Carbon Energy (CRBO) 10-Q 23 May 16 2016 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	May. 10, 2016
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	Mar. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q1
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		110,638,849

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 456	$ 305
Accounts receivable:
Revenue	963	1,082
Joint interest billings and other	617	778
Commodity derivative asset	362	408
Prepaid expense, deposits and other current assets	252	213
Total current assets	2,650	2,786
Oil and gas properties, full cost method of accounting:
Proved, net	21,013	25,032
Unproved	3,146	3,194
Other property and equipment, net	216	238
Total property and equipment, net	24,375	28,464
Investments in affiliates (note 5)	751	1,025
Other long-term assets	371	433
Total assets	28,147	32,708
Current liabilities:
Accounts payable and accrued liabilities	5,606	5,621
Firm transportation contract obligations (note 12)	430	436
Notes payable (note 6)	3,900
Total current liabilities	9,936	6,057
Non-current liabilities:
Firm transportation contract obligations (note 12)	311	416
Asset retirement obligations (note 3)	$ 3,135	3,095
Notes payable (note 6)		3,500
Total non-current liabilities	$ 3,446	$ 7,011
Commitments (note 12)
Stockholders' equity:
Preferred stock, $0.01 par value; authorized 1,000,000 shares, no shares issued and outstanding at March 31, 2016 and December 31, 2015
Common stock, $0.01 par value; authorized 200,000,000 shares, 108,082,583 and 107,655,916 shares issued and outstanding at March 31, 2016 and December 31, 2015 respectively	$ 1,081	$ 1,077
Additional paid-in capital	54,761	54,394
Accumulated deficit	(43,057)	(38,130)
Total Carbon stockholders' equity	12,785	17,341
Non-controlling interests	1,980	2,299
Total stockholders' equity	14,765	19,640
Total liabilities and stockholders' equity	$ 28,148	$ 32,708

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Mar. 31, 2016	Dec. 31, 2015
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	108,082,583	107,655,916
Common stock, shares outstanding	108,082,583	107,655,916

Consolidated Statements of Oper

Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Revenue:
Oil sales	$ 628	$ 1,518
Natural gas sales	1,092	1,618
Commodity derivative income	140	206
Other income	1	51
Total revenue	1,861	3,393
Expenses:
Lease operating expenses	589	835
Transportation costs	372	398
Production and property taxes	135	199
General and administrative	1,523	1,875
Depreciation, depletion and amortization	503	645
Accretion of asset retirement obligations	35	$ 31
Impairment of oil and gas properties	3,890
Total expenses	7,047	$ 3,983
Operating loss	(5,186)	(590)
Other income and (expense):
Interest expense	$ (57)	(44)
Other		(25)
Equity investment income		1
Total other expense	$ (57)	(68)
Loss before income taxes	$ (5,243)	$ (658)
Provision for income taxes
Net loss before non-controlling interests	$ (5,243)	$ (658)
Net loss attributable to non-controlling interests	(316)	(28)
Net loss attributable to controlling interest	$ (4,927)	$ (630)
Net loss per common share:
Basic	$ (0.05)	$ (0.01)
Diluted	$ (0.05)	$ (0.01)
Weighted average common shares outstanding:
Basic	107,180	105,934
Diluted	107,180	105,934

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity (Unaudited) - 3 months ended Mar. 31, 2016 - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Non-Controlling Interests	Accumulated Deficit
Beginning balance at Dec. 31, 2015	$ 19,640	$ 1,077	$ 54,394	$ 2,299	$ (38,130)
Beginning balances, shares at Dec. 31, 2015		107,655
Stock-based compensation	$ 371		$ 371
Restricted stock vested		$ 4	$ (4)
Restricted stock vested, shares		428
Non-controlling interest distributions, net	$ (3)			$ (3)
Net loss	(5,243)			(316)	$ (4,927)
Ending balance at Mar. 31, 2016	$ 14,765	$ 1,081	$ 54,761	$ 1,980	$ (43,057)
Ending balances, shares at Mar. 31, 2016		108,083

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Cash flows from operating activities:
Net loss	$ (5,243)	$ (658)
Items not involving cash:
Depreciation, depletion and amortization	503	645
Accretion of asset retirement obligations	35	$ 31
Impairment of oil and gas properties	3,890
Unrealized commodity derivative loss	62	$ 346
Stock-based compensation expense	$ 371	331
Equity investment income		(1)
Net change in:
Accounts receivable	$ 320	851
Prepaid expenses, deposits and other current assets	(39)	(96)
Accounts payable, accrued liabilities and firm transportation obligations	(163)	(1,667)
Net cash used in operating activities	(264)	(218)
Cash flows from investing activities:
Development and acquisition of properties and equipment	(262)	(1,237)
Other long-term assets	5	$ 271
Equity investment distribution	275
Net cash provided by (used in) investing activities	18	$ (966)
Cash flows from financing activities:
Proceeds from notes payable	600	$ 800
Payments on notes payable	(200)
Distributions to non-controlling interests	(3)	$ (51)
Net cash provided by financing activities	397	749
Net increase (decrease) in cash and cash equivalents	151	(435)
Cash and cash equivalents, beginning of period	305	1,132
Cash and cash equivalents, end of period	$ 456	$ 697

Organization

Organization	3 Months Ended
	Mar. 31, 2016
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.

