 | |
Weighted Avg. Exercise Price Cancelled | (10.50) | (10.50) |
Weighted Avg. Exercise Price Exercised | 0 | |
Weighted Avg. Exercise Price Outstanding, Ending balance | $ 10.17 | $ 9.33 |
Warrants | ||
Warrants Granted | 1,904,286 | |
Warrants Cancelled | 0 | |
Warrants Exercised | 0 | 0 |
Warrants Outstanding | 1,904,286 | 0 |
Weighted Avg. Exercise Price | ||
Weighted Avg. Exercise Price Granted | $ 2.75 | |
Weighted Avg. Exercise Price Cancelled | 0 | |
Weighted Avg. Exercise Price Exercised | 0 | $ 0 |
Weighted Avg. Exercise Price Outstanding, Ending balance | $ 2.75 | $ 0 |
Equity Transactions - Additiona
Equity Transactions - Additional Information (Detail) - USD ($) | May 13, 2015 | Mar. 13, 2015 | Sep. 30, 2014 | Jun. 20, 2014 | Jun. 16, 2014 | Dec. 31, 2010 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Oct. 14, 2008 | Sep. 30, 2007 | Aug. 01, 2002 |
Stock Issued During Period, Shares, Issued for Services | 9,625 | |||||||||||
Stockholders' Equity, Reverse Stock Split | May 30, 2014, the Company affected a 1-for-15 reverse stock split, by which each share of EnerJex common stock was reclassified, and changed into 1/15th of a fully paid and non-assessable share of common stock. In lieu of fractions of a share, the Company paid to holders of fractions of a share cash equal to $11.25 per share | |||||||||||
Stock Issued During Period, Value, New Issues | $ 24,000 | $ 234,654 | ||||||||||
Share-Based Compensation Arrangement By Share-Based Payment Award, Options, Outstanding, Number | 288,331 | 231,332 | 231,133 | |||||||||
Share Based Compensation Arrangements By Share Based Payment Award Options Amount Recognized As Expenses | $ 76,938 | |||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number | 56,702 | |||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested, Number of Shares | 231,629 | |||||||||||
Treasury Stock, Number of Shares Held | 383,333 | |||||||||||
Adjustments to Additional Paid in Capital, Other | $ 2,551,000 | |||||||||||
Preferred Stock, Conversion Basis | the holders of our existing Series A preferred stock exchanged each outstanding share of such existing Series A preferred stock for (i) a number of shares of our common stock into which such Series A preferred stock was then convertible immediately prior to the exchange (318,630 shares in the aggregate), and (ii) 112,658 shares of Series A preferred stock which was equal to the quotient determined by dividing (x) that portion of the holders original Series A preferred stock purchase price that had not yet been paid in dividends, by (y) $23.75. | |||||||||||
Preferred Stock, Liquidation Preference Per Share | $ 1,000 | |||||||||||
Convertible Preferred Stock, Shares Issued upon Conversion | 571 | |||||||||||
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ 2.75 | |||||||||||
Stock Issued During Period Shares Owed For Services | 17,500 | |||||||||||
Stock Issued During Period, Value, Issued for Services | $ 175,356 | |||||||||||
Minimum [Member] | ||||||||||||
Share Price | 0.30 | |||||||||||
Maximum [Member] | ||||||||||||
Share Price | $ 2 | |||||||||||
Stock Option Plan [Member] | ||||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 26,666 | |||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 66,666 | |||||||||||
Stock Incentive Plan [Member] | ||||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 83,333 | |||||||||||
2013 Stock Incentive Plan [Member] | ||||||||||||
Common Stock, Capital Shares Reserved for Future Issuance | 333,300 | |||||||||||
IPO [Member] | ||||||||||||
Stock Issued During Period, Shares, New Issues | 639,157 | |||||||||||
Sale of Stock, Price Per Share | $ 23.75 | |||||||||||
Stock Issued During Period, Value, New Issues | $ 15,179,938 | |||||||||||
Proceeds from Issuance of Preferred Stock and Preference Stock | 13,347,564 | |||||||||||
Over-Allotment Option [Member] | ||||||||||||
Payments of Stock Issuance Costs | $ 1,832,374 | |||||||||||
Common Stock [Member] | ||||||||||||
