Carbon Energy (CRBO) 10-K 31 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Mar. 17, 2017	Jun. 30, 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-K
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float			$ 32.9
Entity Common Stock, Shares Outstanding		5.5

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 858	$ 305
Accounts receivable:
Revenue	2,369	1,082
Joint interest billings and other	2,251	778
Commodity derivative asset		408
Prepaid expense and deposits	305	213
Total current assets	5,783	2,786
Oil and gas properties, full cost method of accounting:
Proved, net	33,212	25,032
Unproved	1,999	3,194
Other property and equipment, net	325	238
Total property and equipment, net	35,536	28,464
Investments in affiliates (note 6)	668	1,025
Other long-term assets	725	433
Total assets	42,712	32,708
Current liabilities:
Accounts payable and accrued liabilities	9,121	5,621
Commodity derivative liability	1,341
Firm transportation contract obligations (note 13)	561	436
Total current liabilities	11,023	6,057
Non-current liabilities:
Firm transportation contract obligations (note 13)	261	416
Commodity derivative liability	591
Ad valorem taxes payable	628
Asset retirement obligations (note 3)	5,006	3,095
Notes payable (note 7)	16,230	3,500
Total non-current liabilities	22,716	7,011
Commitments and contingencies (note 13)
Stockholders' equity:
Preferred stock, $0.01 par value; authorized 1,000,000 shares, no shares issued and outstanding at December 31, 2016 and 2015
Common stock, $0.01 par value; authorized 200,000,000 shares, 5,482,673 and 5,382,796 shares issued and outstanding at December 31, 2016 and 2015, respectively	1,096	1,077
Additional paid-in capital	56,548	54,394
Accumulated deficit	(50,536)	(38,130)
Total Carbon stockholders' equity	7,108	17,341
Non-controlling interests	1,865	2,299
Total stockholders' equity	8,973	19,640
Total liabilities and stockholders' equity	$ 42,712	$ 32,708

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 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	5,482,673	5,382,796
Common stock, shares outstanding	5,482,673	5,382,796

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Revenue:
Natural gas sales	$ 7,127	$ 5,663
Oil sales	3,316	5,045
Commodity derivative (loss) gain	(2,259)	852
Other income	11	118
Total revenue	8,195	11,678
Expenses:
Lease operating expenses	3,175	2,910
Transportation costs	1,645	1,710
Production and property taxes	820	887
General and administrative	8,645	6,741
Depreciation, depletion and amortization	1,953	2,607
Accretion of asset retirement obligations	176	123
Impairment of oil and gas properties	4,299	5,419
Total expenses	20,713	20,397
Operating loss	(12,518)	(8,719)
Other income and (expense):
Interest expense	(367)	(201)
Investment income	49	16
Other income (expense)	17	(30)
Total other expense	(301)	(215)
Loss before income taxes	(12,819)	(8,934)
Income tax expense:
Current
Net loss	(12,819)	(8,934)
Net loss attributable to non-controlling interests	413	636
Net loss attributable to controlling interest	$ (12,406)	$ (8,298)
Net loss per common share:
Basic	$ (2.27)	$ (1.56)
Diluted	$ (2.27)	$ (1.56)
Weighted average common shares outstanding
Basic	5,468	5,335
Diluted	5,468	5,335

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) shares in Thousands, $ 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		5,344
Stock-based compensation	$ 1,443		$ 1,443
Restricted stock activity including vesting and shares exchanged for tax withholding	(201)	$ 8	(209)
Restricted stock activity including vesting and shares exchanged for tax withholding, shares		39
Non-controlling interests distributions, net	(100)			(100)
Net loss	(8,934)			(636)	(8,298)
Ending balances at Dec. 31, 2015	$ 19,640	$ 1,077	$ 54,394	$ 2,299	$ (38,130)
Ending balances, (in shares) at Dec. 31, 2015		5,383
Stock-based compensation	$ 2,440		$ 2,440
Restricted stock vested		$ 13	(13)
Restricted stock vested, shares		65
Performance units vested		$ 17	(17)
Performance units vested, shares		84
Restricted stock activity including vesting and shares exchanged for tax withholding	(267)	$ (11)	(256)
Restricted stock activity including vesting and shares exchanged for tax withholding, shares		(50)
Non-controlling interests distributions, net	(14)			(14)
Non-controlling interest purchase	(7)			(7)
Net loss	(12,819)			(413)	(12,406)
Ending balances at Dec. 31, 2016	$ 8,973	$ 1,096	$ 56,548	$ 1,865	$ (50,536)
Ending balances, (in shares) at Dec. 31, 2016		5,482

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net loss	$ (12,819)	$ (8,934)
Items not involving cash:
Depreciation, depletion and amortization	1,953	2,607
Accretion of asset retirement obligations	176	123
Impairment of oil and gas properties	4,299	5,419
Unrealized derivative loss	2,490	763
Stock-based compensation expense	2,440	1,443
Equity investment loss (income)	17	(16)
Other	(47)	(12)
Net change in:
Accounts receivable	(2,925)	1,631
Prepaid expenses, deposits and other current assets	(93)	(72)
Accounts payable, accrued liabilities and firm transportation contracts	1,367	(2,443)
Net cash (used in) provided by operating activities	(3,142)	509
Cash flows from investing activities:
Development of oil and gas properties and other capital expenditures	(700)	(3,112)
Acquisition of oil and gas properties	(8,117)
Proceeds from sale of other fixed assets	8	213
Equity investment distributions	340
Other long-term assets	(285)	464
Net cash used in investing activities	(8,754)	(2,435)
Cash flows from financing activities:
Vested restricted stock exchanged for tax withholding	(267)	(201)
Proceeds from notes payable	16,937	2,000
Payments on notes payable	(4,207)	(600)
Distribution to non-controlling interests	(14)	(100)
Net cash provided by financing activities	12,449	1,099
Net increase (decrease) in cash and cash equivalents	553	(827)
Cash and cash equivalents, beginning of period	305	1,132
Cash and cash equivalents, end of period	$ 858	$ 305

Organization

Organization	12 Months Ended
	Dec. 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 conduct the Company’s operations in the Appalachian and Illinois Basins. Collectively, Carbon, Nytis USA and Nytis LLC are referred to as the Company.