Going Concern

Going Concern	3 Months Ended
	Mar. 31, 2016
Going Concern [Abstract]
Going Concern	Note 2 – Going Concern The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these consolidated financial statements. On May 17, 2016, Nytis LLC, entered into an amendment to its credit facility with Bank of Oklahoma that reduced the borrowing base under the credit facility from $20.0 million to $5.5 million (of which $500,000 is reserved for future interest payments as those payments become due under the credit facility) and changed the maturity date of the credit facility from May 31, 2017 to January 2, 2017. At March 31, 2016, the Company was in compliance with all of its financial covenants associated with the credit agreement. As a result of the reduction in the borrowing base (and associated borrowing base capacity), the Company is no longer in compliance with the minimum current ratio required under the credit facility nor does it expect to be throughout the remainder of the year. As such, without a waiver, Bank of Oklahoma would have the ability to call the debt. In addition, with the change in the maturity of the credit facility from May 31, 2017 to January 2, 2017, outstanding borrowings under the credit facility were classified as current on the Company’s Consolidated Balance Sheet as of March 31, 2016, resulting in negative working capital of approximately $7.3 million. We are in the process of analyzing various alternatives to enhance our liquidity and capital structure including obtaining a new credit facility, issuing additional equity, divesting nonstrategic assets, reducing costs or similar type activities. Although management believes that it will be able to obtain the necessary funding to allow the Company to remain a going concern through the methods discussed above, there can be no assurance that such methods will prove successful. The accompanying Consolidated Financial Statements do not include any adjustments that might result from the outcome of this uncertainty.

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2016
Summary of Significant Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 3 – 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 March 31, 2016 and the Company’s results of operations and cash flows for the three months ended March 31, 2016 and 2015. Operating results for the three months ended March 31, 2016 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, 2015 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 months ended March 31, 2016, the Company recognized a ceiling test impairment of approximately $3.9 million. For the three months ended March 31, 2015, the Company did not recognize a ceiling test impairment as the Company’s full cost pool did not exceed the ceiling limitation. Future declines in oil and natural gas prices, and increases in future operating expenses and future development costs could result in additional impairments of our oil and gas properties in future periods. The effects of price declines will continue to impact the ceiling test value until such time prices stabilize or improve. Impairment charges are a non-cash charge and accordingly, do not affect cash flow, but 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 of 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 impairment assessments for each investment are 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 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. 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 three months ended March 31, 2016 and 2015: 2016 2015 Balance at beginning of period $ 3,095 $ 2,968 Accretion expense 35 31 Additions during period 5 - Balance at end of period $ 3,135 $ 2,999 Earnings 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, directors 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 2016 2015 Net loss $ (4,927 ) $ (630 ) Basic weighted-average common shares outstanding in period 107,180 105,934 Add dilutive effects of stock options, warrants and nonvested shares of restricted stock - - Diluted weighted-average common shares outstanding in period 107,180 105,934 Basic net loss per common share $ (0.05 ) $ (0.01 ) Diluted net loss per common share $ (0.05 ) $ (0.01 ) For the quarter ended March 31, 2016, the Company had a net loss and therefore, the diluted net loss per share calculation for that period excludes the anti-dilutive effect of approximately 250,000 warrants and approximately 5.8 million nonvested shares of restricted stock. In addition, approximately 6.3 million restricted performance units subject to future contingencies were excluded from the basic and diluted loss per share calculations. For the quarter ended March 31, 2015, the Company had a net loss and therefore, the diluted net loss per share calculation for that period excludes the anti-dilutive effect of approximately 2.7 million stock options and warrants, approximately 4.1 million nonvested shares of restricted stock and approximately 4.7 million restricted performance units, subject to future contingencies, were excluded from the basic and diluted loss per share calculations. Adopted and Recently Issued Accounting Pronouncements In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Improvements To Employee Share-Based Payment Accounting In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases

Property and Equipment

Property and Equipment	3 Months Ended
	Mar. 31, 2016
Property and Equipment [Abstract]
Property and Equipment	Note 4 – Property and Equipment Net property and equipment as of March 31, 2016 and December 31, 2015 consists of the following: (in thousands) March 31, 2016 December 31, 2015 Oil and gas properties: Proved oil and gas properties $ 97,796 $ 97,453 Unproved properties not subject to depletion 3,146 3,194 Accumulated depreciation, depletion, amortization and impairment (76,783 ) (72,421 ) Net oil and gas properties 24,159 28,226 Furniture and fixtures, computer hardware and software, and other equipment 803 825 Accumulated depreciation and amortization (587 ) (587 ) Net other property and equipment 216 238 Total net property and equipment $ 24,375 $ 28,464 As of March 31, 2016 and December 31, 2015, the Company had approximately $3.2 million 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 three months ended March 31, 2016 and 2015, the Company capitalized general and administrative expenses applicable to development and exploration activities of approximately $133,000 and $132,000, respectively. Depletion expense related to oil and gas properties for the three months ended March 31, 2016 and 2015 was approximately $472,000, or $0.79 per Mcfe, and $608,000, or $0.87 per Mcfe, respectively. Depreciation and amortization expense related to furniture and fixtures, computer hardware and software and other equipment for the three months ended March 31, 2016 and 2015 was approximately $31,000 and $37,000, respectively.

Equity Method Investment

Equity Method Investment	3 Months Ended
	Mar. 31, 2016
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 treatment facilities. The Company’s gas production located in Illinois is gathered by CCGGC’s gathering facilities. The Company’s investment in CCGGC is accounted for under the equity method of accounting, and its share of income or loss is recognized. During the three months ended March 31, 2016 and 2015, the Company recorded equity method income of approximately nil and $1,000, respectively, related to this investment. In addition, during the first quarter of 2016, the Company received a cash distribution of $275,000 from CCGGC.

