Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2015 | Aug. 11, 2015 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | Carbon Natural Gas Co | |
Entity Central Index Key | 86,264 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Document Type | 10-Q | |
Document Period End Date | Jun. 30, 2015 | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q2 | |
Entity Filer Category | Smaller Reporting Company | |
Entity Common Stock, Shares Outstanding | 108,158,780 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Current assets: | ||
Cash and cash equivalents | $ 575 | $ 1,132 |
Accounts receivable | ||
Revenue | 1,484 | 2,287 |
Joint interest billings and other | 479 | 1,038 |
Commodity derivative asset | 557 | 1,322 |
Prepaid expense, deposits and other current assets | 216 | 141 |
Total current assets | 3,311 | 5,920 |
Oil and gas properties, full cost method of accounting: | ||
Proved, net | 31,349 | 30,698 |
Unevaluated | 2,895 | 2,789 |
Other property and equipment, net | 239 | 304 |
Total property and equipment, net | 34,483 | 33,791 |
Investments in affiliates (note 5) | 1,008 | 1,009 |
Other long-term assets | 374 | 911 |
Total assets | 39,176 | 41,631 |
Current liabilities: | ||
Accounts payable and accrued liabilities | 6,061 | 7,792 |
Firm transportation contract obligations (note 12) | 446 | 487 |
Total current liabilities | 6,507 | 8,279 |
Non-current liabilities: | ||
Firm transportation contract obligations (note 12) | 633 | 852 |
Asset retirement obligation (note 2) | 3,031 | 2,968 |
Notes payable (note 6) | 2,800 | 2,100 |
Total non-current liabilities | $ 6,464 | $ 5,920 |
Commitments (note 12) | ||
Stockholders' equity: | ||
Preferred stock, $0.01 par value; authorized 1,000,000 shares, no shares issued and outstanding at June 30, 2015 and December 31, 2014 | ||
Common stock, $0.01 par value; authorized 200,000,000 shares, 108,158,780 and 106,875,447 shares issued and outstanding at June 30, 2015 and December 31, 2014, respectively | $ 1,081 | $ 1,069 |
Additional paid-in capital | 53,847 | 53,160 |
Accumulated deficit | (31,643) | (29,832) |
Total Carbon stockholders' equity | 23,285 | 24,397 |
Non-controlling interests | 2,920 | 3,035 |
Total stockholders' equity | 26,205 | 27,432 |
Total liabilities and stockholders' equity | $ 39,176 | $ 41,631 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Jun. 30, 2015 | Dec. 31, 2014 |
Balance Sheets [Abstract] | ||
Preferred stock, par value | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 1,000,000 | 1,000,000 |
Preferred stock, shares issued | ||
Preferred stock, shares outstanding | ||
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 200,000,000 | 200,000,000 |
Common stock, shares issued | 108,158,780 | 106,875,447 |
Common stock, shares outstanding | 108,158,780 | 106,875,447 |
Consolidated Statements of Oper
Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Revenue: | ||||
Oil and gas | $ 2,833 | $ 5,951 | $ 5,969 | $ 12,047 |
Commodity derivative (loss) gain | (59) | (278) | 147 | (768) |
Other (loss) income | (33) | 81 | 18 | 172 |
Total revenue | 2,741 | 5,754 | 6,134 | 11,451 |
Expenses: | ||||
Lease operating expenses | 778 | 839 | 1,613 | 1,736 |
Transportation costs | 357 | 407 | 755 | 891 |
Production and property taxes | 230 | 426 | 429 | 870 |
General and administrative | 1,791 | 1,330 | 3,666 | 2,919 |
Depreciation, depletion and amortization | 696 | 728 | 1,341 | 1,492 |
Accretion of asset retirement obligations | 32 | 29 | 63 | 58 |
Total expenses | 3,884 | 3,759 | 7,867 | 7,966 |
Operating (loss) income | (1,143) | 1,995 | (1,733) | 3,485 |
Other income and (expense): | ||||
Interest expense | (53) | $ (128) | (97) | $ (247) |
Other | (11) | (36) | ||
Equity investment income (loss) | (2) | $ 2 | (1) | $ 5 |
Total other expense | (66) | (126) | (134) | (242) |
Income before income taxes | $ (1,209) | $ 1,869 | $ (1,867) | $ 3,243 |
Provision for income taxes | ||||
Net (loss) income before non-controlling interests | $ (1,209) | $ 1,869 | $ (1,867) | $ 3,243 |
Net (loss) income attributable to non-controlling interests | (28) | 63 | (56) | 154 |
Net (loss) income attributable to controlling interest | $ (1,181) | $ 1,806 | $ (1,811) | $ 3,089 |
Net (loss) income per common share: | ||||
Basic | $ (0.01) | $ 0.02 | $ (0.02) | $ 0.03 |
Diluted | $ (0.01) | $ 0.02 | $ (0.02) | $ 0.03 |
Weighted average common shares outstanding: | ||||
Basic | 107,166 | 111,964 | 106,554 | 112,489 |
Diluted | 107,166 | 117,030 | 106,554 | 117,556 |
Consolidated Statement of Stock
Consolidated Statement of Stockholders' Equity (Unaudited) - 6 months ended Jun. 30, 2015 - USD ($) $ in Thousands | Total | Common Stock | Additional Paid-in Capital | Non-Controlling Interests | Accumulated Deficit |
Beginning balances at Dec. 31, 2014 | $ 27,432 | $ 1,069 | $ 53,160 | $ 3,035 | $ (29,832) |
Beginning balances, (in shares) at Dec. 31, 2014 | 106,875,000 | ||||
Stock-based compensation | $ 699 | 699 | |||
Restricted stock vested | $ 12 | $ (12) | |||
Restricted stock vested, shares | 1,284 | ||||
Non-controlling interest distributions, net | $ (59) | $ (59) | |||
Net loss | (1,867) | (56) | $ (1,811) | ||
Ending balances at Jun. 30, 2015 | $ 26,205 | $ 1,081 | $ 53,847 | $ 2,920 | $ (31,643) |
Ending balances, (in shares) at Jun. 30, 2015 | 108,159,000 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
Cash flows from operating activities: | ||
Net (loss) income | $ (1,867) | $ 3,243 |
Items not involving cash: | ||
Depreciation, depletion and amortization | 1,341 | 1,492 |
Accretion of asset retirement obligations | 63 | 58 |
Unrealized derivative loss | 764 | 266 |
Stock-based compensation expense | 699 | 711 |
Equity investment iloss (income) | 1 | (5) |
Net change in: | ||
Accounts receivable | 1,446 | (643) |
Prepaid expenses, deposits and other current assets | (75) | (61) |
Accounts payable, accrued liabilities and firm transportation contract obligations | (1,723) | 662 |
Net cash provided by operating activities | 649 | 5,723 |
Cash flows from investing activities: | ||
Development of properties and equipment | (2,343) | (5,685) |
Proceeds from sale of oil and gas properties | 42 | 2,338 |
Other long-term assets | 454 | 25 |
Net cash used in investing activities | $ (1,847) | (3,322) |
Cash flows from financing activities: | ||
Purchase of common stock | (3,261) | |
Proceeds from notes payable | $ 1,100 | 4,800 |
Payments on notes payable | (400) | (2,850) |
Distributions to non-controlling interests | (59) | (138) |
Net cash provided by (used in) financing activities | 641 | (1,449) |
Net (decrease) increase in cash and cash equivalents | (557) | 952 |
Cash and cash equivalents, beginning of period | 1,132 | 243 |
Cash and cash equivalents, end of period | $ 575 | $ 1,195 |
Organization
Organization | 6 Months Ended |
Jun. 30, 2015 | |
Organization [Abstract] | |
Organization | Note 1 – Organization Carbon Natural Gas Company (“Carbon” or the “Company”) is an independent oil and gas company engaged in the exploration, development and production of oil and natural gas in the United States. The Company’s business is comprised of the assets and properties of Nytis Exploration (USA) Inc. (“Nytis USA”) and its subsidiary Nytis Exploration Company LLC (“Nytis LLC”) which conducts the Company’s operations in the Appalachian and Illinois Basins. Collectively, Carbon, Nytis USA and Nytis LLC are referred to as the Company. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 6 Months Ended |
Jun. 30, 2015 | |
Summary of Significant Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Note 2 – Summary of Significant Accounting Policies Basis of Presentation The accompanying unaudited Consolidated Financial Statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, the accompanying unaudited Consolidated Financial Statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of June 30, 2015, the Company’s results of operations for the three and six months ended June 30, 2015 and 2014 and the Company’s cash flows for the six months ended June 30, 2015 and 2014. Operating results for the three and six months ended June 30, 2015 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results and other factors. For a more complete understanding of the Company’s operations, financial position and accounting policies, the unaudited financial statements and the notes thereto should be read in conjunction with the Company’s audited Consolidated Financial Statements for the year ended December 31, 2014 filed on Form 10-K with the Securities and Exchange Commission (“SEC”). In the course of preparing the unaudited financial statements, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenue and expenses and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and accordingly, actual results could differ from amounts initially established. Principles of Consolidation The Consolidated Financial Statements include the accounts of Carbon, Nytis USA and its consolidated subsidiary. Carbon owns 100% of Nytis USA. Nytis USA owns approximately 99% of Nytis LLC. Nytis LLC also holds an interest in various oil and gas partnerships. For partnerships where the Company has a controlling interest, the partnerships are consolidated. The Company is currently consolidating on a pro-rata basis 46 partnerships. In these instances, the Company reflects the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on its Consolidated Statements of Operations and also reflects the