Reverse Stock Split

Reverse Stock Split	12 Months Ended
	Dec. 31, 2016
Reverse Stock Split [Abstract]
Reverse Stock Split	Note 2 – Reverse Stock Split Effective March 15, 2017 and pursuant to a reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. The accompanying financial statements and related disclosures give retroactive effect to the reverse stock split for all periods presented.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Summary of Significant Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 3 – Summary of Significant Accounting Policies Accounting policies used by the Company reflect industry practices and conform to accounting principles generally accepted in the United States of America. The more significant of such accounting policies are briefly discussed below. Principles of Consolidation The Consolidated Financial Statements include the accounts of Carbon and its consolidated subsidiaries. The Company owns 100% of Nytis USA. Nytis USA owns approximately 99% of Nytis LLC. Nytis LLC also holds interests in various oil and gas partnerships. For partnerships where the Company has a controlling interest, the partnerships are consolidated. The Company is currently consolidating 46 partnerships and 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 interest 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 the Company’s 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. Cash and Cash Equivalents Cash and cash equivalents, if any, in excess of daily requirements have been generally invested in money market accounts, certificates of deposits and other cash equivalents with maturities of three months or less. Such investments are deemed to be cash equivalents for purposes of the Consolidated Financial Statements. The carrying amount of cash equivalents approximates fair value because of the short maturity and high credit quality of these investments. Accounts Receivable The Company’s accounts receivable are primarily comprised of oil and natural gas revenues from producing activities and from other exploration and production companies and individuals who own working interests in the properties that the Company operates. The Company grants credit to all qualified customers, which potentially subjects the Company to credit risk resulting from, among other factors, adverse changes in the industries in which the Company operates and the financial condition of its customers. The Company continuously monitors collections and payments from its customers and maintains an allowance for doubtful accounts based upon its historical experience and any specific customer collection issues that it has identified. At December 31, 2016 and 2015, the Company had not identified any collection issues related to its oil and gas operations and as a consequence no allowance for doubtful accounts was provided for on those dates. In addition, accounts receivable included a deposit of $1.7 million made by the Company on the purchase of assets in the Ventura Basin of California through Carbon California Company, LLC (“Carbon California”). The deposit was reimbursed to the Company upon the consummation of the acquisition by Carbon California Company LLC on February 15, 2017. See Note 16 for additional information. Oil and Natural Gas Sales The Company sells its oil and natural gas production to various purchasers in the industry. The table below presents purchasers that account for 10% or more of total oil and natural gas sales for the years ended December 31, 2016 and 2015. There are a number of purchasers in the areas where the Company sells its production. Management does not believe that changing its primary purchasers or a loss of any other single purchaser would materially impact the Company’s business. Purchaser 2016 2015 Purchaser A 18 % 18 % Purchaser B 17 % 24 % Purchaser C 16 % 15 % Purchaser D 15 % 15 % The Company recognizes an asset or a liability, whichever is appropriate, for revenues associated with over-deliveries or under-deliveries of natural gas to purchasers. A purchaser imbalance asset occurs when the Company delivers more natural gas than it nominated to deliver to the purchaser and the purchaser pays only for the nominated amount. Conversely, a purchaser imbalance liability occurs when the Company delivers less natural gas than it nominated to deliver to the purchaser and the purchaser pays for the amount nominated. As of December 31, 2016 and 2015, the Company had a purchaser imbalance payable of approximately $25,000 and a receivable of approximately $270,000, respectively, which are recognized as a current liability and current asset, respectively, in the Company’s Consolidated Balance Sheets. Accounting for Oil and Gas Operations The Company uses the full cost method of accounting for oil and gas properties. Accordingly, all costs related 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 gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus 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. See Note 4 regarding the Company’s 2015 divestitures. 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 on a quarterly basis. 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 or impairment 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 capitalized costs in future periods. For the years ended December 31, 2016 and 2015, the Company recognized a ceiling test impairment of approximately $4.3 million and $5.4 million, respectively. Future declines in oil and natural gas prices could result in impairments of our oil and gas properties in future periods. Because the ceiling test used previous twelve month period average commodity prices, the effect of declining prices since mid-2014 had a negative impact on the average price used to value our reserves which will lower the ceiling test value in future periods and may result in additional impairments of our oil and gas properties. The effect of price declines will impact the ceiling test value until such time commodity prices stabilize or improve. Impairment changes are a non-cash charge and accordingly would not affect cash flows but would adversely affect our net income and shareholders’ equity. Other Property and Equipment Other property and equipment are recorded at cost upon acquisition. Depreciation of other property and equipment is calculated over three to seven years using the straight-line method. Long-Lived Assets The Company reviews its long-lived assets other than oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered. The Company looks primarily to the estimated undiscounted future cash flows in its assessment of whether or not long-lived assets have been impaired. 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 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 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 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 years ended December 31, 2016 and 2015. Year Ended December 31, (in thousands) 2016 2015 Balance at beginning of year $ 3,095 $ 2,968 Accretion expense 176 123 Additions during period 1,849 4 5,120 3,095 Less: ARO recognized as a current liability (114 ) - Balance at end of year $ 5,006 $ 3,095 For the year ended December 31, 2016, the addition of approximately $1.8 million to ARO is primarily due to the acquisition of producing oil and natural gas properties in the Appalachian Basin in the fourth quarter of 2016. Financial Instruments The Company’s financial instruments include cash and cash equivalents, accounts receivables, accounts payables, accrued liabilities, commodity derivative instruments and its notes payable. The carrying value of cash and cash equivalents, accounts receivables, payables and accrued liabilities are considered to be representative of their fair value, due to the short maturity of these instruments. The Company’s commodity derivative instruments are recorded at fair value, as discussed below and in Note 11. The carrying amount of the Company’s notes payable approximated fair value since borrowings bear interest at variable rates, which are representative of the Company’s credit adjusted borrowing rate. Commodity Derivative Instruments The Company enters into commodity derivative contracts to manage its exposure to oil and natural gas price volatility with an objective to reduce our exposure to downward price fluctuations. Commodity derivative contracts may take the form of futures contracts, swaps, collars or options. The Company has elected not to designate its derivatives as cash flow hedges. All derivatives are initially and subsequently measured at estimated fair value and recorded as assets or liabilities on the Consolidated Balance Sheets and the changes in fair value are recognized as gains or losses in revenues in the Consolidated Statements of Operations. Income Taxes Carbon accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases, as well as the future tax consequences attributable to the future utilization of existing tax net operating losses and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more likely than not recognition threshold are recognized. Stock - Based Compensation Compensation cost is measured at the grant date, based on the fair value of the awards and is recognized on a straight-line basis over the requisite service period (usually the vesting period). Revenue Recognition Oil and natural gas revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. Natural gas revenues are recognized on the basis of the Company’s net working revenue interest. Net deliveries in excess of entitled amounts are recorded as a liability, while net deliveries lower than entitled amounts are recorded as a receivable. Earnings Per Common Share Basic earnings per common share is computed by dividing the net income attributable to common stockholders for the period by the weighted average number of common shares outstanding during the period. The shares of restricted common stock granted to officers, directors and employees of the Company are included in the computation of basic net income 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: For the Year Ended (in thousands except per share amounts) 2016 2015 Net loss $ (12,406 ) $ (8,298 ) Basic weighted-average common shares outstanding during the period 5,468 5,335 Add dilutive effects of stock options, warrants and non-vested shares of restricted stock - - Diluted weighted-average common shares outstanding during the period 5,468 5,335 Basic net (loss) income per common share $ (2.27 ) $ (1.56 ) Diluted net (loss) income per common share $ (2.27 ) $ (1.56 ) Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and expenses and disclosure of contingent assets and liabilities. Significant items subject to such estimates and assumptions include the carrying value of oil and gas properties, the estimate of proved oil and gas reserve volumes and the related depletion and present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, determining the amounts recorded for deferred income taxes, stock-based compensation, fair value of commodity derivative instruments, fair value of assets acquired qualifying as business contributions and asset retirement obligations. Actual results could differ from those estimates and assumptions used. Adopted and Recently Issued Accounting Pronouncements In August 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-15, Statement of Cash Flows-Classification of Certain Cash Receipts and Cash Payments In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805) In September 2015, the FASB issued ASU 2015-16, Business Combinations (Topic 805)

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2016
Acquisitions and Divestitures [Abstract]
Acquisitions and Divestitures	Note 4 – Acquisitions and Divestitures Acquisitions On October 3, 2016 (the “Closing Date”), Nytis LLC completed an acquisition (the “EXCO Acquisition”) consisting of producing natural gas wells and natural gas gathering facilities located in the Company’s Appalachian Basin operating area. The natural gas gathering facilities are primarily used to gather the Company’s natural gas production. The acquisition was pursuant to a purchase and sale agreement effective October 1, 2016 (the “EXCO Purchase Agreement”) by and among EXCO Production Company (WV), LLC, BG Production Company (WV), LLC and EXCO Resources (PA) LLC (collectively the “Sellers”) and Nytis LLC, as the buyer. The purchase price of the acquired assets pursuant to the EXCO Purchase Agreement was $9.0 million subject to customary closing adjustments and the assumption of certain obligations. The EXCO Acquisition provided the Company with proved developed reserves, production and operating cash flow in a location where the Company has similar assets. The EXCO Acquisition qualified as a business combination and as such, the Company estimated the fair value as of the Closing Date of the assets acquired and liabilities assumed as of the Closing Date. The Company considered various factors in its estimate of fair value of the acquired assets including (i) reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, including price differentials, (v) future cash flows, and (vi) a market participant-based weighted average cost of capital. The Company expensed approximately $501,000 of transaction and due diligence costs related to the EXCO Acquisition that were included in general and administrative expenses in the accompanying Consolidated Statement of Operations for the year ended December 31, 2016. The following table summarizes the preliminary consideration paid to the Sellers and the estimated fair value of the assets acquired and liabilities assumed. Consideration paid to Sellers: Cash consideration $ 8,117 Recognized amounts of identifiable assets acquired and liabilities assumed: Proved oil and gas properties and related support facilities $ 12,656 Asset retirement obligations (1,845 ) Working capital (2,694 ) Total identified net assets $ 8,117 The estimated fair value of the asset acquired and liabilities assumed will be adjusted to reflect any changes in the consideration paid pursuant to the final closing statement. The EXCO Acquisition was funded through borrowings from the Company’s credit facility with LegacyTexas Bank. EXCO Acquisition Unaudited Pro Forma Results of Operations Below are consolidated results of operations for the years ended December 31, 2016 and 2015 as though the EXCO Acquisition made during 2016 had been completed as of January 1, 2015. The EXCO Acquisition closed October 3, 2016, and accordingly, the Company’s consolidated statements of operations for the year ended December 31, 2016 includes the results of operations for the three months ended December 31, 2016 of the EXCO properties acquired, including approximately $2.4 million of revenue. Unaudited Pro Forma Consolidated Results For Years Ended (in thousands, except per share amounts ) 2016 2015 Revenue $ 13,963 $ 22,178 Net (loss) income before non-controlling interests (6,825 ) (3,627 ) Net loss (income) attributable to non-controlling interests 413 636 Net (loss) income attributable to controlling interests (6,412 ) (2,991 ) Net (loss) income per share (basic) (1.17 ) (0.56 ) Net (loss) income per share (diluted) (1.17 ) (0.56 ) Divestitures During December 2014, Nytis LLC together with Liberty Energy LLC (the “Sellers”) completed a preliminary closing in accordance with a purchase and sale agreement 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 purchase and sale agreement, 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. During 2015, the final closing was completed. In connection with the final closing, Nytis LLC received an additional $42,000 in cash.