Bank Credit Facility

Bank Credit Facility	3 Months Ended
	Mar. 31, 2016
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 designed to protect the Company against changes in interest and currency exchange rates. At March 31, 2016, there were approximately $3.9 million in outstanding borrowings and approximately $16.1 million of borrowing capacity available under the credit facility. The Company’s effective borrowing rate at March 31, 2016 was approximately 3.0%. 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, mergers 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 was in compliance with all covenants associated with the credit agreement as of March 31, 2016. On May 17, 2016, Nytis LLC entered into an amendment to its credit facility with Bank of Oklahoma that reduced the borrowing base under the credit facility from $20.0 million to $5.5 million (of which $500,000 is reserved for future interest payments as those payments become due under the credit facility) and changed the maturity date of the credit facility from May 31, 2017 to January 2, 2017. On May 17, 2016 the Company had approximately $4.0 million in outstanding borrowings under the credit facility and approximately $300,000 of available cash. As a result of a reduction in the borrowing base (and associated borrowing base capacity), the Company is no longer is compliance with the minimum current ratio required under the credit facility. In addition, the amendment to the credit agreement provided waivers from Bank of Oklahoma regarding Nytis LLC’s consistent past practice of advancing funding for general and administrative expenses of Carbon and ratified and affirmed the respective obligations for both Bank of Oklahoma and Nytis LLC under the credit facility.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2016
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 March 31, 2016, the Company has established a full valuation allowance against the balance of net deferred tax assets.

Stockholders' Equity

Stockholders' Equity	3 Months Ended
	Mar. 31, 2016
Stockholders' Equity [Abstract]
Stockholders' Equity	Note 8 – Stockholders’ Equity Authorized and Issued Capital Stock As of March 31, 2016, the Company had 200,000,000 shares of common stock authorized with a par value of $0.01 per share, of which 108,082,583 were issued and outstanding and 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 three months of 2016, the increase in the Company’s issued and outstanding common stock was a result of restricted stock that vested 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 March 31, 2016, the Company has 250,000 warrants outstanding and exercisable and approximately 489,000 shares of common stock outstanding that are subject to restricted stock agreements. Nytis USA Restricted Stock Plan As of March 31, 2016, there were approximately 489,000 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 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 expense recognized for these restricted stock grants was approximately $84,000 for the three months ended March 31, 2016 and 2015. As of March 31, 2016, there was approximately $252,000 of unrecognized compensation costs related to these restricted stock grants which the Company expects will be recognized ratably over the next nine months. 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 22.6 million shares of common stock to Carbon 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 three months ended March 31, 2016, approximately 1.7 million shares of restricted stock were granted under the terms of the Carbon Plan in addition to approximately 6.6 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 March 31, 2016, approximately 3.0 million of these restricted stock grants have vested. Compensation costs recognized for these restricted stock grants were approximately $201,000 and $160,000 for the three months ended March 31, 2016 and 2015, respectively. As of March 31, 2016, there was approximately $1.1 million of unrecognized compensation costs related to these restricted stock grants. This cost is expected to be recognized over the next 6.8 years. Restricted Performance Units As of March 31, 2016, approximately 6.4 million shares of restricted performance units have been granted under the terms of the Carbon Plan. 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 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 of the restricted performance units are outstanding as of March 31, 2016. 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 March 31, 2016, 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 March 31, 2016, if change in control and other performance provisions pursuant to the terms and conditions of these 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 earning 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 March 31, 2016 and 2015. As of March 31, 2016, there was approximately $41,000 of unrecognized compensation costs related to performance units granted in 2013. These costs are expected to be recognized over the next three months.

Accounts Payable and Accrued Li

Accounts Payable and Accrued Liabilities	3 Months Ended
	Mar. 31, 2016
Accounts Payable and Accrued Liabilities [Abstract]
Accounts Payable and Accrued Liabilities	Note 9 – Accounts Payable and Accrued Liabilities Accounts payable and accrued liabilities at March 31, 2016 and December 31, 2015 consist of the following: (in thousands) March 31, 2016 December 31, 2015 Accounts payable $ 701 $ 577 Oil and gas revenue payable to oil and gas property owners 1,062 1,221 Production taxes payable 57 59 Drilling advances received from joint venture partner 2,105 2,115 Accrued drilling costs 112 112 Accrued lease operating costs 54 76 Accrued ad valorem taxes 501 496 Accrued general and administrative expenses 797 833 Other liabilities 217 132 Total accounts payable and accrued liabilities $ 5,606 $ 5,621

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2016
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 March 31, 2016 and December 31, 2015 by level within the fair value hierarchy: Fair Value Measurements Using (in thousands) Level 1 Level 2 Level 3 Total March 31, 2016 Assets: Commodity derivatives $ - $ 496 $ - $ 496 December 31, 2015 Assets: Commodity derivatives $ - $ 559 $ - $ 559 As of March 31, 2016, the Company’s commodity derivative financial instruments are comprised of three natural gas swap agreements and one natural gas and four oil costless collar agreements. The fair values of these agreements are determined under an income valuation technique. The valuation 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 three months ended March 31, 2016 and 2015, the Company recorded asset retirement obligations for additions of approximately $5,000 and nil, respectively. See Note 3 for additional information.