non-controlling ownership interests in the net assets of the partnerships as non-controlling interests within stockholders’ equity on its Consolidated Balance Sheets. All significant intercompany accounts and transactions have been eliminated. In accordance with established practice in the oil and gas industry, the Company’s Consolidated Financial Statements also include its pro-rata share of assets, liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which the Company has a non-controlling interest. Non-majority owned investments that do not meet the criteria for pro-rata consolidation are accounted for using the equity method when the Company has the ability to significantly influence the operating decisions of the investee. When the Company does not have the ability to significantly influence the operating decisions of an investee, the cost method is used. All transactions, if any, with investees have been eliminated in the accompanying Consolidated Financial Statements. Accounting for Oil and Gas Operations The Company uses the full cost method of accounting for oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Overhead costs incurred that are directly identified with acquisition, exploration and development activities undertaken by the Company for its own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized. Unproved properties are excluded from amortized capitalized costs until it is determined whether or not proved reserves can be assigned to such properties. The Company assesses its unproved properties for impairment at least annually. Significant unproved properties are assessed individually. Capitalized costs are depleted by an equivalent unit-of-production method, converting oil to gas at the ratio of one barrel of oil to six thousand cubic feet of natural gas. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves. All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred. The Company performs a ceiling test quarterly. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value based measurement. Rather, it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using the un-weighted arithmetic average of the first-day-of-the month price for the previous twelve month period, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs. Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds the capitalized costs in future periods. For the three and six months ended June 30, 2015 and 2014, the Company did not recognize a ceiling test impairment as the Company’s full cost pool did not exceed the ceiling limitations. In December 2014, proceeds from the sale of the Company’s interests in certain leases in Kentucky and West Virginia below the Clinton Formation, referred to as the Deep Rights, were credited to the Company’s full cost pool, which decreased the Company’s net book value of its full cost pool while increasing its ceiling test cushion. Future declines in oil and natural gas prices, and increases in future operating expenses and future development costs could result in impairments of our oil and gas properties in future periods. Because the ceiling test uses the previous twelve month period average commodity price, the effects of declining prices since mid-2014 will have greater impact on the average price used to value our reserves which will lower the ceiling test value in future quarters and may result in an impairment of our oil and gas properties. The effects of price declines will continue to impact the ceiling test value until such time the prices stabilize or improve. Impairment charges are a non-cash charge and accordingly, would not affect cash flow, but would adversely affect our net income and stockholders’ equity. Investments in Affiliates Investments in non-consolidated affiliates are accounted for under either the equity or cost method of accounting as appropriate. The cost method of accounting is used for investments in affiliates in which the Company has less than 20% of the voting interests of a corporate affiliate or less than a 5% interest in a partnership or limited liability company and does not have significant influence. Investments in non-consolidated affiliates, accounted for using the cost method of accounting, are recorded at cost and an impairment assessment of each investment is made annually to determine if a decline in the fair value of the investment, other than temporary, has occurred. A permanent impairment is recognized if a decline in the fair value occurs. If the Company holds between 20% and 50% of the voting interest in a non-consolidated corporate affiliate or greater than a 5% interest in a partnership or limited liability company and exercises significant influence or control, the equity method of accounting is used to account for the investment. The Company’s investment in an affiliate that is accounted for using the equity method of accounting, increases or decreases by the Company’s share of the affiliate’s profits or losses and such profits or losses are recognized in the Company’s Consolidated Statements of Operations. The Company reviews equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred. The amount of the impairment is based on quoted market prices, where available, or other valuation techniques. Asset Retirement Obligations The Company’s asset retirement obligations (“ARO”) relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred and the cost of such liability is recorded as an increase in the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability. The estimated ARO liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or increased as a result of a reassessment of expected cash flows and assumptions inherent in the estimation of the liability. Upward revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. AROs are valued utilizing Level 3 fair value measurement inputs. The following table is a reconciliation of the ARO for the six months ended June 30, 2015 and 2014: Six Months Ended (in thousands) 2015 2014 Balance at beginning of period $ 2,968 $ 2,699 Accretion expense 63 58 Additions during period - 60 Balance at end of period $ 3,031 $ 2,817 Earnings (Loss) Per Common Share Basic earnings or loss per common share is computed by dividing the net income or loss attributable to common shareholders for the period by the weighted average number of common shares outstanding during the period. The shares of restricted common stock granted to certain officers and employees of the Company are included in the computation of basic net income or loss per share only after the shares become fully vested. Diluted earnings per common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise of options and warrants to acquire common stock, computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company with the proceeds from the exercise of options and warrants (which were assumed to have been made at the average market price of the common shares during the reporting period). The following table sets forth the calculation of basic and diluted (loss) income per share: Three Months Ended Six Months Ended (in thousands except per share amounts) 2015 2014 2015 2014 Net (loss) income $ (1,181 ) $ 1,806 $ (1,811 ) $ 3,089 Basic weighted-average common shares outstanding during the period 107,166 111,964 106,554 112,489 Add dilutive effects of stock options, warrants and non-vested shares of restricted stock - 5,066 - 5,067 Diluted weighted-average common shares outstanding during the period 107,166 117,030 106,554 117,556 Basic net (loss) income per common share $ (0.01 ) $ 0.02 $ (0.02 ) $ 0.03 Diluted net (loss) income per common share $ (0.01 ) $ 0.02 $ (0.02 ) $ 0.03 For the three and six months ended June 30, 2015, the Company had a net loss and therefore, the diluted net loss per share calculation excluded the anti-dilutive effect of approximately 250,000 stock options and warrants and approximately 5.0 million nonvested shares of restricted stock in each period, respectively. Approximately 6.3 million restricted performance units, in each period respectively, subject to future contingencies are excluded from the basic and diluted loss per share. For the three and six months ended June 30, 2014, the diluted income per common share calculation excludes the dilutive effect of approximately 250,000 warrants that were out-of-the-money and approximately 4.7 million restricted performance units, subject to future contingencies, were excluded from the basic and diluted income per share in each respective period. |
Acquisitions and Dispositions
Acquisitions and Dispositions | 6 Months Ended |
Jun. 30, 2015 | |
Acquisitions and Dispositions [Abstract] | |
Acquisitions and Dispositions | Note 3– Acquisitions and Dispositions On December 15, 2014, Nytis LLC together with Liberty Energy LLC (the “Sellers”), completed a preliminary closing in accordance with a Purchase and Sale Agreement (the “PSA”) entered into on October 15, 2014 for the sale of a portion of Nytis LLC’s interest in rights below the base of the Clinton Formation (the “Deep Rights”) underlying certain oil and gas leases located in Kentucky and West Virginia. Pursuant to the PSA, the Sellers reserved (i) a minority working interest in the Deep Rights, (ii) an overriding royalty interest in certain of the Deep Rights and (iii) all rights from the surface to the base of the Clinton formation underlying the leases. In connection with the preliminary closing of this transaction, Nytis LLC received approximately $12.4 million. On June 5, 2015, the final closing was completed. In connection with the final closing of this transaction, Nytis LLC received an additional $42,000 in cash. |