Stock Issued During Period, Shares, New Issues | 17,500 | 17,332 | ||||||||||
Stock Issued During Period, Value, New Issues | $ 18 | $ 17 | ||||||||||
Employee Stock Option [Member] | ||||||||||||
Share Price | $ 7.95 | |||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Exercise Price | $ 9.85 | $ 10.50 | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term | 3 years | 3 years | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate | 72.00% | |||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate | 0.00% | 0.00% | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate | 1.41% | 0.47% | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross | 67,332 | 2,367 | ||||||||||
Stock Issued During Period, Value, Share-based Compensation, Gross | $ 295,932 | $ 12,178 | ||||||||||
Payments of Stock Issuance Costs | $ 420,103 | $ 374,433 | ||||||||||
Employee Stock Option [Member] | Minimum [Member] | ||||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate | 70.00% | |||||||||||
Employee Stock Option [Member] | Maximum [Member] | ||||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate | 72.00% | |||||||||||
Registered Shares [Member] | Common Stock [Member] | ||||||||||||
Stock Issued During Period, Shares, New Issues | 763,547 | |||||||||||
Shares Issuable Upon Conversion Of Preferred stock | 709,812 | |||||||||||
Unregistered Shares [Member] | ||||||||||||
Restricted Ownership Percentage | 9.99% | |||||||||||
Class of Warrant or Right, Number of Securities Called by Warrants or Rights | 1,771,428 | |||||||||||
Unregistered Shares [Member] | Common Stock [Member] | ||||||||||||
Shares Issuable Upon Conversion Of Preferred stock | 298,069 | |||||||||||
Convertible Preferred Stock [Member] | Unregistered Shares [Member] | ||||||||||||
Stock Issued During Period, Shares, New Issues | 521.62076 | |||||||||||
Series B Convertable Preferred Stock [Member] | Registered Shares [Member] | ||||||||||||
Stock Issued During Period, Shares, New Issues | 1,242.17099 | |||||||||||
Series A Preferred Stock [Member] | ||||||||||||
Stock Issued During Period, Shares, New Issues | 3,000 | |||||||||||
Stock Issued During Period, Value, New Issues | $ 3 | |||||||||||
Preferred Stock, Dividend Rate, Percentage | 10.00% | |||||||||||
Series A Preferred Stock [Member] | Senior Credit Facility [Member] | ||||||||||||
Stock Issued During Period, Shares, New Issues | 183,433 | |||||||||||
Proceeds from Issuance of Preferred Stock and Preference Stock | $ 2,300,000 | |||||||||||
Preferred Stock, Dividend Rate, Percentage | 10.00% | |||||||||||
Shares Issued, Price Per Share | $ 12.50 | |||||||||||
Employees [Member] | ||||||||||||
Stock Issued During Period, Shares, Issued for Services | 7,707 | |||||||||||
Stock Issued During Period, Value, Issued for Services | $ 59,298 | |||||||||||
Thirteen Employees [Member] | ||||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term | 3 years | |||||||||||
Officer [Member] | ||||||||||||
Share-Based Compensation Arrangement By Share-Based Payment Award, Options, Outstanding, Number | 60,000 | |||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Exercise Price | $ 6 | |||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term | 5 years | |||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested in Period, Fair Value | $ 307,751 | |||||||||||
Share Based Compensation Arrangements By Share Based Payment Award Options Amount Recognized As Expenses | $ 0 | $ 76,938 |
Asset Retirement Obligation (Ch
Asset Retirement Obligation (Changes in Asset Retirement Obligations) (Detail) - USD ($) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Reconciliation Of Changes In Asset Retirement Obligations [Line Items] | ||
Asset retirement obligations, Begining | $ 2,906,093 | $ 2,687,801 |
Liabilities incurred during the period | 65,385 | |
Release of liabilities associated with the sale of oil properties | (70,083) | |
Liabilities settled during the year | (2,244) | (102,929) |
Accretion | 257,712 | 255,836 |
Asset retirement obligations, Ending | $ 3,091,478 | $ 2,906,093 |