Physical Delivery Contracts and

Physical Delivery Contracts and Oil and Gas Derivatives	3 Months Ended
	Mar. 31, 2016
Physical Delivery Contracts and Oil and Gas Derivatives [Abstract]
Physical Delivery Contracts and Oil and Gas Derivatives	Note 11– Physical Delivery Contracts and Oil and Gas Derivatives The Company has historically used commodity-based derivative contracts to manage exposures to commodity price 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 gas physical delivery contracts to effectively provide gas price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives and therefore these contracts are not recorded at fair value in the Consolidated Financial Statements. As of March 31, 2016, the Company has two short-term physical delivery contracts which require the Company to deliver fixed volumes of natural gas. The Company has sufficient production from its natural gas producing properties delivering to the specific meters under these contracts. The following table summarizes the future production volumes to be delivered and sold under these contracts: Daily Volume Period (Dths per day) Price Contract 1 Apr - Oct 2016 1,000 Index less $0.29 Contract 2 Apr - Sep 2016 611 98% of Index less $0.23 The Company’s other oil and gas sales contracts approximate index prices. The Company’s costless collar and swap agreements as of March 31, 2016 are summarized in the table below: Natural Gas Oil Weighted Weighted Average Average Quarter MMBtu Price (a)( c) Bbl Price (b)( c) Swaps: Apr - Jun 2016 40,000 $ 3.39 - - Jul - Sep 2016 30,000 $ 3.12 - - Oct - Dec 2016 30,000 $ 3.12 - - Jan - Mar 2017 30,000 $ 3.27 - - Apr - Jun 2017 30,000 $ 3.27 - - Jul - Sep 2017 30,000 $ 3.27 - - Oct - Dec 2017 30,000 $ 3.27 - - Collars: Apr - Jun 2016 30,000 $ 2.75 - $3.40 6,000 $ 50.00 - $59.00 Jul - Sep 2016 30,000 $ 2.75 - $3.40 5,500 $ 48.64 - $57.91 Oct - Dec 2016 30,000 $ 2.75 - $3.40 4,500 $ 48.33 - $58.00 Jan - Mar 2017 - - 4,500 $ 48.33 - $61.67 Apr - Jun 2017 - - 4,500 $ 48.33 - $61.67 Jul - Sep 2017 - 4,500 $ 48.33 - $61.67 Oct - Dec 2017 - - 4,500 $ 48.33 - $61.67 (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 (c) NYMEX costless collar floor to ceiling prices. 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) March 31, 2016 December 31, 2015 Commodity derivative contracts: Current assets $ 362 $ 408 Other long-term assets 134 151 The table below summarizes the commodity settlements and unrealized gains and losses related to the Company’s derivative instruments for the three months ended March 31, 2016 and 2015. These commodity derivative settlements and unrealized gains and losses are recorded and included in commodity derivative income or loss in the accompanying Consolidated Statements of Operations. (in thousands) Three Months Ended 2016 2015 Commodity derivative contracts: Settlement gains $ 202 $ 552 Unrealized losses (62 ) (346 ) Total settlement and unrealized gains, net $ 140 $ 206 Commodity derivative settlement 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 March 31, 2016, 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 Commodity derivative assets: Current assets $ 378 $ (16 ) $ 362 Other long-term assets 163 (29 ) 134 Total derivative assets $ 541 $ (45 ) $ 496 Commodity derivative liabilities: Current liability $ 16 $ (16 ) $ - Non-current liabilities 29 (29 ) - Total derivative liabilities $ 45 $ (45 ) $ - Due to the volatility of oil and natural gas prices, the estimated fair values of the Company’s derivatives are subject to large fluctuations from period to period.

Commitments

Commitments	3 Months Ended
	Mar. 31, 2016
Commitments [Abstract]
Commitments	Note 12 – Commitments The Company has entered into long-term firm transportation contracts to ensure the transport for certain of its natural gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts at March 31, 2016 are summarized in the table below. Period Dekatherms per day Demand Charges Apr 2016 - 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 $741,000 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 March 31, 2016. 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	3 Months Ended
	Mar. 31, 2016
Supplemental Cash Flow Disclosure [Abstract]
Supplemental Cash Flow Disclosure	Note 13 – Supplemental Cash Flow Disclosure Supplemental cash flow disclosures for the three months ended March 31, 2016 and 2015 are presented below: Three Months Ended March 31, (in thousands) 2016 2015 Cash paid during the period for: Interest $ 53 $ 26 Income taxes $ - $ 325 Non-cash transactions: Increase in net asset retirement obligations $ 5 $ - Increase in accounts payable and accrued liabilities included in oil and gas properties $ 38 $ 18

Summary of Significant Accoun20

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2016
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 March 31, 2016 and the Company’s results of operations and cash flows for the three months ended March 31, 2016 and 2015. Operating results for the three months ended March 31, 2016 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, 2015 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 months ended March 31, 2016, the Company recognized a ceiling test impairment of approximately $3.9 million. For the three months ended March 31, 2015, the Company did not recognize a ceiling test impairment as the Company’s full cost pool did not exceed the ceiling limitation. Future declines in oil and natural gas prices, and increases in future operating expenses and future development costs could result in additional impairments of our oil and gas properties in future periods. The effects of price declines will continue to impact the ceiling test value until such time prices stabilize or improve. Impairment charges are a non-cash charge and accordingly, do not affect cash flow, but 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 of 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 impairment assessments for each investment are 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 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. 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 three months ended March 31, 2016 and 2015: (in thousands) Three Months Ended March 31, 2016 2015 Balance at beginning of period $ 3,095 $ 2,968 Accretion expense 35 31 Additions during period 5 - Balance at end of period $ 3,135 $ 2,999
Earnings Per Common Share	Earnings 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, directors 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 March 31, 2016 2015 Net loss $ (4,927 ) $ (630 ) Basic weighted-average common shares outstanding in period 107,180 105,934 Add dilutive effects of stock options, warrants and nonvested shares of restricted stock - - Diluted weighted-average common shares outstanding in period 107,180 105,934 Basic net loss per common share $ (0.05 ) $ (0.01 ) Diluted net loss per common share $ (0.05 ) $ (0.01 ) For the quarter ended March 31, 2016, the Company had a net loss and therefore, the diluted net loss per share calculation for that period excludes the anti-dilutive effect of approximately 250,000 warrants and approximately 5.8 million nonvested shares of restricted stock. In addition, approximately 6.3 million restricted performance units subject to future contingencies were excluded from the basic and diluted loss per share calculations. For the quarter ended March 31, 2015, the Company had a net loss and therefore, the diluted net loss per share calculation for that period excludes the anti-dilutive effect of approximately 2.7 million stock options and warrants, approximately 4.1 million nonvested shares of restricted stock and approximately 4.7 million restricted performance units, subject to future contingencies, were excluded from the basic and diluted loss per share calculations.
Adopted and Recently Issued Accounting Pronouncements	Adopted and Recently Issued Accounting Pronouncements In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Improvements To Employee Share-Based Payment Accounting In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases

Summary of Significant Accoun21

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2016
Summary of Significant Accounting Policies [Abstract]
Summary of reconciliation of ARO	(in thousands) Three Months Ended March 31, 2016 2015 Balance at beginning of period $ 3,095 $ 2,968 Accretion expense 35 31 Additions during period 5 - Balance at end of period $ 3,135 $ 2,999
Schedule of basic and diluted (loss) income per share	Three Months Ended March 31, 2016 2015 Net loss $ (4,927 ) $ (630 ) Basic weighted-average common shares outstanding in period 107,180 105,934 Add dilutive effects of stock options, warrants and nonvested shares of restricted stock - - Diluted weighted-average common shares outstanding in period 107,180 105,934 Basic net loss per common share $ (0.05 ) $ (0.01 ) Diluted net loss per common share $ (0.05 ) $ (0.01 )

Property and Equipment (Tables)

Property and Equipment (Tables)	3 Months Ended
	Mar. 31, 2016
Property and Equipment [Abstract]
Summary of net property and equipment	(in thousands) March 31, 2016 December 31, 2015 Oil and gas properties: Proved oil and gas properties $ 97,796 $ 97,453 Unproved properties not subject to depletion 3,146 3,194 Accumulated depreciation, depletion, amortization and impairment (76,783 ) (72,421 ) Net oil and gas properties 24,159 28,226 Furniture and fixtures, computer hardware and software, and other equipment 803 825 Accumulated depreciation and amortization (587 ) (587 ) Net other property and equipment 216 238 Total net property and equipment $ 24,375 $ 28,464

Accounts Payable and Accrued 23

Accounts Payable and Accrued Liabilities (Tables)	3 Months Ended
	Mar. 31, 2016
Accounts Payable and Accrued Liabilities [Abstract]
Summary of accounts payable and accrued liabilities	(in thousands) March 31, 2016 December 31, 2015 Accounts payable $ 701 $ 577 Oil and gas revenue payable to oil and gas property owners 1,062 1,221 Production taxes payable 57 59 Drilling advances received from joint venture partner 2,105 2,115 Accrued drilling costs 112 112 Accrued lease operating costs 54 76 Accrued ad valorem taxes 501 496 Accrued general and administrative expenses 797 833 Other liabilities 217 132 Total accounts payable and accrued liabilities $ 5,606 $ 5,621

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2016
Fair Value Measurements [Abstract]
Summary of financial assets and liabilities at fair value	(in thousands) Fair Value Measurements Using Level 1 Level 2 Level 3 Total March 31, 2016 Assets: Commodity derivatives $ - $ 496 $ - $ 496 December 31, 2015 Assets: Commodity derivatives $ - $ 559 $ - $ 559

Physical Delivery Contracts a25

Physical Delivery Contracts and Oil and Gas Derivatives (Tables)	3 Months Ended
	Mar. 31, 2016
Physical Delivery Contracts and Oil and Gas Derivatives [Abstract]
Schedule of future production volumes to be delivered and sold	Daily Period (Dths Price Contract 1 Apr - Oct 2016 1,000 Index less $0.29 Contract 2 Apr - Sep 2016 611 98% of Index less $0.23
Schedule of swap agreements	Natural Gas Oil Weighted Weighted Average Average Quarter MMBtu Price (a)( c) Bbl Price (b)( c) Swaps: Apr - Jun 2016 40,000 $ 3.39 - - Jul - Sep 2016 30,000 $ 3.12 - - Oct - Dec 2016 30,000 $ 3.12 - - Jan - Mar 2017 30,000 $ 3.27 - - Apr - Jun 2017 30,000 $ 3.27 - - Jul - Sep 2017 30,000 $ 3.27 - - Oct - Dec 2017 30,000 $ 3.27 - - Collars: Apr - Jun 2016 30,000 $ 2.75 - $3.40 6,000 $ 50.00 - $59.00 Jul - Sep 2016 30,000 $ 2.75 - $3.40 5,500 $ 48.64 - $57.91 Oct - Dec 2016 30,000 $ 2.75 - $3.40 4,500 $ 48.33 - $58.00 Jan - Mar 2017 - - 4,500 $ 48.33 - $61.67 Apr - Jun 2017 - - 4,500 $ 48.33 - $61.67 Jul - Sep 2017 - 4,500 $ 48.33 - $61.67 Oct - Dec 2017 - - 4,500 $ 48.33 - $61.67 (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 (c) NYMEX costless collar floor to ceiling prices.
Schedule of fair value of the derivatives recorded	(in thousands) March 31, 2016 December 31, 2015 Commodity derivative contracts: Current assets $ 362 $ 408 Other long-term assets 134 151
Schedule of realized and unrealized gains and losses	(in thousands) Three Months Ended 2016 2015 Commodity derivative contracts: Settlement gains $ 202 $ 552 Unrealized losses (62 ) (346 ) Total settlement and unrealized gains, net $ 140 $ 206
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 Commodity derivative assets: Current assets $ 378 $ (16 ) $ 362 Other long-term assets 163 (29 ) 134 Total derivative assets $ 541 $ (45 ) $ 496 Commodity derivative liabilities: Current liability $ 16 $ (16 ) $ - Non-current liabilities 29 (29 ) - Total derivative liabilities $ 45 $ (45 $ -