Property and Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2016
Property and Equipment [Abstract]
Property and Equipment	Note 5 – Property and Equipment Net property and equipment at December 31, 2016 and 2015 consists of the following: (in thousands) As of December 31, 2016 2015 Oil and gas properties: Proved oil and gas properties $ 111,771 $ 97,453 Unproved properties not subject to depletion 1,999 3,194 Accumulated depreciation, depletion, amortization and impairment (78,559 ) (72,421 ) Net oil and gas properties 35,211 28,226 Furniture and fixtures, computer hardware and software, and other equipment 990 825 Accumulated depreciation and amortization (665 ) (587 ) Net other property and equipment 325 238 Total net property and equipment $ 35,536 $ 28,464 The Company had approximately $2.0 million and $3.2 million, at December 31, 2016 and 2015, respectively, of unproved oil and gas properties not subject to depletion. At December 31, 2016 and 2015, the Company’s unproved properties consist principally of leasehold acquisition costs in the following areas: As of December 31, (in thousands) 2016 2015 Illinois Basin: Indiana $ 431 $ 433 Illinois 298 309 Appalachian Basin: Kentucky 750 1,523 Ohio 66 66 West Virginia 454 863 Total unproved properties not subject to depletion $ 1,999 $ 3,194 During the years ended December 31, 2016 and 2015, expiring leasehold costs reclassified into proved property were approximately $1.3 million and $189,000, respectively. 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. These costs do not relate to any individually significant projects. The excluded properties are assessed for impairment at least annually. The Company capitalized overhead applicable to acquisition, development and exploration activities of approximately $562,000 and $576,000 for the years ended December 31, 2016 and 2015, respectively. Depletion expense related to oil and gas properties for the years ended December 31, 2016 and 2015 was approximately $1.8 million and $2.5 million or $0.56 and $0.93 per Mcfe, respectively. Depreciation and amortization expense related to furniture and fixtures, computer hardware and software and other equipment for the years ended December 31, 2016 and 2015 was approximately $114,000 and $140,000, respectively.

Equity and Cost Method Investme

Equity and Cost Method Investment	12 Months Ended
	Dec. 31, 2016
Equity and Cost Method Investment [Abstract]
Equity and Cost Method Investment	Note 6 – Equity and Cost 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 years ended December 31, 2016 and 2015, the Company recorded equity method loss of approximately $17,000 and income of approximately $16,000, respectively, related to this investment. In addition, during 2016, the Company received cash distributions totaling $340,000 from CCGGC. During 2016, the Company received distributions of approximately $65,000 from its investment in Sullivan Energy which it accounts for using the cost method of accounting and as such the Company recognized investment income of $65,000 for the year ended December 31, 2016.

Bank Credit Facility

Bank Credit Facility	12 Months Ended
	Dec. 31, 2016
Bank Credit Facility [Abstract]
Bank Credit Facility	Note 7 – Bank Credit Facility On September 30, 2016, the Company terminated its credit facility with Bank of Oklahoma. On October 3, 2016, in connection with and concurrently with the closing of the EXCO Acquisition, Carbon entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank. LegacyTexas Bank is the initial lender and acts as administrative agent. The credit facility has a maximum availability of $100.0 million (with a $500,000 sublimit for letters of credit), which availability is subject to the amount of the borrowing base. The initial borrowing base established under the credit facility is $17.0 million. The borrowing base is subject to semi-annual redeterminations in March and September, commencing March 2017. On March 30, 2017, the borrowing base was increased to $23.0 million. The credit facility is guaranteed by each existing and future direct or indirect subsidiary of Carbon (subject to certain exceptions). The obligations of Carbon and the subsidiary guarantors under the credit facility are secured by pledges of the equity of Nytis USA held by Carbon and the equity of Nytis LLC held by Nytis USA and by essentially all tangible and intangible personal and real property of the Company. Interest is payable quarterly and accrues on borrowings under the credit facility at a rate per annum equal to either (i) the base rate plus an applicable margin between 0.50% and 1.50% or (ii) the Adjusted LIBOR rate plus an applicable margin between 3.50% and 4.50% at Carbon’s option. The actual margin percentage is dependent on the credit facility utilization percentage. Carbon is obligated to pay certain fees and expenses in connection with the credit facility, including a commitment fee for any unused amounts of 0.50% and an origination fee of 0.75%. The credit facility contains certain affirmative and negative covenants that, among other things, limit the Company’s ability to (i) incur additional debt; (ii) incur additional liens; (iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distributions on, or repurchases of, equity; (vi) make certain investments; (vii) enter into certain transactions with its affiliates; (viii) enter into sales-leaseback transactions; (ix) make optional or voluntary payments of debt; (x) change the nature of its business; (xi) change its fiscal year to make changes to the accounting treatment or reporting practices; (xii) amend constituent documents; and (xiii) enter into certain hedging transactions. The affirmative and negative covenants are subject to various exceptions, including certain basket amounts and acceptable transaction levels. In addition, the credit facility requires Carbon’s compliance, on a consolidated basis, with (i) a maximum funded Debt/EBITDA ratio of 3.5 to 1.0 and (ii) a minimum current ratio of 1.0 to 1.0, commencing with the quarter ending March 31, 2017. Carbon may at any time repay the loans under the credit facility, in whole or in part, without penalty. Carbon must pay down borrowings under the credit facility or provide mortgages of additional oil and natural gas properties to the extent that outstanding loans and letters of credit exceed the borrowing base. As required under the terms of the credit facility, the Company has agreed to establish pricing for a certain percentage of its production through the use of derivative contracts. To that end, the Company has entered into an ISDA Master Agreement with BP Energy Company that establishes standard terms for the derivative contracts and an inter-creditor agreement with LegacyTexas Bank and BP Energy Company whereby any credit exposure related to the derivative contracts entered into by the Company and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facility. Initial borrowings under the credit facility were used (i) to pay off and terminate Nytis LLC’s existing credit facility with Bank of Oklahoma, (ii) to pay the purchase price of the EXCO Acquisition, (iii) to pay costs and expenses associated with the EXCO Acquisition and (iv) to provide working capital for the Company. As of December 31, 2016, there were approximately $16.2 million in outstanding borrowings and approximately $800,000 of additional borrowing capacity available under the credit facility. The Company’s effective borrowing rate at December 31, 2016 was approximately 5.4%.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Taxes [Abstract]
Income Taxes	Note 8 – Income Taxes The provision for income taxes for the years ended December 31, 2016 and 2015 consists of the following: (in thousands) Year Ended December 31, 2016 December 31, 2015 Current income tax expense $ - $ - Deferred income tax (benefit) expense (4,472 ) (3,733 ) Change in valuation allowance 4,472 3,773 Total income tax expense $ - $ - The effective income tax rate for the years ended December 31, 2016 and 2015 differed from the statutory U.S. federal income tax rate as follows: Year Ended December 31, 2016 December 31, 2015 Federal income tax rate 35.0 % 35.0 % State income taxes, net of federal benefit 3.5 3.5 Percentage depletion in excess of basis 1.1 1.3 Non-controlling interest in consolidated partnerships (.4 ) (.4 ) True-up of prior year depletion in excess of basis .2 .2 Stock-based compensation deficiency (2.9 ) (1.8 ) Rate changes of prior year deferreds (1.6 ) 4.2 Increase in valuation allowance and other (34.9 ) (42.0 ) Total income tax expense - - The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities at December 31, 2016 and 2015 are presented below: (in thousands) December 31, 2016 December 31, 2015 Deferred tax assets Net operating loss carryforwards $ 8,274 $ 5,433 Depletion carryforwards 2,740 2,570 Accrual and other 1,694 1,318 Derivatives 730 (213 ) Asset retirement obligations 1,936 1,168 Property, plant and equipment 6,439 7,185 Total deferred tax assets 21,813 17,461 Deferred tax liability Interest in partnerships (762 ) (757 ) Less valuation allowance (21,051 ) (16,704 ) Net deferred tax asset $ - $ - The Company has net operating losses (“NOL”) of approximately $19.7 million available to reduce future years’ federal taxable income. The federal net operating losses expire beginning in 2031 through 2036. The Company has NOL of approximately $34.4 million available to reduce future years’ state taxable income. These state NOL carryforwards will expire beginning in 2023 through 2036 depending on each jurisdiction’s specific law surrounding NOL carryforwards. Tax returns are subject to audit by various taxation authorities. The results of any audits will be accounted for in the period in which they are determined. The Company believes that the tax positions taken in the Company's tax returns satisfy the more likely than not threshold for benefit recognition. Accordingly, no liabilities have been recorded by the Company. Any potential adjustments for uncertain tax positions would be a reclassification between the deferred tax asset related to the Company’s NOL and another deferred tax asset. The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. As of December 31, 2016, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the current year.