Long-Term Debt - Additional Inf
Long-Term Debt - Additional Information (Detail) - USD ($) | Aug. 12, 2015 | May 22, 2014 | Sep. 30, 2013 | Dec. 31, 2015 | May 02, 2015 | Dec. 31, 2014 | Aug. 15, 2014 | Apr. 16, 2013 | Nov. 02, 2012 | Aug. 31, 2012 | Dec. 15, 2011 |
Debt Instrument [Line Items] | |||||||||||
Line of credit facility, maximum borrowing capacity | $ 18,600,000 | $ 19,500,000 | |||||||||
Line of credit facility, current borrowing capacity | $ 18,600,000 | ||||||||||
Proceeds from potential future securities offering unencumbered by Banks’ Liens | $ 1,000,000 | ||||||||||
Line of Credit Facility, Expiration Date | Oct. 3, 2018 | ||||||||||
First Amendment | Rantoul Partners | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Line of credit facility, maximum borrowing capacity | $ 50,000,000 | ||||||||||
Second Amendment | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Line of credit facility, maximum borrowing capacity | $ 7,000,000 | ||||||||||
Second Amendment | Minimum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.75% | ||||||||||
Third Amendment | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Line of credit facility, maximum borrowing capacity | $ 12,150,000 | ||||||||||
Fifth Amendment | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Line of credit facility, maximum borrowing capacity | $ 100,000,000 | ||||||||||
Line of credit facility, current borrowing capacity | $ 38,000,000 | ||||||||||
Seventh Amendment | Series A Cumulative Redeemable Perpetual Preferred Stock | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Preferred Stock, Dividend Rate, Percentage | 10.00% | ||||||||||
Preferred Stock Shares Issued | 850,000 | ||||||||||
Eight Amendment | Minimum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Line of credit facility, maximum borrowing capacity | $ 38,000,000 | ||||||||||
Eight Amendment | Maximum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Line of credit facility, maximum borrowing capacity | $ 40,000,000 | ||||||||||
Credit Facility [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.30% | 3.30% | |||||||||
Tenth Amendment [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Proceed From Sale To Outstanding Loan Balances | $ 1,300,000 | ||||||||||
Proceeds from Sale of Oil and Gas Property and Equipment | $ 1,500,000 | ||||||||||
Line of Credit | Federal Funds Rate | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument interest rate, margin | 0.50% | ||||||||||
Line of Credit | Base Rate | Minimum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument interest rate, margin | 0.00% | ||||||||||
Line of Credit | Base Rate | Maximum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument interest rate, margin | 0.75% | ||||||||||
Line of Credit | Floating Rate | Minimum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument interest rate, margin | 2.25% | ||||||||||
Line of Credit | Floating Rate | Maximum | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument interest rate, margin | 3.00% | ||||||||||
Line of Credit | Fifth Amendment | Federal Funds Rate | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument interest rate, margin | 3.30% |
Commitments and Contingencies -
Commitments and Contingencies - Additional Information (Detail) - USD ($) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Commitments and Contingencies Disclosure [Line Items] | ||
Operating Leases, Rent Expense | $ 149,000 | $ 159,000 |
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 147,000 | |
Operating Leases, Future Minimum Payments, Due in Two Years | 145,000 | |
Operating Leases, Future Minimum Payments, Due in Three Years | 91,000 | |
Operating Leases, Future Minimum Payments, Due in Four Years | 77,000 | |
Texas Railroad Commission [Member] | ||
Commitments and Contingencies Disclosure [Line Items] | ||
Letters of Credit Outstanding, Amount | $ 50,000 |
Income Taxes (Reconciliation of