Commitments (Tables)

Commitments (Tables)	3 Months Ended
	Mar. 31, 2016
Commitments [Abstract]
Summary of firm transportation volumes and related demand charges	Period Dekatherms per day Demand Charges Apr 2016 - 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)	3 Months Ended
	Mar. 31, 2016
Supplemental Cash Flow Disclosure [Abstract]
Supplemental cash flow disclosures	Three Months Ended March 31, (in thousands) 2016 2015 Cash paid during the period for: Interest $ 53 $ 26 Income taxes $ - $ 325 Non-cash transactions: Increase in net asset retirement obligations $ 5 $ - Increase in accounts payable and accrued liabilities included in oil and gas properties $ 38 $ 18

Going Concern (Details)

Going Concern (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended
	May. 17, 2016	Mar. 31, 2016
Going Concern [Line Items]
Negative working capital		$ 7.3
Subsequent Event [Member]
Going Concern [Line Items]
Credit facility, Description	Credit facility from $20.0 million to $5.5 million (of which $500,000 is reserved for future interest payments as those payments become due under the credit facility) and changed the maturity date of the credit facility from May 31, 2017 to January 2, 2017.

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Summary of reconciliation of the ARO
Balance at beginning of period	$ 3,095	$ 2,968
Accretion expense	35	$ 31
Additions during period	5
Balance at end of period	$ 3,135	$ 2,999

Summary of Significant Accoun30

Summary of Significant Accounting Policies (Details 1) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Summary of Significant Accounting Policies [Abstract]
Net loss	$ (4,927)	$ (630)
Basic weighted-average common shares outstanding in period	107,180	105,934
Add dilutive effects of stock options, warrants and nonvested shares of restricted stock
Diluted weighted-average common shares outstanding in period	107,180	105,934
Basic net loss per common share	$ (0.05)	$ (0.01)
Diluted net loss per common share	$ (0.05)	$ (0.01)

Summary of Significant Accoun31

Summary of Significant Accounting Policies (Details Textual) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)Partnershipshares	Mar. 31, 2015shares
Summary of Significant Accounting Policies (Textual)
Number of consolidated partnerships | Partnership	46
Ceiling test impairment cost | $	$ 3.9
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	250,000	2,700,000
Stock Options [Member]
Summary of Significant Accounting Policies (Textual)
Anti-dilutive earnings per shares		2,700,000
Restricted Stock [Member]
Summary of Significant Accounting Policies (Textual)
Anti-dilutive earnings per shares	5,800,000	4,100,000
Restricted Performance Units [Member]
Summary of Significant Accounting Policies (Textual)
Common stock equivalent restricted to future contingencies	6,300,000	4,700,000
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%

Property and Equipment (Details

Property and Equipment (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Oil and gas properties
Accumulated depreciation, depletion, amortization and impairment	$ (76,783)	$ (72,421)
Net oil and gas properties	24,159	28,226
Furniture and fixtures, computer hardware and software, and other equipment	803	825
Accumulated depreciation and amortization	(587)	(587)
Net other property and equipment	216	238
Total net property and equipment	24,375	28,464
Proved oil and gas properties [Member]
Oil and gas properties
Oil and gas properties, gross	97,796	97,453
Unproved properties not subject to depletion [Member]
Oil and gas properties
Oil and gas properties, gross	$ 3,146	$ 3,194

Property and Equipment (Detai33

Property and Equipment (Details Textual)	3 Months Ended		12 Months Ended
	Mar. 31, 2016USD ($)Per_Mcfe	Mar. 31, 2015USD ($)Per_Mcfe	Dec. 31, 2015USD ($)
Property and Equipment (Textual)
Depletion expense related to oil and gas properties	$ 3,200,000		$ 3,200,000
Capitalized general and administrative expenses	133,000	$ 132,000
Depletion expense related to oil and gas properties	$ 472,000	$ 608,000
Depletion expense related to oil and gas properties (in dollars per Mcfe) | Per_Mcfe	0.79	0.87
Depreciation and amortization expense	$ 31,000	$ 37,000

Equity Method Investment (Detai

Equity Method Investment (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Equity Method Investment (Textual)
Ownership interest percentage in crawford county gas gathering company, LLC	50.00%
Equity investment income (loss) in crawford county gas gathering company, LLC		$ 1,000
Cash received	$ 275,000

Bank Credit Facility (Details)