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2016
Stockholders' Equity [Abstract]
Stockholders' Equity	Note 9 – Stockholders’ Equity Authorized and Issued Capital Stock Effective March 15, 2017 and pursuant to a reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. References to the number of shares and price per share give retroactive effect to the reverse stock split for all periods presented. As of December 31, 2016, the Company had 200,000,000 shares of common stock authorized with a par value of $0.01 per share, of which approximately 5.5 million were issued and outstanding and 1,000,000 shares of preferred stock with a par value of $0.01 per share, none of which were issued and outstanding. During the year ended December 31, 2016, the increase in the Company’s issued and outstanding common stock reflect restricted stock, and performance units net of shares exchanged for payroll tax obligations paid by the Company, that vested during the year. Equity Plans Prior to Merger In 2011, pursuant to an Agreement and Plan of Merger by and among St. Lawrence Seaway Corporation (“SLSC”), St. Lawrence Merger Sub, Inc. (“Merger Co.”) and Nytis USA, Merger Co. merged with and into Nytis USA with Nytis USA remaining as the surviving subsidiary of SLSC. Pursuant to the merger, all options, warrants and restricted stock were adjusted to reflect the conversion ratio used in the merger. As of December 31, 2016, the Company has 12,500 warrants granted by SLSC prior to the merger outstanding and exercisable and approximately 24,000 shares of common stock outstanding that are subject to restricted stock agreements. Nytis USA Warrants As of December 31, 2016, the Company has 12,500 warrants outstanding and exercisable, which were granted by SLSC prior to the merger. These warrants have an exercise price of $20.00 and expire on August 31, 2017. Nytis USA Restricted Stock Plan Under Nytis USA’s restricted stock plan, participants were granted stock without cost to the participant. As of December 31, 2016, there were approximately 24,000 shares of unvested restricted stock granted under the Nytis USA Restricted Stock Plan (“Nytis USA Plan”). The Company accounted for these grants at their intrinsic value. From the dates 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 costs recognized for these restricted stock grants were approximately $335,000 for the years ended December 31, 2016 and 2015. As of December 31, 2016, compensation costs relative to these restricted stock have been fully recognized. Carbon Stock Incentive Plans The Company has two stock plans, the Carbon 2011 Stock Incentive Plan and the Carbon 2015 Stock Incentive Plan (collectively the “Carbon Plans”). The Carbon Plans were approved by the shareholders of the Company and in the aggregate provide for the issuance of approximately 1.1 million shares of common stock to Carbon officers, directors, employees or consultants eligible to receive the 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 Restricted stock awards for employees vest ratably over a three-year service period or cliff vest at the end of 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 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). For restricted stock granted between 2014 and 2016, the Company recognized compensation expense based on the grant date fair value of the shares, utilizing an enterprise value approach, using valuation metrics primarily based on multiples of cash flow from operations, production and reserves. For restricted stock and performance units granted in 2013, the Company utilized the closing price of the Company’s stock on the date of grant to recognize compensation expense. The following table shows a summary of the Company’s unvested restricted stock under the Carbon Plans as of December 31, 2016 and 2015 as well as activity during the years then ended. Weighted Avg Number Grant Date of Shares Fair Value Restricted stock awards, nonvested, January 1, 2015 176,167 $ 12.26 Granted 87,000 8.00 Vested (64,167 ) 12.33 Restricted stock awards, nonvested, December 31, 2015 199,000 10.37 Granted 134,501 5.40 Vested (64,668 ) 10.84 Forfeited (1,083 ) 6.20 Restricted stock awards, nonvested, December 31, 2016 267,750 $ 7.78 Compensation costs recognized for these restricted stock grants were approximately $742,000 and $762,000 for the years ended December 31, 2016 and 2015, respectively. As of December 31, 2016, there was approximately $1.2 million of unrecognized compensation costs related to these restricted stock grants which the Company expects to be recognized over the next 6.3 years. Restricted Performance Units 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 certain performance measures relative to a defined peer group or the growth of certain performance measures over a defined period of time for the Company as well as 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. The following table shows a summary of the Company’s unvested performance units as of December 31, 2016 and 2015 as well as activity during the years then ended. Number of Shares Restricted performance units, non-vested, January 1, 2015 234,311 Granted 80,000 Restricted performance units, non-vested, December 31, 2015 314,311 Granted 80,000 Vested (84,480 ) Forfeited (13,520 ) Restricted performance units, non-vested, December 31, 2016 296,311 The Company accounts for the performance units granted during 2012 and 2014 through 2016 at their fair value determined at the date of grant, which were $12.80, $11.80, $8.00 and $5.40 per share, respectively. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At December 31, 2016, the Company estimated that none of the performance units granted in 2012 and 2016 would vest whether due to change in control or other performance provisions and accordingly, no compensation cost has been recorded for these performance units. During 2016, the Company estimated that it was probable that a portion of the performance units granted in 2014 and 2015 would vest and therefore compensation costs of approximately $1.2 million related to these performance units were recognized for the year ended December 31, 2016. As of December 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 through 2016 would be approximately $2.5 million. The performance units granted in 2013 contained specific vesting provisions, and did not contain 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 and 2014-2016, 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. MCS is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of the Company’s common stock and those of the Company’s defined peer group and was determined to be 92.92%. A risk free interest rate of .39% was determined based on the yield of U.S. Treasury strips with maturities similar to those of the expected term of the performance units which was determined to be 2.87 years. The grant date fair value of these performance units as determined by the valuation model was $10.80 per share. Compensation costs recognized for these performance units were approximately $127,000 and $346,000 for the years ended December 31, 2016 and 2015, respectively. As of December 31, 2016, compensation costs relative to these performance units have been fully recognized.

Accounts Payable and Accrued Li

Accounts Payable and Accrued Liabilities	12 Months Ended
	Dec. 31, 2016
Accounts Payable and Accrued Liabilities [Abstract]
Accounts Payable and Accrued Liabilities	Note 10 – Accounts Payable and Accrued Liabilities Accounts payable and accrued liabilities at December 31, 2016 and 2015 consist of the following: (in thousands) As of December 31, 2016 2015 Accounts payable $ 2,315 $ 577 Oil and gas revenue payable to oil and gas property owners 1,415 862 Gathering and transportation payables 468 359 Production taxes payable 113 59 Drilling advances received from joint venture partner 955 2,115 Accrued drilling costs 4 112 Accrued lease operating costs 282 76 Accrued ad valorem taxes 1,552 496 Accrued general and administrative expenses 1,572 833 Accrued income taxes payable - - Accrued interest 184 3 Other liabilities 261 129 Total accounts payable and accrued liabilities $ 9,121 $ 5,621

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Fair Value Measurements [Abstract]
Fair Value Measurements	Note 11 – 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 in 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 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 December 31, 2016 and 2015 by level within the fair value hierarchy: (in thousands) Fair Value Measurements Using Level 1 Level 2 Level 3 Total December 31, 2016 Liabilities: Commodity derivatives $ - $ 1,932 $ - $ 1,932 December 31, 2015 Assets: Commodity derivatives $ - $ 559 $ - $ 559 As of December 31, 2016, the Company’s commodity derivative financial instruments are comprised of eight natural gas and nine oil swap agreements. As of December 31, 2015, the Company’s commodity derivative financial instruments were comprised of three natural gas swap agreements and one gas and four oil costless collar agreements. The fair values of these agreements are determined under an income valuation technique. 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 results 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 for all of the Company’s outstanding commodity derivative financial instruments as of December 31, 2016 is BP Energy Company. Assets Measured and Recorded at Fair Value on a Non-recurring Basis The fair value of each of the following assets and 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 years ended December 31, 2016 and 2015, the Company recorded asset retirement obligations for additions of approximately $1.8 million and $4,000, respectively. See Note 3 for additional information. To determine the fair value of the proved developed properties acquired in 2016, the Company primarily used the income approach and made market assumptions as to projections of estimated quantities of oil and natural gas reserves, future production rates, future commodity prices including price differentials as of the Closing Date, future operating and development costs and a market participant weighted average cost of capital. The fair value of the non-controlling interest in the partnerships the Company is required to consolidate, was determined based on the net discounted cash flows of the proved developed producing properties attributable to the non-controlling interests in these partnerships. The Company assumed certain firm transportation contracts as part of an acquisition in 2011. The fair value of the 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.