Income Taxes (Reconciliation of The Provision For Income Taxes) (Detail) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Statutory tax rate | 35.00% | 35.00% |
State tax rate, net of federal tax | 1.90% | 1.37% |
Other permanent items | 0.00% | 0.05% |
Change in valuation allowance | (36.90%) | (36.42%) |
Effective tax rate | 0.00% | 0.00% |
Income Taxes (Components of The
Income Taxes (Components of The Deferred Tax Assets and Liabilities) (Detail) - USD ($) | Dec. 31, 2015 | Dec. 31, 2014 |
Non-current deferred tax asset: | ||
Oil and gas costs and long-lived assets | $ 14,513,571 | $ (1,038,092) |
Derivative instruments | 934,340 | (1,717,301) |
Net operating loss carry-forward | 29,532,954 | 25,915,146 |
Valuation allowance | (44,980,865) | (23,159,753) |
Net deferred tax asset (liability) | $ 0 | $ 0 |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Detail) $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Operating Loss Carryforwards | $ 81 |
Operating Loss Carryforward, Expiration Date | 2021-2036 |
Limitations On Use Operating Loss Carryforwards | $ 40.9 |
Fair Value Measurements (Variab
Fair Value Measurements (Variable to Fixed Price Commodity Swaps Derivative Instruments) (Detail) | Dec. 31, 2015USD ($) |
Fair Value, Inputs, Level 1 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Crude oil contracts | $ 0 |
Marketable Securities | 0 |
Fair Value, Inputs, Level 2 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Crude oil contracts | 2,531,401 |
Marketable Securities | 0 |
Fair Value, Inputs, Level 3 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Crude oil contracts | 0 |
Marketable Securities | $ 210,990 |
Derivative Instruments (Derivat
Derivative Instruments (Derivative Contracts) (Detail) | 12 Months Ended | |
Dec. 31, 2015USD ($)$ / Barrel-bblbbl | ||
Derivative [Line Items] | ||
Fair Value | $ 2,531,401 | |
Deferred premium put | Derivative Instrument 1 | ||
Derivative [Line Items] | ||
Monthly Volumes Bbls | bbl | 9,000 | [1] |
Price/Bbl | $ / Barrel-bbl | 85 | |
Fair Value | $ 2,170,912 | |
Deferred premium put | Derivative Instrument 2 | ||
Derivative [Line Items] | ||
Monthly Volumes Bbls | bbl | 5,000 | [1] |
Price/Bbl | $ / Barrel-bbl | 60 | |
Fair Value | $ 360,489 | |
Deferred premium put | Minimum | Derivative Instrument 1 | ||
Derivative [Line Items] | ||
Term | 2016-01 | |
Deferred premium put | Minimum | Derivative Instrument 2 | ||
Derivative [Line Items] | ||
Term | 2016-07 | |
Deferred premium put | Maximum | Derivative Instrument 1 | ||
Derivative [Line Items] | ||
Term | 2016-06 | |
Deferred premium put | Maximum | Derivative Instrument 2 | ||
Derivative [Line Items] | ||
Term | 2016-12 | |
[1] | Monthly volumes are the weighted average throughout the period. |
Derivative Instruments - Additi
Derivative Instruments - Additional Information (Detail) - USD ($) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Loss on Derivative Instruments, Pretax | $ 2,194,679 | $ 6,073,960 |
Impairment of Oil and Gas Pro42
Impairment of Oil and Gas Properties - Additional Information (Detail) | 3 Months Ended | 6 Months Ended | 9 Months Ended | 12 Months Ended | |
Mar. 31, 2015USD ($)bbl | Jun. 30, 2015USD ($)bbl | Sep. 30, 2015USD ($)bbl | Dec. 31, 2015USD ($)bbl | Dec. 31, 2014USD ($) | |
Oil Price Per Barrel | 78.82 | 71.68 | 59.21 | 52.73 | |
Natural Gas Price Per MMBtu | 3.74 | 3.39 | 3.06 | 2.76 | |
Impairment of Oil and Gas Properties | $ | $ 16,400,000 | $ 11,400,000 | $ 9,700,000 | $ 48,930,087 | $ 0 |
Other Income (Components of Oth
Other Income (Components of Other Income) (Detail) - USD ($) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Interest And Other Income [Line Items] | ||
Realized gain (loss) clearing of derivative contracts | $ 4,662,012 | $ (914,694) |
Loss on sale of fixed assets | (13,661) | (9,738) |
Miscellaneous income | 27,105 | 4,004 |
Interest income | 398 | 901 |
Other Income | $ 4,675,854 | $ (919,527) |
Supplemental Oil and Gas Rese44