Bank Credit Facility (Details) - USD ($)	1 Months Ended	3 Months Ended
	May. 17, 2016	Mar. 31, 2016
Bank Credit Facility (Textual)
Current borrowing base		$ 20,000,000
Maximum line of credit available under hedging arrangements		$ 9,500,000
Line of credit facility maturity date		May 31, 2017
Maximum borrowing base		$ 50,000,000
Outstanding borrowings		3,900,000
Additional borrowing capacity available		$ 16,100,000
Effective borrowing rate (as a percent)		3.00%
Subsequent Event [Member]
Bank Credit Facility (Textual)
Outstanding borrowings	$ 4,000,000
Additional borrowing capacity available	$ 300,000
Credit facility, Description	Credit facility from $20.0 million to $5.5 million (of which $500,000 is reserved for future interest payments as those payments become due under the credit facility) and changed the maturity date of the credit facility from May 31, 2017 to January 2, 2017.
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 ($)	Jun. 25, 2013	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2012
Stockholders' Equity (Textual)
Common stock, shares authorized		200,000,000		200,000,000
Common stock, par value (in dollars per share)		$ 0.01		$ 0.01
Common stock, shares issued		108,082,583		107,655,916
Common stock, shares outstanding		108,082,583		107,655,916
Preferred stock, shares authorized		1,000,000		1,000,000
Preferred stock, par value (in dollars per share)		$ 0.01		$ 0.01
Preferred stock, shares issued
Preferred stock, shares outstanding
Unrecognized compensation cost		$ 252,000
Restricted performance units		6,600,000
Restricted Stock Units (RSUs) [Member]
Stockholders' Equity (Textual)
Compensation costs for restricted stock grants		$ 201,000	$ 160,000
Expected period of recognition of unrecognized compensation costs		6 years 9 months 18 days
Value of restricted stock grants to vested		$ 3,000,000
Number of shares granted		6,300,000
Restricted Stock [Member]
Stockholders' Equity (Textual)
Compensation costs for restricted stock grants		$ 84,000	84,000
Unrecognized compensation cost		$ 1,100,000
Number of shares granted		1,700,000
Restricted stock awards vest peroid		3 years
Restricted Performance Units [Member]
Stockholders' Equity (Textual)
Compensation costs for restricted stock grants		$ 86,000	$ 86,000
Unrecognized compensation cost		$ 41,000		$ 3,100,000	$ 3,100,000	$ 3,100,000
Expected period of recognition of unrecognized compensation costs		3 months
Restricted performance units		$ 6,300,000
Equity Plans Prior To Merger [Member] | Warrant [Member]
Stockholders' Equity (Textual)
Number of shares outstanding		250,000
Number of shares exercisable		250,000
Equity Plans Prior To Merger [Member] | Restricted Stock Units (RSUs) [Member]
Stockholders' Equity (Textual)
Number of shares outstanding		489,000
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		9 months
Vesting, percentage	25.00%
Nytis USA Restricted Stock Plan [Member] | Restricted Stock Units (RSUs) [Member]
Stockholders' Equity (Textual)
Number of shares restricted stock issued		489,000
Carbon Stock Incentive Plans [Member] | Officer [Member]
Stockholders' Equity (Textual)
Stock incentive plan, common stock shares authorized		22,600,000

Accounts Payable and Accrued 37

Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Accounts Payable and Accrued Liabilities [Abstract]
Accounts payable	$ 701	$ 577
Oil and gas revenue payable to oil and gas property owners	1,062	1,221
Production taxes payable	57	59
Drilling advances received from joint venture partner	2,105	2,115
Accrued drilling costs	112	112
Accrued lease operating costs	54	76
Accrued ad valorem taxes	501	496
Accrued general and administrative expenses	797	833
Other liabilities	217	132
Total accounts payable and accrued liabilities	$ 5,606	$ 5,621

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Assets:
Commodity derivatives	$ 362	$ 408
Recurring basis [Member] | Level 1 [Member]
Assets:
Commodity derivatives
Recurring basis [Member] | Level 2 [Member]
Assets:
Commodity derivatives	$ 496	$ 559
Recurring basis [Member] | Level 3 [Member]
Assets:
Commodity derivatives

Fair Value Measurements (Deta39

Fair Value Measurements (Details Textual) - USD ($)	Mar. 31, 2016	Mar. 31, 2015
Fair Value Measurements (Textual)
Asset retirement obligation	$ 5,000

Physical Delivery Contracts a40

Physical Delivery Contracts and Oil and Gas Derivatives (Details )	3 Months Ended
	Mar. 31, 2016Volume
Contract 1 [Member] | Apr-Oct 2016
Derivatives, Fair Value [Line Items]
Daily Volume (Dths per day)	1,000
Price	Index less $0.29
Contract 2 [Member] | Apr-Sep 2016
Derivatives, Fair Value [Line Items]
Daily Volume (Dths per day)	611
Price	98% of Index less $0.23