Physical Delivery Contracts and

Physical Delivery Contracts and Commodity Derivatives	12 Months Ended
	Dec. 31, 2016
Physical Delivery Contracts and Commodity Derivatives [Abstract]
Physical Delivery Contracts and Commodity Derivatives	Note 12 – Physical Delivery Contracts and Commodity 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 has historically entered into fixed price delivery contracts to effectively provide commodity 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. Pursuant to the terms of the Company’s credit facility with LegacyTexas Bank, the Company has entered into swap derivative agreements to hedge certain of its oil and natural gas production for 2017 through 2019. As of December 31, 2016, these derivative agreements consisted of the following: Natural Gas Oil Weighted Weighted Average Average Year MMBtu Price (a) Bbl Price (b) 2017 3,360,000 $ 3.30 60,000 $ 52.98 2018 3,120,000 $ 3.01 48,000 $ 54.11 2019 1,320,000 $ 2.85 36,000 $ 54.90 (a) NYMEX Henry Hub Natural Gas futures contract for the respective period. (b) NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective period. 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) As of December 31, 2016 2015 Commodity derivative contracts: Current assets $ - $ 408 Non-current assets $ - $ 151 Current liabilities $ 1,341 $ - Non-current liabilities $ 591 $ - The table below summarizes the commodity settlements and unrealized gains and losses related to the Company’s derivative instruments for the years ended December 31, 2016 and 2015. These commodity settlements and unrealized gains and losses are recorded and included in commodity derivative gain or loss in the accompanying Consolidated Statements of Operations. (in thousands) For the year ended 2016 2015 Commodity derivative contracts: Settlement gains $ 231 $ 1,615 Unrealized losses (2,490 ) (763 ) Total settlement and unrealized (losses) gains, net $ (2,259 ) $ 852 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 BP Energy Company. T he Company has entered into an ISDA Master Agreement with BP Energy Company that establishes standard terms for the derivative contracts and an inter-creditor agreement with LegacyTexas Bank and BP Energy Company whereby any credit exposure related to the derivative contracts entered into by the Company and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facility. 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 contracts and in the event of default or termination of the contracts. The following table summarizes the location and fair value amounts of all derivative instruments in the Consolidated Balance Sheet, as well as the gross recognized derivative assets, liabilities and amounts offset in the Consolidated Balance Sheet as of December 31, 2016. Net Gross Recognized Recognized Gross Fair Value Assets/ Amounts Assets/ Balance Sheet Classification Liabilities Offset Liabilities Commodity derivative assets: Current assets $ - $ - $ - Other long-term assets 249 (249 ) - Total derivative assets $ 249 $ (249 ) $ - Commodity derivative liabilities: Current liability $ 1,341 $ - $ 1,341 Non-current liabilities 840 (249 ) 591 Total derivative liabilities $ 2,181 $ (249 ) $ 1,932 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 and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies [Abstract]
Commitments and Contingencies	Note 13 – Commitments and Contingencies The Company has entered into employment agreements with certain executives and officers of the Company. The term of the agreements generally range from one to two years and provide for renewal provisions in one year increments thereafter. The agreements provide for, among other items, severance and continuation of benefit payments upon termination of employment or certain change of control events. The Company has entered into long-term firm transportation contracts to ensure the transport for certain of its gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts at December 31, 2016 are summarized in the table below. Period Dekatherms per day Demand Charges Jan 2017 - Apr 2018 5,530 $0.20 - $0.65 May 2018 - Mar 2020 3,230 $0.20 - $0.62 Apr 2020 – May 2020 2,150 $0.20 Jun 2020 – May 2036 1,000 $0.20 A liability of approximately $822,000 related to firm transportation contracts assumed in a 2011 asset acquisition and the EXCO Acquisition in 2016, which represents the remaining commitment, is reflected on the Company’s Consolidated Balance Sheet as of December 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. The Company leases, under an operating lease arrangement, approximately 5,500 square feet of administrative office space in Denver, Colorado and approximately 5,300 square feet of office space in Lexington, Kentucky, both of which expire in 2019. For the years ended December 31, 2016 and 2015, the Company incurred rental expenses of $220,000 and $236,000, respectively. The Company has minimum lease payments for its office space and equipment of approximately $260,000 for 2017, $263,000 for 2018 and $263,000 for 2019.

Retirement Savings Plan

Retirement Savings Plan	12 Months Ended
	Dec. 31, 2016
Retirement Savings Plan [Abstract]
Retirement Savings Plan	Note 14 – Retirement Savings Plan The Company has a 401(k) plan available to eligible employees. The plan provides for 6% matching which vests immediately. For the years ended December 31, 2016 and 2015, the Company paid approximately $99,000 and $277,000, respectively, for 401(k) contributions and related administrative expenses. During 2016, as part of a cost reduction measure, the Company temporarily suspended its 401 (k) match from August through December.

Supplemental Cash Flow Disclosu

Supplemental Cash Flow Disclosure	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Disclosure [Abstract]
Supplemental Cash Flow Disclosure	Note 15 – Supplemental Cash Flow Disclosure Supplemental cash flow disclosures for the years ended December 31, 2016 and 2015 are presented below: (in thousands) For the Year Ended 2016 2015 Cash paid during the period for: Interest payments $ 156 $ 166 Income taxes - 325 Non-cash transactions: Increase in net asset retirement obligations $ 1,849 $ 4 Increase (decrease) in accounts payable and accrued liabilities included in oil and gas properties $ 1,099 $ (215 ) Obligations assumed with acquisitions $ 2,694 $ -

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	Note 16 – Subsequent Events On March 15, 2017 and pursuant to a reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. All references to the number of shares of common stock and per share amounts give retroactive effect to the reverse stock split for all periods presented. On February 15, 2017, the Company entered into an Amended and Restated Limited Liability Company Agreement ( “LLC Agreement” On February 15, 2017, Carbon California (i) issued and sold Class A Units to two institutional investors for an aggregate cash consideration of $22 million, (ii) entered into a Note Purchase Agreement (the “Note Purchase Agreement” “Senior Revolving Notes” Securities Purchase Agreement” “Subordinated Notes” Net proceeds from the Offering Transaction were used by Carbon California to complete the acquisitions of oil and gas assets in the Ventura Basin of California from three entities, which acquisitions also closed on February 15, 2017. The remainder of the net proceeds will be used to fund field development projects and to fund future complementary acquisitions and for general working capital purposes of Carbon California. In connection with the Company entering into the LLC Agreement described above and Carbon California engaging in the transactions also described above, the Company issued to an affiliate of one of the institutional investors which purchased Class A Units of Carbon California (which is also an affiliate of the Company’s largest stockholders), a warrant to purchase shares of the Company’s common stock at an exercise price of $7.20 per share (the “Warrant” The borrowing base under the Company’s credit facility is subject to semi-annual redeterminations in March and September, commencing March 2017. On March 30, 2017, the borrowing base was increased from $17.0 million to $23.0 million.