Supplemental Oil and Gas Reserve Information (Unaudited) (Results of Operations From Oil and gas Producing Activities) (Detail) - USD ($) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Production revenues | $ 4,878,722 | $ 14,293,368 |
Production costs | (4,501,940) | (6,762,248) |
Depletion and depreciation | (1,108,039) | (3,259,442) |
Income tax | 255,940 | (1,495,087) |
Results of operations for producing activities | $ (475,317) | $ 2,776,591 |
Supplemental Oil and Gas Rese45
Supplemental Oil and Gas Reserve Information (Unaudited) (Summary of Capitalized Costs of Oil and gas Properties) (Detail) - USD ($) | Dec. 31, 2015 | Dec. 31, 2014 |
Properties subject to amortization | $ 26,642,325 | $ 78,090,619 |
Accumulated depletion | (14,935,386) | (13,827,347) |
Net capitalized costs | $ 11,706,939 | $ 64,263,272 |
Supplemental Oil and Gas Rese46
Supplemental Oil and Gas Reserve Information (Unaudited) (Cost Incurred in Property Acquisition, Exploration and Development Activities) (Detail) - USD ($) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Acquisition of properties | $ 85,895 | $ 1,017,698 |
Exploration costs | 0 | 0 |
Development costs | 165,926 | 6,078,167 |
Net capitalized costs | $ 251,821 | $ 7,095,865 |
Supplemental Oil and Gas Rese47
Supplemental Oil and Gas Reserve Information (Unaudited) (Estimated Quantities of Proved Reserves) (Detail) | 12 Months Ended | ||
Dec. 31, 2015Boebbl | Dec. 31, 2014Boebbl | ||
Production | (133.7) | (211.4) | |
Crude Oil [Member] | |||
Beginning | [1] | 2,954,738 | 4,452,838 |
Revisions of previous estimates | [1] | (1,151,550) | (1,352,091) |
Purchases of minerals in place | [1] | 0 | 2,234 |
Extensions and discoveries | [1] | 2,226 | 0 |
Sales of minerals in place | [1] | (217,032) | |
Production | [1] | (96,244) | (150,469) |
Ending | [1] | 1,489,912 | 2,954,738 |
Crude Oil [Member] | Proved Developed Reserves [Member] | |||
Beginning | [1] | 2,214,038 | 3,084,238 |
Revisions of previous estimates | [1] | (629,480) | (724,191) |
Purchases of minerals in place | [1] | 0 | 2,234 |
Extensions and discoveries | [1] | 2,226 | 0 |
Sales of minerals in place | [1] | (201,286) | 0 |
Production | [1] | (96,244) | (150,469) |
Ending | [1] | 1,287,028 | 2,214,038 |
Crude Oil [Member] | Proved Undeveloped Reserve [Member] | |||
Beginning | [1] | 740,700 | 1,368,600 |
Revisions of previous estimates | [1] | (522,070) | (627,900) |
Purchases of minerals in place | [1] | 0 | 0 |
Extensions and discoveries | [1] | 0 | 0 |
Sales of minerals in place | [1] | (15,746) | 0 |
Production | [1] | 0 | 0 |
Ending | [1] | 202,884 | 740,700 |
Natural Gas Liquids [Member] | |||
Beginning | [1] | 89,250 | 38,950 |
Revisions of previous estimates | [1] | (35,860) | 56,919 |
Purchases of minerals in place | [1] | 0 | |
Production | [1] | (6,045) | (6,619) |
Ending | [1] | 47,345 | 89,250 |
Natural Gas Liquids [Member] | Proved Developed Reserves [Member] | |||
Beginning | [1] | 89,250 | 38,950 |
Revisions of previous estimates | [1] | (35,860) | 56,919 |
Purchases of minerals in place | [1] | 0 | |
Production | [1] | (6,045) | (6,619) |
Ending | [1] | 47,345 | 89,250 |
Natural Gas Liquids [Member] | Proved Undeveloped Reserve [Member] | |||
Beginning | [1] | 0 | 0 |
Revisions of previous estimates | [1] | 0 | 0 |
Purchases of minerals in place | [1] | 0 | 0 |
Production | [1] | 0 | 0 |
Ending | [1] | 0 | 0 |
Natural Gas [Member] | |||
Beginning | [1] | 8,137,159 | 7,877,965 |
Revisions of previous estimates | [1] | (1,723,342) | 585,088 |
Purchases of minerals in place | [1] | 0 | |
Production | [1] | (188,408) | (325,894) |
Ending | [1] | 6,225,409 | 8,137,159 |
Natural Gas [Member] | Proved Developed Reserves [Member] | |||
Beginning | [1] | 4,469,845 | 3,818,065 |
Revisions of previous estimates | [1] | (1,085,542) | 977,674 |
Purchases of minerals in place | [1] | 0 | |
Production | [1] | (188,408) | (325,894) |
Ending | [1] | 3,195,895 | 4,469,845 |
Natural Gas [Member] | Proved Undeveloped Reserve [Member] | |||
Beginning | [1] | 3,667,314 | 4,059,900 |
Revisions of previous estimates | [1] | (637,800) | (392,586) |