Property and Equipment
Property and Equipment | 6 Months Ended |
Jun. 30, 2015 | |
Property and Equipment [Abstract] | |
Property and Equipment | Note 4 – Property and Equipment Net property and equipment as of June 30, 2015 and December 31, 2014 consists of the following: (in thousands) June 30, December 31, Oil and gas properties: Proved oil and gas properties $ 97,152 $ 95,233 Unproved properties not subject to depletion 2,895 2,789 Accumulated depreciation, depletion, amortization and impairment (65,803 ) (64,535 ) Net oil and gas properties 34,244 33,487 Furniture and fixtures, computer hardware and software, and other equipment 818 1,131 Accumulated depreciation and amortization (579 ) (827 ) Net other property and equipment 239 304 Total net property and equipment $ 34,483 $ 33,791 As of June 30, 2015 and December 31, 2014, the Company had approximately $2.9 million and $2.8 million, respectively, of unproved oil and gas properties not subject to depletion. The costs not subject to depletion relate to unproved properties that are excluded from amortized capital costs until it is determined whether or not proved reserves can be assigned to such properties. The excluded properties are assessed for impairment at least annually. Subject to industry conditions, evaluation of most of these properties and the inclusion of their costs in amortized capital costs is expected to be completed within five years. During the six months ended June 30, 2015 and 2014, the Company capitalized general and administrative expenses applicable to development and exploration activities of approximately $288,000 and $258,000, respectively. Depletion expense related to oil and gas properties for the three and six months ended June 30, 2015 was approximately $661,000, or $1.07 per Mcfe, and approximately $1.3 million, or $0.97 per Mcfe, respectively. For the three and six months ended June 30, 2014, depletion expense was approximately $689,000 and $1.4 million, respectively, or $0.97 per Mcfe for each period. Depreciation and amortization expense related to furniture and fixtures, computer hardware and software and other equipment for the three months ended June 30, 2015 and 2014 was approximately $35,000 and $39,000, respectively and for the six months ended June 30, 2015 and 2014 was approximately $72,000 and $78,000, respectively. |
Equity Method Investment
Equity Method Investment | 6 Months Ended |
Jun. 30, 2015 | |
Equity Method Investment [Abstract] | |
Equity Method Investment | Note 5 – Equity Method Investment The Company has a 50% interest in Crawford County Gas Gathering Company, LLC (“CCGGC”) which owns and operates pipelines and related gathering and treating facilities. The Company’s gas production located in Illinois is gathered and transported on CCGGC’s gathering facilities. The Company’s investment in CCGGC is accounted for under the equity method of accounting, and its share of the income or loss is recognized. For the six months ended June 30, 2015 and 2014, the Company recorded equity investment loss of approximately $1,000 and income of $5,000, respectively, related to its investment in CCGGC. |
Bank Credit Facility
Bank Credit Facility | 6 Months Ended |
Jun. 30, 2015 | |
Bank Credit Facility [Abstract] | |
Bank Credit Facility | Note 6 – Bank Credit Facility Nytis LLC’s credit facility with Bank of Oklahoma has a borrowing base of $20.0 million and a maximum line of credit available under hedging arrangements of $9.5 million. The credit facility matures in May 2017. Carbon and Nytis USA are guarantors of Nytis LLC’s obligations under its credit facility. No repayments of principal are required until maturity, except to the extent that outstanding balances exceed the borrowing base then in effect. The Company has the right both to repay principal at any time and to reborrow. Subject to the agreement between the Company and the lender, the size of the credit facility may be increased up to $50.0 million. The borrowing base is redetermined semi-annually, and the available borrowing amount could be increased or decreased as a result of such redeterminations. Under certain circumstances the lender may request an interim redetermination. The facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base. Interest rates are based on either an Alternate Base Rate or LIBOR. The portion of the loan based on an “Alternate Base Rate” is determined by the rate per annum equal to 1.5% plus the greatest of the following: (a) the Federal Funds Rate for such day plus one-half of one percentage point, (b) the Prime Rate for such day or (c) LIBOR for a one-month LIBOR Interest Period plus one percentage point. The portion based on LIBOR is determined by the rate per annum equal to LIBOR plus between 2.5% and 3.25% for each LIBOR tranche. The credit facility includes a hedging component that provides a line of credit under commodity swap, exchange, collar, cap and fixed price agreements in addition to agreements designated to protect the Company against changes in interest and currency exchange rates. At June 30, 2015, there were approximately $2.8 million in outstanding borrowings and approximately $17.2 million of additional borrowing capacity available under the credit facility. The Company’s effective borrowing rate at June 30, 2015 was approximately 2.8%. The credit facility is collateralized by substantially all of the Company’s oil and gas assets. The credit facility includes terms that place limitations on certain types of activities including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, merger and acquisitions, and the payment of dividends. The credit facility requires satisfaction of a minimum current ratio (the ratio of current assets (including borrowing base capacity) to current liabilities as defined) of 1.0 to 1.0 and a maximum funded debt ratio (the ratio of the outstanding balance of all interest bearing indebtedness to the sum of EBITDAX (net income plus interest expense, income taxes, depreciation, depletion, amortization, exploration and impairment expenses and other non-cash charges)) for the most recently completed fiscal quarter times four of 4.25 to 1.0 as of the end of any fiscal quarter. The Company is in compliance with all covenants associated with the credit agreement as of June 30, 2015. |
Income Taxes
Income Taxes | 6 Months Ended |
Jun. 30, 2015 | |
Income Taxes [Abstract] | |
Income Taxes | Note 7 – Income Taxes The Company recognizes deferred income tax assets and liabilities for the estimated future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. The Company has net operating loss carryforwards available in certain jurisdictions to reduce future taxable income. Future tax benefits for net operating loss carryforwards are recognized to the extent that realization of these benefits is considered more likely than not. To the extent that available evidence raises doubt about the realization of a deferred income tax asset, a valuation allowance is established. At June 30, 2015, the Company has established a full valuation allowance against the balance of net deferred tax assets. |
Stockholders' Equity
Stockholders' Equity | 6 Months Ended |
Jun. 30, 2015 | |
Stockholders' Equity [Abstract] | |
Stockholders' Equity | Note 8 – Stockholders’ Equity Authorized and Issued Capital Stock As of June 30, 2015, the Company had 200,000,000 shares of common stock authorized with a par value of $0.01 per share, of which 108,158,780 were issued and outstanding. The Company also had 1,000,000 shares of preferred stock authorized with a par value of $0.01 per share, none of which were issued and outstanding. During the first six months of 2015, the increase in the Company’s issued and outstanding common stock was a result of the vesting of restricted stock during the period. Equity Plans Prior to Merger Pursuant to the merger of Nytis USA with and into the Company in 2011, all options, warrants and restricted stock were adjusted to reflect the conversion ratio used in the merger. As of June 30, 2015, the Company has approximately 163,000 options outstanding and exercisable, 250,000 warrants outstanding and exercisable and approximately 979,000 shares of common stock outstanding that are subject to restricted stock agreements. Nytis USA Restricted Stock Plan As of June 30, 2015, there were approximately 979,000 shares of restricted stock issued under the Nytis USA Restricted Stock Plan (“Nytis USA Plan”). The Company accounted for these grants at their intrinsic value. From the date of the grant through March 31, 2013, the Company estimated that none of these shares would vest and accordingly, no compensation cost had been recorded through March 31, 2013. In June 2013, the vesting terms of these restricted stock grants were modified so that 25% of the shares would vest on the first of January from 2014 through 2017. As such, the Company is recognizing compensation expense for these restricted stock grants based on the fair value of the shares on the date the vesting terms were modified. Compensation costs recognized for these restricted stock grants were approximately $84,000 for the three months ended June 30, 2015 and 2014 and approximately $167,000 for the six months ended June 30, 2015 and 2014. As of June 30, 2015, there was approximately $503,000 