Supplemental Financial Data - O

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited)	12 Months Ended
	Dec. 31, 2016
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) [Abstract]
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited)	Note 17– Supplemental Financial Data – Oil and Gas Producing Activities (unaudited) Estimated Proved Oil and Gas Reserves The reserve estimates as of December 31, 2016 and 2015 presented herein were made in accordance with oil and gas reserve estimation and disclosure authoritative accounting guidance. Proved oil and gas reserves as of December 31, 2016 and 2015 were calculated based on the prices for oil and gas during the twelve month period before the reporting date, determined as an un-weighted arithmetic average of the first-day-of-the month price for each month within such period. This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. SEC rules dictate the types of technologies that a company may use to establish reserve estimates, including the extraction of non-traditional resources, such as bitumen extracted from oil sands as well as oil and gas extracted from shales. The Company’s estimates of its net proved, net proved developed, and net proved undeveloped oil and gas reserves and changes in its net proved oil and gas reserves for 2016 and 2015 are presented in the table below. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Existing economic conditions include the average prices for oil and gas during the twelve month period prior to the reporting date of December 31, 2016 and 2015 unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Prices do not include the effects of commodity derivatives. The independent petroleum engineering firm, Cawley, Gillespie & Associates, Inc. (“CGA”), evaluated and prepared independent estimated proved reserves quantities and related pre-tax future cash flows as of December 31, 2016 and 2015. To facilitate the preparation of an independent reserve study, we provided CGA our reserve database and related supporting technical, economic, production and ownership information. Estimated reserves and related pre-tax future cash flows for the non-controlling interests of the consolidated partnerships included in the Company’s Consolidated Financial Statements, were based on CGA’s estimated reserves and related pre-tax future cash flows for the specific properties in the partnerships and have been added to CGA’s reserve estimates for December 31, 2016 and 2015. See Note 3 for additional information. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. A summary of the Company’s changes in quantities of proved oil and gas reserves for the years ended December 31, 2016 and 2015 are as follows: 2016 2015 Oil Natural Gas Total Oil Natural Gas Total MBbls MMcf MMcfe MBbls MMcf MMcfe Proved reserves, beginning of year 598 29,958 33,546 853 36,948 42,066 Revisions of previous estimates 110 2,207 2,867 (185 ) (4,670 ) (5,780 ) Extensions and discoveries - - - 31 - 186 Production (79 ) (2,823 ) (3,297 ) (101 ) (2,040 ) (2,646 ) Purchases of reserves in-place 253 44,923 46,441 - 138 138 Sales of reserves in-place - - - - (418 ) (418 ) Proved reserves, end of year 882 74,265 79,557 598 29,958 33,546 Proved developed reserves at: End of Year 851 74,265 79,371 554 29,958 33,282 Proved undeveloped reserves at: End of Year 31 - 186 44 - 264 The estimated proved reserves for December 31, 2016 and 2015 includes approximately 3.1 and 3.0 Bcfe, respectively, attributed to non-controlling interests of consolidated partnerships. Aggregate Capitalized Costs The aggregate capitalized costs relating to oil and gas producing activities at the end of each of the years indicated were as follows: 2016 2015 (in thousands) Oil and gas properties Proved oil and gas properties $ 112,579 $ 97,453 Unproved properties not subject to depletion 1,999 3,194 Accumulated depreciation, depletion, amortization and impairment (78,596 ) (72,421 ) Net oil and gas properties $ 35,982 $ 28,226 Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities The following costs were incurred in oil and gas property acquisition, exploration, and development activities during the years ended December 31, 2016 and 2015: 2016 2015 (in thousands) Property acquisition costs: Unevaluated properties $ 97 $ 341 Proved properties and gathering facilities 8,117 - Development costs 360 2,106 Gathering facilities 42 578 Asset retirement obligation 1,849 4 Total costs incurred $ 10,465 $ 3,029 The Company’s investment in unproved properties as of December 31, 2016, by the year in which such costs were incurred is set forth in the table below: 2016 2015 2014 and Prior (in thousands) Acquisition costs $ 97 $ 341 $ 1,561 Results of Operations from Oil and Gas Producing Activities Results of operations from oil and gas producing activities for the years ended December 31, 2016 and 2015 are presented below: 2016 2015 (in thousands) Oil and gas sales, including commodity derivative gains and losses $ 8,184 $ 11,560 Expenses: Production expenses 5,640 5,507 Depletion expense 1,839 2,466 Accretion of asset retirement obligations 176 123 Impairment of oil and gas properties 4,299 5,419 Total expenses 11,954 13,515 Results of operations from oil and gas producing activities $ (3,770 ) $ (1,955 ) Depletion rate per Mcfe $ 0.56 $ 0.93 Standardized Measure of Discounted Future Net Cash Flows Future oil and gas sales are calculated applying the prices used in estimating the Company’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes were considered only to the extent provided by contractual arrangements in existence at each year-end. Future production and development costs, which include costs related to plugging of wells, removal of facilities and equipment, and site restoration, are calculated by estimating the expenditures to be incurred in producing and developing the proved oil and gas reserves at the end of each year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses give effect to tax deductions, credits, and allowances relating to the proved oil and gas reserves. All cash flow amounts, including income taxes, are discounted at 10%. Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of the Company’s proved reserves. Management does not rely upon the information that follows in making investment decisions. December 31, 2016 2015 (in thousands) Future cash inflows $ 214,658 $ 102,741 Future production costs (103,252 ) (47,117 ) Future development costs (315 ) (420 ) Future income taxes (14,858 ) - Future net cash flows 96,233 55,204 10% annual discount (51,522 ) (30,172 ) Standardized measure of discounted future net cash flows $ 44,711 $ 25,032 Changes in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves An analysis of the changes in the standardized measure of discounted future net cash flows during each of the last two years is as follows: December 31, 2016 2015 (in thousands) Standardized measure of discounted future net cash flows, beginning of year $ 25,032 $ 65,006 Sales of oil and gas, net of production costs and taxes (4,804 ) (5,283 ) Price revisions (786 ) (37,490 ) Extensions, discoveries and improved recovery, less related costs - 384 Changes in estimated future development costs 248 3,290 Development costs incurred during the period 102 - Quantity revisions 2,091 (4,282 ) Accretion of discount 2,503 6,702 Net changes in future income taxes (4,633 ) 2,010 Purchases of reserves-in-place 26,776 115 Sales of reserves-in-place - (380 ) Changes in production rate timing and other (1,818 ) (5,040 ) Standardized measure of discounted future net cash flows, end of year $ 44,711 $ 25,032 The twelve month weighted averaged adjusted prices in effect at December 31, 2016 and 2015 were as follows: 2016 2015 Oil (per Bbl) $ 40.40 $ 46.12 Natural Gas (per Mcf) $ 2.41 $ 2.50

Summary of Significant Accoun24

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Summary of Significant Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The Consolidated Financial Statements include the accounts of Carbon and its consolidated subsidiaries. The Company owns 100% of Nytis USA. Nytis USA owns approximately 99% of Nytis LLC. Nytis LLC also holds interests in various oil and gas partnerships. For partnerships where the Company has a controlling interest, the partnerships are consolidated. The Company is currently consolidating 46 partnerships and 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 interest 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 the Company’s 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.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents, if any, in excess of daily requirements have been generally invested in money market accounts, certificates of deposits and other cash equivalents with maturities of three months or less. Such investments are deemed to be cash equivalents for purposes of the Consolidated Financial Statements. The carrying amount of cash equivalents approximates fair value because of the short maturity and high credit quality of these investments.
Accounts Receivable	Accounts Receivable The Company’s accounts receivable are primarily comprised of oil and natural gas revenues from producing activities and from other exploration and production companies and individuals who own working interests in the properties that the Company operates. The Company grants credit to all qualified customers, which potentially subjects the Company to credit risk resulting from, among other factors, adverse changes in the industries in which the Company operates and the financial condition of its customers. The Company continuously monitors collections and payments from its customers and maintains an allowance for doubtful accounts based upon its historical experience and any specific customer collection issues that it has identified. At December 31, 2016 and 2015, the Company had not identified any collection issues related to its oil and gas operations and as a consequence no allowance for doubtful accounts was provided for on those dates. In addition, accounts receivable included a deposit of $1.7 million made by the Company on the purchase of assets in the Ventura Basin of California through Carbon California Company, LLC (“Carbon California”). The deposit was reimbursed to the Company upon the consummation of the acquisition by Carbon California Company LLC on February 15, 2017. See Note 16 for additional information.
Oil and Natural Gas Sales	Oil and Natural Gas Sales The Company sells its oil and natural gas production to various purchasers in the industry. The table below presents purchasers that account for 10% or more of total oil and natural gas sales for the years ended December 31, 2016 and 2015. There are a number of purchasers in the areas where the Company sells its production. Management does not believe that changing its primary purchasers or a loss of any other single purchaser would materially impact the Company’s business. Purchaser 2016 2015 Purchaser A 18 % 18 % Purchaser B 17 % 24 % Purchaser C 16 % 15 % Purchaser D 15 % 15 % The Company recognizes an asset or a liability, whichever is appropriate, for revenues associated with over-deliveries or under-deliveries of natural gas to purchasers. A purchaser imbalance asset occurs when the Company delivers more natural gas than it nominated to deliver to the purchaser and the purchaser pays only for the nominated amount. Conversely, a purchaser imbalance liability occurs when the Company delivers less natural gas than it nominated to deliver to the purchaser and the purchaser pays for the amount nominated. As of December 31, 2016 and 2015, the Company had a purchaser imbalance payable of approximately $25,000 and a receivable of approximately $270,000, respectively, which are recognized as a current liability and current asset, respectively, in the Company’s Consolidated Balance Sheets.
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 related 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 gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus 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. See Note 4 regarding the Company’s 2015 divestitures. 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 on a quarterly basis. 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 or impairment 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 capitalized costs in future periods. For the years ended December 31, 2016 and 2015, the Company recognized a ceiling test impairment of approximately $4.3 million and $5.4 million, respectively. Future declines in oil and natural gas prices could result in impairments of our oil and gas properties in future periods. Because the ceiling test used previous twelve month period average commodity prices, the effect of declining prices since mid-2014 had a negative impact on the average price used to value our reserves which will lower the ceiling test value in future periods and may result in additional impairments of our oil and gas properties. The effect of price declines will impact the ceiling test value until such time commodity prices stabilize or improve. Impairment changes are a non-cash charge and accordingly would not affect cash flows but would adversely affect our net income and shareholders’ equity.
Other Property and Equipment	Other Property and Equipment Other property and equipment are recorded at cost upon acquisition. Depreciation of other property and equipment is calculated over three to seven years using the straight-line method.
Long-Lived Assets	Long-Lived Assets The Company reviews its long-lived assets other than oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered. The Company looks primarily to the estimated undiscounted future cash flows in its assessment of whether or not long-lived assets have been impaired.
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 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 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 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 years ended December 31, 2016 and 2015. Year Ended December 31, (in thousands) 2016 2015 Balance at beginning of year $ 3,095 $ 2,968 Accretion expense 176 123 Additions during period 1,849 4 5,120 3,095 Less: ARO recognized as a current liability (114 ) - Balance at end of year $ 5,006 $ 3,095 For the year ended December 31, 2016, the addition of approximately $1.8 million to ARO is primarily due to the acquisition of producing oil and natural gas properties in the Appalachian Basin in the fourth quarter of 2016.
Financial Instruments	Financial Instruments The Company’s financial instruments include cash and cash equivalents, accounts receivables, accounts payables, accrued liabilities, commodity derivative instruments and its notes payable. The carrying value of cash and cash equivalents, accounts receivables, payables and accrued liabilities are considered to be representative of their fair value, due to the short maturity of these instruments. The Company’s commodity derivative instruments are recorded at fair value, as discussed below and in Note 11. The carrying amount of the Company’s notes payable approximated fair value since borrowings bear interest at variable rates, which are representative of the Company’s credit adjusted borrowing rate.
Commodity Derivative Instruments	Commodity Derivative Instruments The Company enters into commodity derivative contracts to manage its exposure to oil and natural gas price volatility with an objective to reduce our exposure to downward price fluctuations. Commodity derivative contracts may take the form of futures contracts, swaps, collars or options. The Company has elected not to designate its derivatives as cash flow hedges. All derivatives are initially and subsequently measured at estimated fair value and recorded as assets or liabilities on the Consolidated Balance Sheets and the changes in fair value are recognized as gains or losses in revenues in the Consolidated Statements of Operations.
Income Taxes	Income Taxes Carbon accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases, as well as the future tax consequences attributable to the future utilization of existing tax net operating losses and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more likely than not recognition threshold are recognized.
Stock - Based Compensation	Stock - Based Compensation Compensation cost is measured at the grant date, based on the fair value of the awards and is recognized on a straight-line basis over the requisite service period (usually the vesting period).
Revenue Recognition	Revenue Recognition Oil and natural gas revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. Natural gas revenues are recognized on the basis of the Company’s net working revenue interest. Net deliveries in excess of entitled amounts are recorded as a liability, while net deliveries lower than entitled amounts are recorded as a receivable.
Earnings Per Common Share	Earnings Per Common Share Basic earnings per common share is computed by dividing the net income attributable to common stockholders for the period by the weighted average number of common shares outstanding during the period. The shares of restricted common stock granted to officers, directors and employees of the Company are included in the computation of basic net income 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: For the Year Ended (in thousands except per share amounts) 2016 2015 Net loss $ (12,406 ) $ (8,298 ) Basic weighted-average common shares outstanding during the period 5,468 5,335 Add dilutive effects of stock options, warrants and non-vested shares of restricted stock - - Diluted weighted-average common shares outstanding during the period 5,468 5,335 Basic net (loss) income per common share $ (2.27 ) $ (1.56 ) Diluted net (loss) income per common share $ (2.27 ) $ (1.56 )
Use of Estimates in the Preparation of Financial Statements	Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and expenses and disclosure of contingent assets and liabilities. Significant items subject to such estimates and assumptions include the carrying value of oil and gas properties, the estimate of proved oil and gas reserve volumes and the related depletion and present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, determining the amounts recorded for deferred income taxes, stock-based compensation, fair value of commodity derivative instruments, fair value of assets acquired qualifying as business contributions and asset retirement obligations. Actual results could differ from those estimates and assumptions used.
Adopted and Recently Issued Accounting Pronouncements	Adopted and Recently Issued Accounting Pronouncements In August 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-15, Statement of Cash Flows-Classification of Certain Cash Receipts and Cash Payments In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805) In September 2015, the FASB issued ASU 2015-16, Business Combinations (Topic 805)