Physical Delivery Contracts a41

Physical Delivery Contracts and Oil and Gas Derivatives (Details1)	Mar. 31, 2016USD_MMBtuUSD_Bbl$ / shares
Swap [Member] | Apr - Jun 2016 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	40,000
Weighted Average Price	$ 3.39	[1],[2]
Swap [Member] | Apr - Jun 2016 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl
Weighted Average Price		[2],[3]
Swap [Member] | Jul - Sep 2016 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Weighted Average Price	$ 3.12	[1],[2]
Swap [Member] | Jul - Sep 2016 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl
Weighted Average Price		[2],[3]
Swap [Member] | Oct - Dec 2016 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Weighted Average Price	$ 3.12	[1],[2]
Swap [Member] | Oct - Dec 2016 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl
Weighted Average Price		[2],[3]
Swap [Member] | Jan - Mar 2017 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Weighted Average Price	$ 3.27	[1],[2]
Swap [Member] | Jan - Mar 2017 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl
Weighted Average Price		[2],[3]
Swap [Member] | Apr - Jun 2017 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Weighted Average Price	$ 3.27	[1],[2]
Swap [Member] | Apr - Jun 2017 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl
Weighted Average Price		[2],[3]
Swap [Member] | Jul - Sep 2017 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Weighted Average Price	$ 3.27	[1],[2]
Swap [Member] | Jul - Sep 2017 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl
Weighted Average Price		[2],[3]
Swap [Member] | Oct - Dec 2017 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Weighted Average Price	$ 3.27	[1],[2]
Swap [Member] | Oct - Dec 2017 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl
Weighted Average Price		[1],[2]
Collars [Member] | Apr - Jun 2016 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Collars [Member] | Apr - Jun 2016 [Member] | Natural Gas [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 2.75	[1],[2]
Collars [Member] | Apr - Jun 2016 [Member] | Natural Gas [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 3.40	[1],[2]
Collars [Member] | Apr - Jun 2016 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl	6,000
Collars [Member] | Apr - Jun 2016 [Member] | Oil [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 50	[2],[3]
Collars [Member] | Apr - Jun 2016 [Member] | Oil [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 59	[2],[3]
Collars [Member] | Jul - Sep 2016 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Collars [Member] | Jul - Sep 2016 [Member] | Natural Gas [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 2.75	[1],[2]
Collars [Member] | Jul - Sep 2016 [Member] | Natural Gas [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 3.40	[1],[2]
Collars [Member] | Jul - Sep 2016 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl	5,500
Collars [Member] | Jul - Sep 2016 [Member] | Oil [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 48.64	[2],[3]
Collars [Member] | Jul - Sep 2016 [Member] | Oil [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 57.91	[2],[3]
Collars [Member] | Oct - Dec 2016 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Collars [Member] | Oct - Dec 2016 [Member] | Natural Gas [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 2.75	[1],[2]
Collars [Member] | Oct - Dec 2016 [Member] | Natural Gas [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 3.40	[1],[2]
Collars [Member] | Oct - Dec 2016 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl	4,500
Collars [Member] | Oct - Dec 2016 [Member] | Oil [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 48.33	[2],[3]
Collars [Member] | Oct - Dec 2016 [Member] | Oil [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 58	[2],[3]
Collars [Member] | Jan - Mar 2017 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu
Weighted Average Price		[1],[2]
Collars [Member] | Jan - Mar 2017 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl	4,500
Collars [Member] | Jan - Mar 2017 [Member] | Oil [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 48.33	[2],[3]
Collars [Member] | Jan - Mar 2017 [Member] | Oil [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 61.67	[2],[3]
Collars [Member] | Apr - Jun 2017 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu
Weighted Average Price		[1],[2]
Collars [Member] | Apr - Jun 2017 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl	4,500
Collars [Member] | Apr - Jun 2017 [Member] | Oil [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 48.33	[2],[3]
Collars [Member] | Apr - Jun 2017 [Member] | Oil [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 61.67	[2],[3]
Collars [Member] | Jul - Sep 2017 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu
Weighted Average Price		[1],[2]
Collars [Member] | Jul - Sep 2017 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl	4,500
Collars [Member] | Jul - Sep 2017 [Member] | Oil [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 48.33	[2],[3]
Collars [Member] | Jul - Sep 2017 [Member] | Oil [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 61.67	[2],[3]
Collars [Member] | Oct - Dec 2017 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu
Weighted Average Price		[1],[2]
Collars [Member] | Oct - Dec 2017 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl	4,500
Collars [Member] | Oct - Dec 2017 [Member] | Oil [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 48.33	[2],[3]
Collars [Member] | Oct - Dec 2017 [Member] | Oil [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 61.67	[2],[3]
[1]	NYMEX Henry Hub Natural Gas futures contract for the respective delivery month.
[2]	NYMEX costless collar floor and ceiling prices.
[3]	NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective delivery month

Physical Delivery Contracts a42

Physical Delivery Contracts and Oil and Gas Derivatives (Details 2) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Commodity derivative contracts:
Current assets	$ 362	$ 408
Other long-term assets	$ 134	$ 151

Physical Delivery Contracts a43

Physical Delivery Contracts and Oil and Gas Derivatives (Details 3) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Commodity derivative contracts:
Unrealized losses	$ (62)	$ (346)
Commodity derivative contracts [Member]
Commodity derivative contracts:
Settlement gains	202	552
Unrealized losses	(62)	(346)
Total settlement and unrealized gains, net	$ 140	$ 206

Physical Delivery Contracts a44

Physical Delivery Contracts and Oil and Gas Derivatives (Details 4) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Commodity derivative assets:
Current derivative assets	$ 362	$ 408
Other long-term assets	134	$ 151
Gross Recognized Assets/Liabilities [Member]
Commodity derivative assets:
Current derivative assets	378
Other long-term assets	163
Total derivative assets	541
Commodity derivative liabilities:
Current derivative liabilities	16
Non-current derivative liabilities	29
Total derivative liabilities	45
Gross Amounts Offset [Member]
Commodity derivative assets:
Current derivative assets	(16)
Other long-term assets	(29)
Total derivative assets	(45)
Commodity derivative liabilities:
Current derivative liabilities	(16)
Non-current derivative liabilities	(29)
Total derivative liabilities	(45)
Net Recognized Fair Value Assets/Liabilities [Member]
Commodity derivative assets:
Current derivative assets	362
Other long-term assets	134
Total derivative assets	$ 496
Commodity derivative liabilities:
Current derivative liabilities
Non-current derivative liabilities
Total derivative liabilities

Commitments (Details)

Commitments (Details)	3 Months Ended
	Mar. 31, 2016Per_McfePartnership
Apr 2016 - Apr 2018 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Partnership	4,450
Apr 2016 - Apr 2018 [Member] | Maximum [Member]
Other Commitments [Line Items]
Demand charges (in dollars per dekatherm)	0.65
Apr 2016 - Apr 2018 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand charges (in dollars per dekatherm)	0.20
May 2018 - May 2020 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Partnership	2,150
Demand charges (in dollars per dekatherm)	0.20
Jun 2020 - May 2036 [Member]
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)	Mar. 31, 2016USD ($)
Commitments (Textual)
Liability related to firm transportation contracts assumed	$ 741,000

Supplemental Cash Flow Disclo47

Supplemental Cash Flow Disclosure (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Cash paid during the period for:
Interest	$ 53	$ 26
Income taxes		$ 325
Non-cash transactions:
Increase in net asset retirement obligations	$ 5
Increase in accounts payable and accrued liabilities included in oil and gas properties	$ 38	$ 18