of unrecognized compensation costs related to these restricted stock grants which the Company expects will be recognized ratably over the next 1.5 years. Carbon Stock Incentive Plans The Company has two stock plans, the Carbon 2011 and 2015 Stock Incentive Plans (collectively the “Carbon Plans”). The Carbon Plans were approved by the shareholders of the Company and in the aggregate provide for the issuance of 22.0 million shares of common stock to Carbon’s officers, directors, employees or consultants eligible to receive these awards under the Carbon Plans. The Carbon Plans provide for granting Director Stock Awards to Non-Employee Directors and for granting Incentive Stock Options, Non-qualified Stock Options, Restricted Stock Awards, Performance Awards and Phantom Stock Awards, or a combination of the foregoing as is best suited to the circumstances of the particular employee, officer, director or consultant. Restricted Stock During the six months ended June 30, 2015, approximately 1.7 million shares of restricted stock were granted under the terms of the Carbon Plans in addition to approximately 4.8 million shares granted during previous years. For employees, these restricted stock awards vest ratably over a three-year service period. For non-employee directors, the awards vest upon the earlier of a change in control of the Company or the date their membership on the Board of Directors is terminated other than for cause. The Company recognizes compensation expense for these restricted stock grants based on the estimated grant date fair value of the shares, amortized ratably over three years for employee awards (based on the required service period for vesting) and seven years for non-employee director awards (based on a market survey of the average tenure of directors among U.S. public companies). As of June 30, 2015, approximately 2.6 million of these restricted stock grants have vested. Compensation costs recognized for these restricted stock grants were approximately $199,000 and $220,000 for the three months ended June 30, 2015 and 2014, respectively and approximately $359,000 and $371,000 for the six months ended June 30, 2015 and 2014, respectively. As of June 30, 2015, there was approximately $1.7 million of unrecognized compensation costs related to these restricted stock grants. This cost is expected to be recognized over the next 6.5 years. Restricted Performance Units As of June 30, 2015, approximately 6.4 million shares of restricted performance units have been granted under the terms of the Carbon Plans. The performance units represent a contractual right to receive one share of the Company’s common stock subject to the terms and conditions of the agreements including the achievement of the price of the Company’s stock, net asset value per share, net production per share and adjusted EBITDA (defined as net income (loss) before interest expense, taxes, depreciation, depletion, amortization, accretion of asset retirement obligations, ceiling test write downs of oil and gas properties and the gain or loss on sold investments or properties) per share relative to a defined peer group and the lapse of forfeiture restrictions pursuant to the terms and conditions of the agreements, including for certain of the grants, the requirement of continuous employment by the grantee prior to a change in control of the Company. Based on the relative achievement of performance, approximately 6.3 million restricted performance units are outstanding as of June 30, 2015. The Company accounts for the performance units granted during 2012, 2014 and 2015 at their fair value determined at the date of grant. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At June 30, 2015, the Company estimated that none of the performance units granted in 2012, 2014 and 2015 would vest due to change in control and other performance provisions and accordingly, no compensation cost has been recorded. As of June 30, 2015, if change in control provisions pursuant to the terms and conditions of the agreements are met in full, the estimated unrecognized compensation cost related to the performance units granted in 2012, 2014 and 2015 would be approximately $3.1 million. The performance units granted in 2013 contain specific vesting provisions, no change in control provisions nor any performance conditions other than stock price performance. Due to different vesting requirements compared to the performance units granted in 2012, 2014 and 2015, the Company recognizes compensation expense for the performance units granted in 2013 based on the grant date fair value of the performance units, amortized ratably over three years (the performance period). The fair value of the performance units granted in 2013 was estimated using a Monte Carlo simulation (“MCS”) valuation model using the following key assumptions: no expected dividends, volatility of our stock and those of defined peer companies used to determine our performance relative to the defined peer group, a risk free interest rate and an expected life of three years. Compensation costs recognized for these performance unit grants were approximately $86,000 for the three months ended June 30, 2015 and 2014 and approximately $173,000 for the six months ended June 30, 2015 and 2014. As of June 30, 2015, there was approximately $300,000 of unrecognized compensation costs related to performance units granted in 2013. These costs are expected to be recognized over the next year. |
Accounts Payable and Accrued Li
Accounts Payable and Accrued Liabilities | 6 Months Ended |
Jun. 30, 2015 | |
Accounts Payable and Accrued Liabilities [Abstract] | |
Accounts Payable and Accrued Liabilities | Note 9 – Accounts Payable and Accrued Liabilities Accounts payable and accrued liabilities at June 30, 2015 and December 31, 2014 consist of the following: June 30, December 31, (in thousands) 2015 2014 Accounts payable $ 520 $ 742 Oil and gas revenue payable to oil and gas property owners 1,273 1,296 Production taxes payable 87 132 Drilling advances received from joint venture partner 2,225 2,354 Accrued drilling costs - 166 Accrued lease operating costs 66 74 Accrued ad valorem taxes 919 1,194 Accrued general and administrative expenses 716 1,247 Accrued income taxes payable 77 377 Other accrued liabilities 178 210 Total accounts payable and accrued liabilities $ 6,061 $ 7,792 |
Fair Value Measurements
Fair Value Measurements | 6 Months Ended |
Jun. 30, 2015 | |
Fair Value Measurements [Abstract] | |
Fair Value Measurements | Note 10 – Fair Value Measurements Authoritative guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available under the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows: Level 1: Quoted prices are available in active markets for identical assets or liabilities; Level 2: Quoted prices in active markets for similar assets or liabilities that are observable for the asset or liability; or Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s policy is to recognize transfers in and/or out of the fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed below for all periods presented. The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2015 and December 31, 2014 by level within the fair value hierarchy: Fair Value Measurements Using (in thousands) Level 1 Level 2 Level 3 Total June 30, 2015 Assets: Commodity derivatives $ - $ 557 $ - $ 557 December 31, 2014 Assets: Commodity derivatives $ - $ 1,322 $ - $ 1,322 As of June 30, 2015, the Company’s commodity derivative financial instruments are comprised of four natural gas swap agreements and one oil swap agreement. The fair values of the swap agreements are determined under the income valuation technique using a discounted cash flow model. The valuation model requires a variety of inputs, including contractual terms, published forward prices, volatilities for options, and discount rates, as appropriate. The Company’s estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, the Company’s credit worthiness and the time value of money. The consideration of these factors resulted in an estimated exit-price for each derivative asset or liability under a market place participant’s view. All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s derivative instruments are included within the Level 2 fair value hierarchy. The counterparty in all of the Company’s commodity derivative financial instruments is the lender in the Company’s bank credit facility. Assets Measured and Recorded at Fair Value on a Non-recurring Basis The fair value of the following liabilities measured and recorded at fair value on a non-recurring basis are based on unobservable pricing inputs and therefore, are included within the Level 3 fair value hierarchy. The Company uses the income valuation technique to estimate the fair value of asset retirement obligations using the amounts and timing of expected future dismantlement costs, credit-adjusted risk-free rates and time value of money. During the six months ended June 30, 2015 and 2014, the Company recorded asset retirement obligations for additions of approximately nil and $60,000, respectively. See Note 2 for additional information. |
Physical Delivery Contracts and
Physical Delivery Contracts and Gas Derivatives | 6 Months Ended |
Jun. 30, 2015 | |
Physical Delivery Contracts and Gas Derivatives [Abstract] | |