Purchases of minerals in place | [1] | 0 | 0 |
Production | [1] | 0 | 0 |
Ending | [1] | 3,029,514 | 3,667,314 |
Oil Equivalents [Member] | |||
Beginning | Boe | [1] | 4,400,180 | 5,804,600 |
Revisions of previous estimates | Boe | [1] | (1,474,634) | (1,197,657) |
Purchases of minerals in place | Boe | [1] | 0 | 2,234 |
Production | Boe | [1] | (133,690) | (211,403) |
Ending | Boe | [1] | 2,574,860 | 4,400,180 |
Oil Equivalents [Member] | Proved Developed Reserves [Member] | |||
Beginning | Boe | [1] | 3,048,261 | 3,759,412 |
Revisions of previous estimates | Boe | [1] | (846,264) | (504,326) |
Purchases of minerals in place | Boe | [1] | 0 | 2,234 |
Production | Boe | [1] | (133,690) | (211,403) |
Ending | Boe | [1] | 1,867,041 | 3,048,261 |
Oil Equivalents [Member] | Proved Undeveloped Reserve [Member] | |||
Beginning | Boe | [1] | 1,351,919 | 2,045,188 |
Revisions of previous estimates | Boe | [1] | (628,370) | (693,331) |
Purchases of minerals in place | Boe | [1] | 0 | 0 |
Production | Boe | [1] | 0 | 0 |
Ending | Boe | [1] | 707,819 | 1,351,919 |
[1] | Amounts in this table may differ from amounts previously disclosed due to roundings. |
Supplemental Oil and Gas Rese48
Supplemental Oil and Gas Reserve Information (Unaudited) (Estimated Conversion ofProved Undeveloped Reserves) (Detail) | Dec. 31, 2015USD ($)bbl |
CAPEX 2016 | $ | $ 0 |
CAPEX 2017 | $ | 1,120 |
CAPEX 2018 | $ | 1,162.8 |
CAPEX 2019 | $ | 3,057.2 |
CAPEX 2020 | $ | $ 561.7 |
MBOE’s 2016 | bbl | 0 |
MBOE’s 2017 | bbl | 112.5 |
MBOE’s 2018 | bbl | 89.6 |
MBOE’s 2019 | bbl | 131.4 |
MBOE’s 2020 | bbl | 374.3 |
Supplemental Oil and Gas Rese49
Supplemental Oil and Gas Reserve Information (Unaudited)(Standardized Measure of Discounted Future Net Cash Flows) (Detail) - USD ($) | Dec. 31, 2015 | Dec. 31, 2014 |
Future production revenue | $ 74,087,130 | $ 282,557,900 |
Future production costs | (46,015,320) | (101,119,500) |
Future development costs | (5,901,660) | (13,736,500) |
Future cash flows before income tax | 22,170,150 | 167,701,900 |
Future income taxes | 0 | (4,211,005) |
Future net cash flows | 22,170,150 | 163,490,895 |
10% annual discount for estimating of future cash flows | (13,400,180) | (100,787,044) |
Standardized measure of discounted net cash flows | $ 8,769,970 | $ 62,703,851 |
Supplemental Oil and Gas Rese50
Supplemental Oil and Gas Reserve Information (Unaudited) (Changes in Standardized Measure of Discounted Future Net Cash Flows) (Detail) - USD ($) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Balance beginning of year | $ 62,703,851 | $ 81,447,656 |
Sales, net of production costs | (491,055) | (7,531,119) |
Net change in pricing and production costs | (51,184,718) | (19,087,068) |
Net change in future estimated development costs | 7,834,840 | 6,281,385 |
Purchase of minerals in place | 0 | 190,502 |
Extensions and discoveries | 0 | 35,203 |
Sale of minerals in place | (2,746,550) | 0 |
Revisions | (8,448,569) | (25,498,141) |
Accretion of discount | 16,770,190 | 27,098,964 |
Change in income tax | (15,668,019) | (233,531) |
Balance end of year | $ 8,769,970 | $ 62,703,851 |
Supplemental Oil and Gas Rese51
Supplemental Oil and Gas Reserve Information (Unaudited) - Additional Information (Detail) | 12 Months Ended | |||
Dec. 31, 2015USD ($)Boebbl | Dec. 31, 2014USD ($)Boebbl | Dec. 31, 2013Boebbl | ||
Percentage Of Oil For Proved Developed Reserves | 71.00% | 76.00% | ||
Percentage Of Natural Gas For Proved Developed Reserves | 29.00% | 24.00% | ||
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease), Total | 1,825.3 | 1,404.4 | ||
Proved Developed and Undeveloped Reserves, Production | 133.7 | 211.4 | ||
Percentage of Decrease Proved Developed And Undeveloped Reserves Production | 7.30% | 15.10% | ||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates and Sales of Minerals | 1,691.6 | 1,193 | ||
Payments To Acquire Oil and Gas Property | $ | $ 251,821 | $ 7,095,865 | ||