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Summary of Significant Accounting Policies [Abstract]
Summary of percentages by purchaser that account for 10% or more of total oil and natural gas sales	Purchaser 2016 2015 Purchaser A 18 % 18 % Purchaser B 17 % 24 % Purchaser C 16 % 15 % Purchaser D 15 % 15 %
Summary of reconciliation of the ARO	Year Ended December 31, (in thousands) 2016 2015 Balance at beginning of year $ 3,095 $ 2,968 Accretion expense 176 123 Additions during period 1,849 4 5,120 3,095 Less: ARO recognized as a current liability (114 ) - Balance at end of year $ 5,006 $ 3,095
Schedule of basic and diluted (loss) income per share	For the Year Ended (in thousands except per share amounts) 2016 2015 Net loss $ (12,406 ) $ (8,298 ) Basic weighted-average common shares outstanding during the period 5,468 5,335 Add dilutive effects of stock options, warrants and non-vested shares of restricted stock - - Diluted weighted-average common shares outstanding during the period 5,468 5,335 Basic net (loss) income per common share $ (2.27 ) $ (1.56 ) Diluted net (loss) income per common share $ (2.27 ) $ (1.56 )

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2016
Acquisitions and Divestitures [Abstract]
Schedule of assets acquired and liabilities consideration	Consideration paid to Sellers: Cash consideration $ 8,117 Recognized amounts of identifiable assets acquired and liabilities assumed: Proved oil and gas properties and related support facilities $ 12,656 Asset retirement obligations (1,845 ) Working capital (2,694 ) Total identified net assets $ 8,117
Schedule of unaudited pro-forma consolidated results	Unaudited Pro Forma Consolidated Results For Years Ended (in thousands, except per share amounts ) 2016 2015 Revenue $ 13,963 $ 22,178 Net (loss) income before non-controlling interests (6,825 ) (3,627 ) Net loss (income) attributable to non-controlling interests 413 636 Net (loss) income attributable to controlling interests (6,412 ) (2,991 ) Net (loss) income per share (basic) (1.17 ) (0.56 ) Net (loss) income per share (diluted) (1.17 ) (0.56 )

Property and Equipment (Tables)

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Property and Equipment [Abstract]
Summary of net property and equipment	(in thousands) As of December 31, 2016 2015 Oil and gas properties: Proved oil and gas properties $ 111,771 $ 97,453 Unproved properties not subject to depletion 1,999 3,194 Accumulated depreciation, depletion, amortization and impairment (78,559 ) (72,421 ) Net oil and gas properties 35,211 28,226 Furniture and fixtures, computer hardware and software, and other equipment 990 825 Accumulated depreciation and amortization (665 ) (587 ) Net other property and equipment 325 238 Total net property and equipment $ 35,536 $ 28,464
Summary of unproved oil and gas properties	As of December 31, (in thousands) 2016 2015 Illinois Basin: Indiana $ 431 $ 433 Illinois 298 309 Appalachian Basin: Kentucky 750 1,523 Ohio 66 66 West Virginia 454 863 Total unproved properties not subject to depletion $ 1,999 $ 3,194

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Taxes [Abstract]
Summary of provision for income taxes	(in thousands) Year Ended December 31, 2016 December 31, 2015 Current income tax expense $ - $ - Deferred income tax (benefit) expense (4,472 ) (3,733 ) Change in valuation allowance 4,472 3,773 Total income tax expense $ - $ -
Summary of effective income tax rate differed from the statutory U.S. federal income tax rate	Year Ended December 31, 2016 December 31, 2015 Federal income tax rate 35.0 % 35.0 % State income taxes, net of federal benefit 3.5 3.5 Percentage depletion in excess of basis 1.1 1.3 Non-controlling interest in consolidated partnerships (.4 ) (.4 ) True-up of prior year depletion in excess of basis .2 .2 Stock-based compensation deficiency (2.9 ) (1.8 ) Rate changes of prior year deferreds (1.6 ) 4.2 Increase in valuation allowance and other (34.9 ) (42.0 ) Total income tax expense - -
Summary of deferred tax assets and liabilities	(in thousands) December 31, 2016 December 31, 2015 Deferred tax assets Net operating loss carryforwards $ 8,274 $ 5,433 Depletion carryforwards 2,740 2,570 Accrual and other 1,694 1,318 Derivatives 730 (213 ) Asset retirement obligations 1,936 1,168 Property, plant and equipment 6,439 7,185 Total deferred tax assets 21,813 17,461 Deferred tax liability Interest in partnerships (762 ) (757 ) Less valuation allowance (21,051 ) (16,704 ) Net deferred tax asset $ - $ -

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2016
Restricted Stock [Member]
Class Of Stock [Line Items]
Summary of Company's unvested restricted stock	Weighted Avg Number Grant Date of Shares Fair Value Restricted stock awards, nonvested, January 1, 2015 176,167 $ 12.26 Granted 87,000 8.00 Vested (64,167 ) 12.33 Restricted stock awards, nonvested, December 31, 2015 199,000 10.37 Granted 134,501 5.40 Vested (64,668 ) 10.84 Forfeited (1,083 ) 6.20 Restricted stock awards, nonvested, December 31, 2016 267,750 $ 7.78
Restricted Performance Units [Member]
Class Of Stock [Line Items]
Summary of Company's unvested restricted stock	Number of Shares Restricted performance units, non-vested, January 1, 2015 234,311 Granted 80,000 Restricted performance units, non-vested, December 31, 2015 314,311 Granted 80,000 Vested (84,480 ) Forfeited (13,520 ) Restricted performance units, non-vested, December 31, 2016 296,311