Physical Delivery Contracts and Gas Derivatives | Note 11 – Physical Delivery Contracts and Gas Derivatives The Company has historically used commodity-based derivative contracts to manage exposure to commodity prices on certain of its oil and natural gas production. The Company does not hold or issue derivative financial instruments for speculative or trading purposes. The Company also enters into oil and natural gas physical delivery contracts to effectively provide price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore these contracts are not recorded at fair value in the Consolidated Financial Statements. At June 30, 2015, the Company has a fixed price contract requiring physical deliveries for approximately 530 Bbl/month at an average sales price of $96.75 per barrel from July through August 2015. The Company’s other physical oil and gas sales contracts provide for sale prices at regional market index prices. The Company’s swap agreements as of June 30, 2015 are summarized in the table below: Natural Gas Oil Weighted Weighted Average Average Period MMBtu Price (a) Bbl Price (b) Jul - Sep 2015 180,000 $ 4.05 2,000 $ 94.80 Oct - Dec 2015 180,000 $ 4.05 - - Jan - Mar 2016 30,000 $ 4.20 - - Apr 2016 10,000 $ 4.20 - - (a) NYMEX Henry Hub Natural Gas futures contract for the respective delivery month. (b) NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective delivery month. For its swap instruments, the Company receives a fixed price for the hedged commodity and pays a floating price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. The following table summarizes the fair value of the derivatives recorded in the Consolidated Balance Sheets. These derivative instruments are not designated as cash flow hedging instruments for accounting purposes: (in thousands) June 30, December 31, Commodity derivative contracts: Current assets $ 557 $ 1,322 The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the three and six months ended June 30, 2015 and 2014. These realized and unrealized gains and losses are recorded and included in commodity derivative gain or loss in the accompanying Consolidated Statements of Operations. Three Months Ended Six Months Ended (in thousands) 2015 2014 2015 2014 Commodity derivative contracts: Realized gains (losses) $ 359 $ (245 ) $ 911 $ (502 ) Unrealized losses (418 ) (33 ) (764 ) (266 ) Total realized and unrealized (losses) gains, net $ (59 ) $ (278 ) $ 147 $ (768 ) Realized gains and losses are included in cash flows from operating activities in the Company’s Consolidated Statements of Cash Flows. The counterparty in all of the Company’s derivative instruments is the lender in the Company’s bank credit facility. Accordingly, the Company is not required to post collateral since the bank is secured by the Company’s oil and gas assets. The Company nets its derivative instrument fair value amounts executed with its counterparty pursuant to an ISDA master agreement, which provides for the net settlement over the term of the contract and in the event of default or termination of the contract. The following table summarizes the location and fair value amounts of all derivative instruments in the Consolidated Balance Sheet as of June 30, 2015, as well as the gross recognized derivative assets, liabilities and amounts offset in the Consolidated Balance Sheet: Net Gross Recognized Recognized Gross Fair Value Assets/ Amounts Assets/ Balance Sheet Classification Liabilities Offset Liabilities (in thousands) Commodity derivative assets: Current derivative asset $ 557 $ - $ 557 Total derivative assets $ 557 $ - $ 557 Due to the volatility of oil and gas prices, the estimated fair value of the Company’s derivatives are subject to large fluctuations from period to period. |
Commitments
Commitments | 6 Months Ended |
Jun. 30, 2015 | |
Commitments [Abstract] | |
Commitments | Note 12 – Commitments The Company has entered into long-term firm transportation contracts to ensure the transport of certain gas production to its purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts at June 30, 2015 are summarized in the table below. Period Dekatherms per day Demand Charges Jul 2015 - Oct 2015 5,950 $ 0.20 - $0.65 Nov 2015 - Apr 2018 4,450 $ 0.20 - $0.65 May 2018 - May 2020 2,150 $ 0.20 Jun 2020 - May 2036 1,000 $ 0.20 A liability of approximately $1.1 million related to firm transportation contracts assumed in a 2011 asset acquisition, which represents the remaining commitment, is reflected on the Company’s Consolidated Balance Sheet as of June 30, 2015. The fair value of these firm transportation obligations were determined based upon the contractual obligations assumed by the Company and discounted based upon the Company’s effective borrowing rate. These contractual obligations are being amortized on a monthly basis as the Company pays these firm transportation obligations in the future. |
Supplemental Cash Flow Disclosu
Supplemental Cash Flow Disclosure | 6 Months Ended |
Jun. 30, 2015 | |
Supplemental Cash Flow Disclosure [Abstract] | |
Supplemental Cash Flow Disclosure | Note 13 – Supplemental Cash Flow Disclosure Supplemental cash flow disclosures for the six months ended June 30, 2015 and 2014 are presented below: Six Months Ended (in thousands) 2015 2014 Cash paid during the period for: Interest $ 60 $ 208 Income taxes $ 325 $ - Non-cash transactions: Increase in net asset retirement obligations $ - $ 60 Decrease in accounts payable and accrued liabilities included in oil and gas properties $ (267 ) $ (603 ) Decrease in accounts receivable included in oil and gas property proceeds $ - $ 462 |
Summary of Significant Accoun20
Summary of Significant Accounting Policies (Policies) | 6 Months Ended |
Jun. 30, 2015 | |
Summary of Significant Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The accompanying unaudited Consolidated Financial Statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, the accompanying unaudited Consolidated Financial Statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of June 30, 2015, the Company’s results of operations for the three and six months ended June 30, 2015 and 2014 and the Company’s cash flows for the six months ended June 30, 2015 and 2014. Operating results for the three and six months ended June 30, 2015 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results and other factors. For a more complete understanding of the Company’s operations, financial position and accounting policies, the unaudited financial statements and the notes thereto should be read in conjunction with the Company’s audited Consolidated Financial Statements for the year ended December 31, 2014 filed on Form 10-K with the Securities and Exchange Commission (“SEC”). In the course of preparing the unaudited financial statements, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenue and expenses and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and accordingly, actual results could differ from amounts initially established. |
Principles of Consolidation | Principles of Consolidation The Consolidated Financial Statements include the accounts of Carbon, Nytis USA and its consolidated subsidiary. Carbon owns 100% of Nytis USA. Nytis USA owns approximately 99% of Nytis LLC. Nytis LLC also holds an interest in various oil and gas partnerships. For partnerships where the Company has a controlling interest, the partnerships are consolidated. The Company is currently consolidating on a pro-rata basis 46 partnerships. In these instances, the Company reflects the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on its Consolidated Statements of Operations and also reflects the non-controlling ownership interests in the net assets of the partnerships as non-controlling interests within stockholders’ equity on its Consolidated Balance Sheets. All significant intercompany accounts and transactions have been eliminated. In accordance with established practice in the oil and gas industry, the Company’s Consolidated Financial Statements also include its pro-rata share of assets, liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which the Company has a non-controlling interest. Non-majority owned investments that do not meet the criteria for pro-rata consolidation are accounted for using the equity method when the Company has the ability to significantly influence the operating decisions of the investee. When the Company does not have the ability to significantly influence the operating decisions of an investee, the cost method is used. All transactions, if any, with investees have been eliminated in the accompanying Consolidated Financial Statements. |