Assets, Current, Total | $ | 7,213,213 | 7,411,168 | ||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | $ | 3,700,000 | |||
Loans Payable to Bank, Noncurrent | $ | 5,000,000 | |||
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Development Costs | $ | 5,901,660 | 13,736,500 | ||
Oil and Gas Properties [Member] | ||||
Payments To Acquire Oil and Gas Property | $ | $ 250,000 | |||
Assets, Current, Total | $ | $ 7,400,000 | |||
Crude Oil [Member] | ||||
Proved Developed and Undeveloped Reserves, Net | [1] | 1,489,912 | 2,954,738 | 4,452,838 |
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease), Total | 1,352,091 | |||
Proved Developed and Undeveloped Reserves, Production | [1] | 96,244 | 150,469 | |
Decrease in Oil and Gas Prices | $ | $ 40 | |||
Percentage of Decrease in Oil And Gas Prices | 46.10% | |||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | [1] | (1,151,550) | (1,352,091) | |
Proved Developed Producing Reserves [Member] | Crude Oil [Member] | ||||
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease), Total | 724,000 | |||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | 586.6 | |||
Proved Developed Non Producing Reserves [Member] | Crude Oil [Member] | ||||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | 42.9 | |||
Proved Undeveloped Reserves [Member] | ||||
Proved Developed and Undeveloped Reserves, Net | 707.8 | 1,351.9 | ||
Proved Undeveloped Reserves [Member] | Crude Oil [Member] | ||||
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease), Total | 628,000 | |||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | 522.1 | |||
Proved Developed Reserves [Member] | ||||
Proved Developed and Undeveloped Reserves, Net | 1,867 | 3,048.3 | ||
Natural Gas [Member] | ||||
Proved Developed and Undeveloped Reserves, Net | [1] | 6,225,409 | 8,137,159 | 7,877,965 |
Proved Developed and Undeveloped Reserves, Production | [1] | 188,408 | 325,894 | |
Decrease in Oil and Gas Prices | $ | $ 1.37 | |||
Percentage of Decrease in Oil And Gas Prices | 42.20% | |||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | [1] | (1,723,342) | 585,088 | |
Natural Gas [Member] | Proved Developed Producing Reserves [Member] | ||||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | 1,347.9 | |||
Natural Gas [Member] | Proved Developed Non Producing Reserves [Member] | ||||
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease), Total | 65,000 | |||
Proved Developed and Undeveloped Reserves, Improved Recovery | 262.4 | |||
Natural Gas [Member] | Proved Undeveloped Reserves [Member] | ||||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | 637.8 | |||
Natural Gas Liquids [Member] | ||||
Proved Developed and Undeveloped Reserves, Net | [1] | 47,345 | 89,250 | 38,950 |
Proved Developed and Undeveloped Reserves, Production | [1] | 6,045 | 6,619 | |
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | [1] | (35,860) | 56,919 | |
Natural Gas Liquids [Member] | Proved Developed Producing Reserves [Member] | ||||
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease), Total | 163,000 | |||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | 65.6 | |||
Natural Gas Liquids [Member] | Proved Developed Non Producing Reserves [Member] | ||||
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease), Total | 57,000 | |||
Proved Developed and Undeveloped Reserves, Improved Recovery | 29.7 | |||
Oil Equivalents [Member] | ||||
Proved Developed and Undeveloped Reserve, Net (Energy), Beginning Balance | Boe | [1] | 2,574,860 | 4,400,180 | 5,804,600 |
Oil Equivalents [Member] | Proved Undeveloped Reserves [Member] | ||||
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease), Total | 644.1 | |||
Percentage of Decrease Proved Developed And Undeveloped Reserves Production | 47.60% | |||
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Development Costs | $ | $ 5.9 | |||
Proved Developed and Undeveloped Reserve, Net (Energy), Beginning Balance | Boe | 707.8 | |||
[1] | Amounts in this table may differ from amounts previously disclosed due to roundings. |