Accounting for Oil and Gas Operations | Accounting for Oil and Gas Operations The Company uses the full cost method of accounting for oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Overhead costs incurred that are directly identified with acquisition, exploration and development activities undertaken by the Company for its own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized. Unproved properties are excluded from amortized capitalized costs until it is determined whether or not proved reserves can be assigned to such properties. The Company assesses its unproved properties for impairment at least annually. Significant unproved properties are assessed individually. Capitalized costs are depleted by an equivalent unit-of-production method, converting oil to gas at the ratio of one barrel of oil to six thousand cubic feet of natural gas. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves. All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred. The Company performs a ceiling test quarterly. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value based measurement. Rather, it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using the un-weighted arithmetic average of the first-day-of-the month price for the previous twelve month period, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs. Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds the capitalized costs in future periods. For the three and six months ended June 30, 2015 and 2014, the Company did not recognize a ceiling test impairment as the Company’s full cost pool did not exceed the ceiling limitations. In December 2014, proceeds from the sale of the Company’s interests in certain leases in Kentucky and West Virginia below the Clinton Formation, referred to as the Deep Rights, were credited to the Company’s full cost pool, which decreased the Company’s net book value of its full cost pool while increasing its ceiling test cushion. Future declines in oil and natural gas prices, and increases in future operating expenses and future development costs could result in impairments of our oil and gas properties in future periods. Because the ceiling test uses the previous twelve month period average commodity price, the effects of declining prices since mid-2014 will have greater impact on the average price used to value our reserves which will lower the ceiling test value in future quarters and may result in an impairment of our oil and gas properties. The effects of price declines will continue to impact the ceiling test value until such time the prices stabilize or improve. Impairment charges are a non-cash charge and accordingly, would not affect cash flow, but would adversely affect our net income and stockholders’ equity. |
Investments in Affiliates | Investments in Affiliates Investments in non-consolidated affiliates are accounted for under either the equity or cost method of accounting as appropriate. The cost method of accounting is used for investments in affiliates in which the Company has less than 20% of the voting interests of a corporate affiliate or less than a 5% interest in a partnership or limited liability company and does not have significant influence. Investments in non-consolidated affiliates, accounted for using the cost method of accounting, are recorded at cost and an impairment assessment of each investment is made annually to determine if a decline in the fair value of the investment, other than temporary, has occurred. A permanent impairment is recognized if a decline in the fair value occurs. If the Company holds between 20% and 50% of the voting interest in a non-consolidated corporate affiliate or greater than a 5% interest in a partnership or limited liability company and exercises significant influence or control, the equity method of accounting is used to account for the investment. The Company’s investment in an affiliate that is accounted for using the equity method of accounting, increases or decreases by the Company’s share of the affiliate’s profits or losses and such profits or losses are recognized in the Company’s Consolidated Statements of Operations. The Company reviews equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred. The amount of the impairment is based on quoted market prices, where available, or other valuation techniques. |
Asset Retirement Obligations | Asset Retirement Obligations The Company’s asset retirement obligations (“ARO”) relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred and the cost of such liability is recorded as an increase in the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability. The estimated ARO liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or increased as a result of a reassessment of expected cash flows and assumptions inherent in the estimation of the liability. Upward revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. AROs are valued utilizing Level 3 fair value measurement inputs. The following table is a reconciliation of the ARO for the six months ended June 30, 2015 and 2014: Six Months Ended (in thousands) 2015 2014 Balance at beginning of period $ 2,968 $ 2,699 Accretion expense 63 58 Additions during period - 60 Balance at end of period $ 3,031 $ 2,817 |
Earnings Per Common Share | Earnings (Loss) Per Common Share Basic earnings or loss per common share is computed by dividing the net income or loss attributable to common shareholders for the period by the weighted average number of common shares outstanding during the period. The shares of restricted common stock granted to certain officers and employees of the Company are included in the computation of basic net income or loss per share only after the shares become fully vested. Diluted earnings per common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise of options and warrants to acquire common stock, computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company with the proceeds from the exercise of options and warrants (which were assumed to have been made at the average market price of the common shares during the reporting period). The following table sets forth the calculation of basic and diluted (loss) income per share: Three Months Ended Six Months Ended (in thousands except per share amounts) 2015 2014 2015 2014 Net (loss) income $ (1,181 ) $ 1,806 $ (1,811 ) $ 3,089 Basic weighted-average common shares outstanding in period 107,166 111,964 106,554 112,489 Add dilutive effects of stock options, warrants and non-vested shares of restricted stock - 5,066 - 5,067 Diluted weighted-average common shares outstanding in period 107,166 117,030 106,554 117,556 Basic net (loss) income per common share $ (0.01 ) $ 0.02 $ (0.02 ) $ 0.03 Diluted net (loss) income per common share $ (0.01 ) $ 0.02 $ (0.02 ) $ 0.03 For the three and six months ended June 30, 2015, the Company had a net loss and therefore, the diluted net loss per share calculation excluded the anti-dilutive effect of approximately 250,000 stocks options and warrants and approximately 5.0 million nonvested shares of restricted stock in each period, respectively. Approximately 6.3 million restricted performance units, in each period respectively, subject to future contingencies are excluded from the basic and diluted loss per share. For the three and six months ended June 30, 2014, the diluted income per common share calculation excludes the dilutive effect of approximately 250,000 warrants that were out-of-the-money and approximately 4.7 million restricted performance units, subject to future contingencies, were excluded from the basic and diluted income per share in each respective period. |
Summary of Significant Accoun21
Summary of Significant Accounting Policies (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Summary of Significant Accounting Policies [Abstract] | |
Summary of reconciliation of the ARO | Six Months Ended (in thousands) 2015 2014 Balance at beginning of period $ 2,968 $ 2,699 Accretion expense 63 58 Additions during period - 60 Balance at end of period $ 3,031 $ 2,817 |
Schedule of basic and diluted (loss) income per share | Three Months Ended Six Months Ended (in thousands except per share amounts) 2015 2014 2015 2014 Net (loss) income $ (1,181 ) $ 1,806 $ (1,811 ) $ 3,089 Basic weighted-average common shares outstanding during the period 107,166 111,964 106,554 112,489 Add dilutive effects of stock options, warrants and non-vested shares of restricted stock - 5,066 - 5,067 Diluted weighted-average common shares outstanding during the period 107,166 117,030 106,554 117,556 Basic net (loss) income per common share $ (0.01 ) $ 0.02 $ (0.02 ) $ 0.03 Diluted net (loss) income per common share $ (0.01 ) $ 0.02 $ (0.02 ) $ 0.03 |
Property and Equipment (Tables)
Property and Equipment (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Property and Equipment [Abstract] | |
Summary of net property and equipment | (in thousands) June 30, December 31, Oil and gas properties: Proved oil and gas properties $ 97,152 $ 95,233 Unproved properties not subject to depletion 2,895 2,789 Accumulated depreciation, depletion, amortization and impairment (65,803 ) (64,535 ) Net oil and gas properties 34,244 33,487 Furniture and fixtures, computer hardware and software, and other equipment 818 1,131 Accumulated depreciation and amortization (579 ) (827 ) Net other property and equipment 239 304 Total net property and equipment $ 34,483 $ 33,791 |
Accounts Payable and Accrued 23
Accounts Payable and Accrued Liabilities (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Accounts Payable and Accrued Liabilities [Abstract] | |
Summary of accounts payable and accrued liabilities | June 30, December 31, (in thousands) 2015 2014 Accounts payable $ 520 $ 742 Oil and gas revenue payable to oil and gas property owners 1,273 1,296 Production taxes payable 87 132 Drilling advances received from joint venture partner 2,225 2,354 Accrued drilling costs - 166 Accrued lease operating costs 66 74 Accrued ad valorem taxes 919 1,194 Accrued general and administrative expenses 716 1,247 Accrued income taxes payable 77 377 Other accrued liabilities 178 210 Total accounts payable and accrued liabilities $ 6,061 $ 7,792 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Fair Value Measurements [Abstract] | |
Summary of financial assets and liabilities at fair value | Fair Value Measurements Using (in thousands) Level 1 Level 2 Level 3 Total June 30, 2015 Assets: Commodity derivatives $ - $ 557 $ - $ 557 December 31, 2014 Assets: Commodity derivatives $ - $ 1,322 $ - $ 1,322 |
Physical Delivery Contracts a25
Physical Delivery Contracts and Gas Derivatives (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Physical Delivery Contracts and Gas Derivatives [Abstract] | |
Schedule of swap agreements | Natural Gas Oil Weighted Weighted Average Average Period MMBtu Price (a) Bbl Price (b) Jul - Sep 2015 180,000 $ 4.05 2,000 $ 94.80 Oct - Dec 2015 180,000 $ 4.05 - - Jan - Mar 2016 30,000 $ 4.20 - - Apr 2016 10,000 $ 4.20 - - |
Schedule of fair value of the derivatives recorded | (in thousands) June 30, December 31, Commodity derivative contracts: Current assets $ 557 $ 1,322 |
Schedule of realized and unrealized gains and losses | Three Months Ended Six Months Ended (in thousands) 2015 2014 2015 2014 Commodity derivative contracts: Realized gains (losses) $ 359 $ (245 ) $ 911 $ (502 ) Unrealized losses (418 ) (33 ) (764 ) (266 ) Total realized and unrealized (losses) gains, net $ (59 ) $ (278 ) $ 147 $ (768 ) |
Schedule of fair value amounts of all derivative instruments assets and liabilities | Net Gross Recognized Recognized Gross Fair Value Assets/ Amounts Assets/ Balance Sheet Classification Liabilities Offset Liabilities (in thousands) Commodity derivative assets: Current derivative asset $ 557 $ - $ 557 Total derivative assets $ 557 $ - $ 557 |
Commitments (Tables)
Commitments (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Commitments [Abstract] | |
Summary of firm transportation volumes and related demand charges | Period Dekatherms per day Demand Charges Jul 2015 - Oct 2015 5,950 $ 0.20 - $0.65 Nov 2015 - Apr 2018 4,450 $ 0.20 - $0.65 May 2018 - May 2020 2,150 $ 0.20 Jun 2020 - May 2036 1,000 $ 0.20 |
Supplemental Cash Flow Disclo27
Supplemental Cash Flow Disclosure (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Supplemental Cash Flow Disclosure [Abstract] | |
Supplemental cash flow disclosures | Six Months Ended (in thousands) 2015 2014 Cash paid during the period for: Interest $ 60 $ 208 Income taxes $ 325 $ - Non-cash transactions: Increase in net asset retirement obligations $ - $ 60 Decrease in accounts payable and accrued liabilities included in oil and gas properties $ (267 ) $ (603 ) Decrease in accounts receivable included in oil and gas property proceeds $ - $ 462 |
Summary of Significant Accoun28
Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
Summary of reconciliation of the ARO | ||
Balance at beginning of period | $ 2,968 | $ 2,699 |
Accretion expense | $ 63 | 58 |
Additions during period | 60 | |
Balance at end of period | $ 3,031 | $ 2,817 |
Summary of Significant Accoun29
Summary of Significant Accounting Policies (Details 1) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Summary of Significant Accounting Policies [Abstract] | ||||
Net (loss) income | $ (1,181) | $ 1,806 | $ (1,811) | $ 3,089 |
Basic weighted-average common shares outstanding during the period | 107,166 | 111,964 | 106,554 | 112,489 |
Add dilutive effects of stock options, warrants and nonvested shares of restricted stock | 5,066 | 5,067 | ||
Diluted weighted-average common shares outstanding during the period | 107,166 | 117,030 | 106,554 | 117,556 |
Basic net (loss) income per common share | $ (0.01) | $ 0.02 | $ (0.02) | $ 0.03 |
Diluted net (loss) income per common share | $ (0.01) | $ 0.02 | $ (0.02) | $ 0.03 |
Summary of Significant Accoun30
Summary of Significant Accounting Policies (Details Textual) shares in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015shares | Jun. 30, 2014shares | Jun. 30, 2015Partnershipshares | Jun. 30, 2014shares | |
Summary of Significant Accounting Policies (Textual) | ||||
Number of consolidated partnerships | Partnership | 46 | |||
Cost method investments, additional information | The Company has less than 20% of the voting interests of a corporate affiliate or less than a 5% interest of a partnership or limited liability company and does not have significant influence. | |||
Equity method investment, additional information | If the Company holds between 20% and 50% of the voting interest in non-consolidated corporate affiliates or greater than a 5% interest of a partnership or limited liability company and exercises significant influence or control, the equity method of accounting is used to account for the investment. | |||
Warrant [Member] | ||||
Summary of Significant Accounting Policies (Textual) | ||||
Anti-dilutive earnings per shares | 5,000 | 5,000 | ||
Stock Options [Member] | ||||
Summary of Significant Accounting Policies (Textual) | ||||
Anti-dilutive earnings per shares | 250,000 | 250,000 | 250,000 | 250,000 |
Restricted Performance Units [Member] | ||||
Summary of Significant Accounting Policies (Textual) | ||||
Common stock equivalent restricted to future contingencies | 6,300 | 4,700 | 6,300 | 4,700 |
Nytis LLC [Member] | ||||
Summary of Significant Accounting Policies (Textual) | ||||
Percentage of ownership interest in the subsidiary | 99.00% | |||
Nytis Usa [Member] | ||||
Summary of Significant Accounting Policies (Textual) | ||||
Percentage of ownership interest in the subsidiary | 100.00% |
Acquisitions and Dispositions (
Acquisitions and Dispositions (Details) - Nytis LLC [Member] - USD ($) $ in Thousands | Oct. 15, 2014 | Jun. 05, 2015 |
Dispositions and Acquisitions [Textual] | ||
Cash transferred | $ 12,400 | |
Addition cash received | $ 42,000 |
Property and Equipment (Details
Property and Equipment (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Oil and gas properties | ||
Accumulated depreciation, depletion, amortization and impairment | $ (65,803) | $ (64,535) |
Net oil and gas properties | 34,244 | 33,487 |
Furniture and fixtures, computer hardware and software, and other equipment | 818 | 1,131 |
Accumulated depreciation and amortization | (579) | (827) |
Net other property and equipment | 239 | 304 |
Total net property and equipment | 34,483 | 33,791 |
Proved oil and gas properties [Member] | ||
Oil and gas properties | ||
Oil and gas properties, gross | 97,152 | 95,233 |
Unproved properties not subject to depletion [Member] | ||
Oil and gas properties | ||
Oil and gas properties, gross | $ 2,895 | $ 2,789 |
Property and Equipment (Detai33
Property and Equipment (Details Textual) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015USD ($)Per_Mcfe | Jun. 30, 2014USD ($)Per_Mcfe | Jun. 30, 2015USD ($)Per_Mcfe | Jun. 30, 2014USD ($)Per_Mcfe | |
Property and Equipment (Textual) | ||||
Depletion expense related to oil and gas properties | $ 2,900 | $ 2,800 | ||
Capitalized general and administrative expenses | 288,000 | 258,000 | ||
Depletion expense related to oil and gas properties | $ 661,000 | $ 689,000 | $ 1,300 | $ 1,400 |
Depletion expense related to oil and gas properties (in dollars per Mcfe) | Per_Mcfe | 1.07 | 0.97 | 0.97 | 0.97 |
Depreciation and amortization expense | $ 35,000 | $ 39,000 | $ 72,000 | $ 78,000 |
Equity Method Investment (Detai
Equity Method Investment (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Equity Method Investment (Textual) | ||||
Ownership interest percentage in crawford county gas gathering company, LLC | 50.00% | 50.00% | ||
Equity investment income (loss) in crawford county gas gathering company, LLC | $ (2) | $ 2 | $ (1) | $ 5 |
Bank Credit Facility (Details)
Bank Credit Facility (Details) - Jun. 30, 2015 - USD ($) $ in Millions | Total |
Bank Credit Facility (Textual) | |
Current borrowing base | $ 20 |
Maximum line of credit available under hedging arrangements | $ 9.5 |
Line of credit facility maturity date | May 31, 2017 |
Maximum borrowing base | $ 50 |
Outstanding borrowings | 2.8 |
Additional borrowing capacity available | $ 17.2 |
Effective borrowing rate (as a percent) | 2.80% |
Minimum [Member] | |
Bank Credit Facility (Textual) | |
Current ratio required to be maintained | 1 |
Funded Debt Ratio required to be maintained | 1 |
Maximum [Member] | |
Bank Credit Facility (Textual) | |
Current ratio required to be maintained | 1 |
Funded Debt Ratio required to be maintained | 4.25 |
Credit facility [Member] | |
Bank Credit Facility (Textual) | |
Variable interest rate basis | The portion of the loan based on an "Alternate Base Rate" is determined by the rate per annum equal to 1.5% plus the greatest of the following: (a) the Federal Funds Rate for such day plus one-half of one percentage point, (b) the Prime Rate for such day or (c) LIBOR for a one-month LIBOR Interest Period plus one percentage point. |
Credit facility [Member] | LIBOR [Member] | Minimum [Member] | |
Bank Credit Facility (Textual) | |
Percentage points added to the reference rate | 2.50% |
Credit facility [Member] | LIBOR [Member] | Maximum [Member] | |
Bank Credit Facility (Textual) | |
Percentage points added to the reference rate | 3.25% |
Stockholders' Equity (Details)
Stockholders' Equity (Details) - USD ($) $ / shares in Units, $ in Thousands | Jun. 25, 2013 | Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | Dec. 31, 2012 |
Stockholders' Equity (Textual) | |||||||
Common stock, shares authorized | 200,000,000 | 200,000,000 | 200,000,000 | ||||
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 | $ 0.01 | ||||
Common stock, shares issued | 108,158,780 | 108,158,780 | 106,875,447 | ||||
Common stock, shares outstanding | 108,158,780 | 108,158,780 | 106,875,447 | ||||
Preferred stock, shares authorized | 1,000,000 | 1,000,000 | 1,000,000 | ||||
Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 | $ 0.01 | ||||
Preferred stock, shares issued | |||||||
Preferred stock, shares outstanding | |||||||
Number of warrants granted in period | 6,400,000 | ||||||
Compensation costs for restricted stock grants | $ 84,000 | $ 84,000 | $ 167,000 | $ 167,000 | |||
Unrecognized compensation cost | 503,000 | 503,000 | |||||
Restricted performance units | 4,800 | $ 4,800 | |||||
Warrant [Member] | |||||||
Stockholders' Equity (Textual) | |||||||
Number of warrants granted by SLSC | 250,000 | ||||||
Restricted Stock Units (RSUs) [Member] | |||||||
Stockholders' Equity (Textual) | |||||||
Number of warrants granted in period | 1,700,000 | ||||||
Compensation costs for restricted stock grants | 199,000 | 220,000 | $ 359,000 | 371,000 | |||
Expected period of recognition of unrecognized compensation costs | 6 years 6 months | ||||||
Value of restricted stock grants have vested | $ 2,600 | ||||||
Restricted Performance Units [Member] | |||||||
Stockholders' Equity (Textual) | |||||||
Compensation costs for restricted stock grants | 86,000 | $ 86,000 | 173,000 | $ 173,000 | |||
Unrecognized compensation cost | 300,000 | 300,000 | $ 3,100 | $ 3,100 | |||
Restricted performance units | $ 6,300 | $ 6,300 | |||||
Equity Plans Prior To Merger [Member] | Stock Options [Member] | |||||||
Stockholders' Equity (Textual) | |||||||
Number of shares outstanding | 163,000 | 163,000 | |||||
Number of shares exercisable | 163,000 | 163,000 | |||||
Equity Plans Prior To Merger [Member] | Warrant [Member] | |||||||
Stockholders' Equity (Textual) | |||||||
Number of shares outstanding | 250,000 | 250,000 | |||||
Number of shares exercisable | 250,000 | 250,000 | |||||
Equity Plans Prior To Merger [Member] | Restricted Stock Units (RSUs) [Member] | |||||||
Stockholders' Equity (Textual) | |||||||
Number of shares outstanding | 979,000 | 979,000 | |||||
Nytis USA Restricted Stock Plan [Member] | |||||||
Stockholders' Equity (Textual) | |||||||
Vesting terms of restricted stock | The vesting terms of these restricted stock grants were modified so that 25% of the shares would vest on the first of January from 2014 through 2017. | ||||||
Expected period of recognition of unrecognized compensation costs | 1 year 6 months | ||||||
Vesting, percentage | 25.00% | ||||||
Carbon 2011 Stock Incentive Plan [Member] | Officer [Member] | |||||||
Stockholders' Equity (Textual) | |||||||
Stock incentive plan, common stock shares authorized | 22,000,000 | 22,000,000 |
Accounts Payable and Accrued 37
Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Accounts Payable and Accrued Liabilities [Abstract] | ||
Accounts payable | $ 520 | $ 742 |
Oil and gas revenue payable to oil and gas property owners | 1,273 | 1,296 |
Production taxes payable | 87 | 132 |
Drilling advances received from joint venture partner | $ 2,225 | 2,354 |
Accrued drilling costs | 166 | |
Accrued lease operating costs | $ 66 | 74 |
Accrued ad valorem taxes | 919 | 1,194 |
Accrued general and administrative expenses | 716 | 1,247 |
Accrued income taxes payable | 77 | 377 |
Other accrued liabilities | 178 | 210 |
Total accounts payable and accrued liabilities | $ 6,061 | $ 7,792 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Assets: | ||
Commodity derivatives | $ 557 | $ 1,322 |
Recurring basis [Member] | Level 1 [Member] | ||
Assets: | ||
Commodity derivatives | ||
Recurring basis [Member] | Level 2 [Member] | ||
Assets: | ||
Commodity derivatives | $ 557 | $ 1,322 |
Recurring basis [Member] | Level 3 [Member] | ||
Assets: | ||
Commodity derivatives |
Fair Value Measurements (Deta39
Fair Value Measurements (Details Textual) - USD ($) $ in Thousands | Jun. 30, 2015 | Jun. 30, 2014 |
Fair Value Measurements Textual [Abstract] | ||
Asset retirement obligation | $ 60,000 |
Physical Delivery Contracts a40
Physical Delivery Contracts and Gas Derivatives (Details) - Jun. 30, 2015 - Swap [Member] | USD_MMBtu$ / shares | |
Jul - Sep 2015 [Member] | Natural Gas [Member] | NYMEX Henry Hub Natural Gas Futures Contract [Member] | ||
Summary of swap agreements | ||
Quantity | 180,000 | |
Weighted Average Price | $ / shares | [1] | $ 4.05 |
Jul - Sep 2015 [Member] | Oil [Member] | NYMEX Light Sweet Crude West Texas Intermediate Futures Contract [Member] | ||
Summary of swap agreements | ||
Quantity | 2,000 | |
Weighted Average Price | $ / shares | [2] | $ 94.80 |
Oct - Dec 2015 [Member] | Natural Gas [Member] | NYMEX Henry Hub Natural Gas Futures Contract [Member] | ||
Summary of swap agreements | ||
Quantity | 180,000 | |
Weighted Average Price | $ / shares | [1] | $ 4.05 |
Oct - Dec 2015 [Member] | Oil [Member] | NYMEX Light Sweet Crude West Texas Intermediate Futures Contract [Member] | ||
Summary of swap agreements | ||
Quantity | ||
Weighted Average Price | $ / shares | [2] | |
Jan - Mar 2016 [Member] | Natural Gas [Member] | NYMEX Henry Hub Natural Gas Futures Contract [Member] | ||
Summary of swap agreements | ||
Quantity | 30,000 | |
Weighted Average Price | $ / shares | [1] | $ 4.20 |
Jan - Mar 2016 [Member] | Oil [Member] | NYMEX Light Sweet Crude West Texas Intermediate Futures Contract [Member] | ||
Summary of swap agreements | ||
Quantity | ||
Weighted Average Price | $ / shares | [2] | |
Apr 2016 [Member] | Natural Gas [Member] | NYMEX Henry Hub Natural Gas Futures Contract [Member] | ||
Summary of swap agreements | ||
Quantity | 10,000 | |
Weighted Average Price | $ / shares | [1] | $ 4.20 |
Apr 2016 [Member] | Oil [Member] | NYMEX Light Sweet Crude West Texas Intermediate Futures Contract [Member] | ||
Summary of swap agreements | ||
Quantity | ||
Weighted Average Price | $ / shares | [2] | |
[1] | (a) NYMEX Henry Hub Natural Gas futures contract for the respective delivery month. | |
[2] | (b) NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective delivery month. |
Physical Delivery Contracts a41
Physical Delivery Contracts and Gas Derivatives (Details 1) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Commodity derivative contracts: | ||
Current assets | $ 557 | $ 1,322 |
Physical Delivery Contracts a42
Physical Delivery Contracts and Gas Derivatives (Details 2) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Commodity derivative contracts: | ||||
Unrealized losses | $ (764) | $ (266) | ||
Commodity derivative contracts [Member] | ||||
Commodity derivative contracts: | ||||
Realized gains (losses) | $ 359 | $ (245) | 911 | (502) |
Unrealized losses | (418) | (33) | (764) | (266) |
Total realized and unrealized (losses) gains, net | $ (59) | $ (278) | $ 147 | $ (768) |
Physical Delivery Contracts a43
Physical Delivery Contracts and Gas Derivatives (Details 3) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Commodity derivative assets: | ||
Current derivative asset | $ 557 | $ 1,322 |
Gross Recognized Assets/Liabilities [Member] | ||
Commodity derivative assets: | ||
Current derivative asset | 557 | |
Total derivative assets | $ 557 | |
Gross Amounts Offset [Member] | ||
Commodity derivative assets: | ||
Current derivative asset | ||
Total derivative assets | ||
Net Recognized Fair Value Assets/Liabilities [Member] | ||
Commodity derivative assets: | ||
Current derivative asset | $ 557 | |
Total derivative assets | $ 557 |
Physical Delivery Contracts a44
Physical Delivery Contracts and Gas Derivatives (Details Textual) - Jun. 30, 2015 - April 2015 through August 2015 [Member] | Per_McfeUSD_MMBtu |
Physical Delivery Contracts and Commodity Derivatives (Textual) | |
Physical deliveries required for fixed price contracts (in Bbl per month) | 530 |
Average sales price (in dollars per Bbl) | Per_Mcfe | 96.75 |
Commitments (Details)
Commitments (Details) - 6 months ended Jun. 30, 2015 | Per_McfePartnership |
Jul 2015 - Oct 2015 | |
Other Commitments [Line Items] | |
Capacity levels (Dekatherms per day) | Partnership | 5,950 |
Jul 2015 - Oct 2015 | Maximum [Member] | |
Other Commitments [Line Items] | |
Demand charges (in dollars per dekatherm) | 0.65 |
Jul 2015 - Oct 2015 | Minimum [Member] | |
Other Commitments [Line Items] | |
Demand charges (in dollars per dekatherm) | 0.20 |
Nov 2015 - Apr 2018 | |
Other Commitments [Line Items] | |
Capacity levels (Dekatherms per day) | Partnership | 4,450 |
Nov 2015 - Apr 2018 | Maximum [Member] | |
Other Commitments [Line Items] | |
Demand charges (in dollars per dekatherm) | 0.65 |
Nov 2015 - Apr 2018 | Minimum [Member] | |
Other Commitments [Line Items] | |
Demand charges (in dollars per dekatherm) | 0.20 |
May 2018 - May 2020 | |
Other Commitments [Line Items] | |
Capacity levels (Dekatherms per day) | Partnership | 2,150 |
Demand charges (in dollars per dekatherm) | 0.20 |
Jun 2020 - May 2036 | |
Other Commitments [Line Items] | |
Capacity levels (Dekatherms per day) | Partnership | 1,000 |
Demand charges (in dollars per dekatherm) | 0.20 |
Commitments (Details Textual)
Commitments (Details Textual) $ in Millions | Jun. 30, 2015USD ($) |
Commitments (Textual) | |
Liability related to firm transportation contracts assumed | $ 1.1 |
Supplemental Cash Flow Disclo47
Supplemental Cash Flow Disclosure (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
Cash paid during the period for: | ||
Interest | $ 60 | $ 208 |
Income taxes | $ 325 | |
Non-cash transactions: | ||
Increase in net asset retirement obligations | $ 60 | |
Decrease in accounts payable and accrued liabilities included in oil and gas properties | $ (267) | (603) |
Decrease in accounts receivable included in oil and gas property proceeds | $ 462 |