Accounts Payable and Accrued 30

Accounts Payable and Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2016
Accounts Payable and Accrued Liabilities [Abstract]
Summary of accounts payable and accrued liabilities	(in thousands) As of December 31, 2016 2015 Accounts payable $ 2,315 $ 577 Oil and gas revenue payable to oil and gas property owners 1,415 862 Gathering and transportation payables 468 359 Production taxes payable 113 59 Drilling advances received from joint venture partner 955 2,115 Accrued drilling costs 4 112 Accrued lease operating costs 282 76 Accrued ad valorem taxes 1,552 496 Accrued general and administrative expenses 1,572 833 Accrued income taxes payable - - Accrued interest 184 3 Other liabilities 261 129 Total accounts payable and accrued liabilities $ 9,121 $ 5,621

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 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 December 31, 2016 Liabilities: Commodity derivatives $ - $ 1,932 $ - $ 1,932 December 31, 2015 Assets: Commodity derivatives $ - $ 559 $ - $ 559

Physical Delivery Contracts a32

Physical Delivery Contracts and Commodity Derivatives (Tables)	12 Months Ended
	Dec. 31, 2016
Physical Delivery Contracts and Commodity Derivatives [Abstract]
Schedule of swap derivative agreements	Natural Gas Oil Weighted Weighted Average Average Year MMBtu Price (a) Bbl Price (b) 2017 3,360,000 $ 3.30 60,000 $ 52.98 2018 3,120,000 $ 3.01 48,000 $ 54.11 2019 1,320,000 $ 2.85 36,000 $ 54.90 (a) NYMEX Henry Hub Natural Gas futures contract for the respective period. (b) NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective period.
Schedule of fair value of the derivatives recorded	(in thousands) As of December 31, 2016 2015 Commodity derivative contracts: Current assets $ - $ 408 Non-current assets $ - $ 151 Current liabilities $ 1,341 $ - Non-current liabilities $ 591 $ -
Schedule of realized and unrealized gains and losses	(in thousands) For the year ended 2016 2015 Commodity derivative contracts: Settlement gains $ 231 $ 1,615 Unrealized losses (2,490 ) (763 ) Total settlement and unrealized (losses) gains, net $ (2,259 ) $ 852
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 $ - $ - $ - Other long-term assets 249 (249 ) - Total derivative assets $ 249 $ (249 ) $ - Commodity derivative liabilities: Current liability $ 1,341 $ - $ 1,341 Non-current liabilities 840 (249 ) 591 Total derivative liabilities $ 2,181 $ (249 ) $ 1,932

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies [Abstract]
Summary of firm transportation volumes and related demand charges	Period Dekatherms per day Demand Charges Jan 2017 - Apr 2018 5,530 $0.20 - $0.65 May 2018 - Mar 2020 3,230 $0.20 - $0.62 Apr 2020 – May 2020 2,150 $0.20 Jun 2020 – May 2036 1,000 $0.20

Supplemental Cash Flow Disclo34

Supplemental Cash Flow Disclosure (Tables)	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Disclosure [Abstract]
Summary of supplemental cash flow disclosures	(in thousands) For the Year Ended 2016 2015 Cash paid during the period for: Interest payments $ 156 $ 166 Income taxes - 325 Non-cash transactions: Increase in net asset retirement obligations $ 1,849 $ 4 Increase (decrease) in accounts payable and accrued liabilities included in oil and gas properties $ 1,099 $ (215 ) Obligations assumed with acquisitions $ 2,694 $ -

Supplemental Financial Data -35

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) [Abstract]
Summary of proved undeveloped and developed oil and gas reserves expected to be recovered from new wells	2016 2015 Oil Natural Gas Total Oil Natural Gas Total MBbls MMcf MMcfe MBbls MMcf MMcfe Proved reserves, beginning of year 598 29,958 33,546 853 36,948 42,066 Revisions of previous estimates 110 2,207 2,867 (185 ) (4,670 ) (5,780 ) Extensions and discoveries - - - 31 - 186 Production (79 ) (2,823 ) (3,297 ) (101 ) (2,040 ) (2,646 ) Purchases of reserves in-place 253 44,923 46,441 - 138 138 Sales of reserves in-place - - - - (418 ) (418 ) Proved reserves, end of year 882 74,265 79,557 598 29,958 33,546 Proved developed reserves at: End of Year 851 74,265 79,371 554 29,958 33,282 Proved undeveloped reserves at: End of Year 31 - 186 44 - 264
Summary of aggregate capitalized costs relating to oil and gas producing activities	2016 2015 (in thousands) Oil and gas properties Proved oil and gas properties $ 112,579 $ 97,453 Unproved properties not subject to depletion 1,999 3,194 Accumulated depreciation, depletion, amortization and impairment (78,596 ) (72,421 ) Net oil and gas properties $ 35,982 $ 28,226
Summary of costs incurred in oil and gas property acquisition, exploration, and development activities	2016 2015 (in thousands) Property acquisition costs: Unevaluated properties $ 97 $ 341 Proved properties and gathering facilities 8,117 - Development costs 360 2,106 Gathering facilities 42 578 Asset retirement obligation 1,849 4 Total costs incurred $ 10,465 $ 3,029
Summary of company's investment in unproved properties	2016 2015 2014 and Prior (in thousands) Acquisition costs $ 97 $ 341 $ 1,561
Summary of results of operations from oil and gas producing activities	2016 2015 (in thousands) Oil and gas sales, including commodity derivative gains and losses $ 8,184 $ 11,560 Expenses: Production expenses 5,640 5,507 Depletion expense 1,839 2,466 Accretion of asset retirement obligations 176 123 Impairment of oil and gas properties 4,299 5,419 Total expenses 11,954 13,515 Results of operations from oil and gas producing activities $ (3,770 ) $ (1,955 ) Depletion rate per Mcfe $ 0.56 $ 0.93
Summary of estimate of the current market value of the Company's proved reserves	December 31, 2016 2015 (in thousands) Future cash inflows $ 214,658 $ 102,741 Future production costs (103,252 ) (47,117 ) Future development costs (315 ) (420 ) Future income taxes (14,858 ) - Future net cash flows 96,233 55,204 10% annual discount (51,522 ) (30,172 ) Standardized measure of discounted future net cash flows $ 44,711 $ 25,032
Summary of discounted future cash flows relating to proved oil and gas reserves	December 31, 2016 2015 (in thousands) Standardized measure of discounted future net cash flows, beginning of year $ 25,032 $ 65,006 Sales of oil and gas, net of production costs and taxes (4,804 ) (5,283 ) Price revisions (786 ) (37,490 ) Extensions, discoveries and improved recovery, less related costs - 384 Changes in estimated future development costs 248 3,290 Development costs incurred during the period 102 - Quantity revisions 2,091 (4,282 ) Accretion of discount 2,503 6,702 Net changes in future income taxes (4,633 ) 2,010 Purchases of reserves-in-place 26,776 115 Sales of reserves-in-place - (380 ) Changes in production rate timing and other (1,818 ) (5,040 ) Standardized measure of discounted future net cash flows, end of year $ 44,711 $ 25,032
Summary of weighted averaged adjusted prices	2016 2015 Oil (per Bbl) $ 40.40 $ 46.12 Natural Gas (per Mcf) $ 2.41 $ 2.50

Summary of Significant Accoun36

Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Concentration Risk [Line Items]
Percentages by purchaser	10.00%	10.00%
Purchaser A [Member]
Concentration Risk [Line Items]
Percentages by purchaser	18.00%	18.00%
Purchaser B [Member]
Concentration Risk [Line Items]
Percentages by purchaser	17.00%	24.00%
Purchaser C [Member]
Concentration Risk [Line Items]
Percentages by purchaser	16.00%	15.00%
Purchaser D [Member]
Concentration Risk [Line Items]
Percentages by purchaser	15.00%	15.00%

Summary of Significant Accoun37

Summary of Significant Accounting Policies (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Summary of reconciliation of the ARO
Balance at beginning of year	$ 3,095	$ 2,968
Accretion expense	176	123
Additions during period	1,849	4
Reconciliation of the ARO, Gross	5,120	3,095
Less: ARO recognized as a current liability	(114)
Balance at end of year	$ 5,006	$ 3,095

Summary of Significant Accoun38

Summary of Significant Accounting Policies (Details 2) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Summary of Significant Accounting Policies [Abstract]
Net loss	$ (12,406)	$ (8,298)
Basic weighted-average common shares outstanding during the period	5,468	5,335
Add dilutive effects of stock options, warrants and non-vested shares of restricted stock
Diluted weighted-average common shares outstanding during the period	5,468	5,335
Basic net (loss) income per common share	$ (2.27)	$ (1.56)
Diluted net (loss) income per common share	$ (2.27)	$ (1.56)

Summary of Significant Accoun39

Summary of Significant Accounting Policies (Details Textual)	12 Months Ended
	Dec. 31, 2016USD ($)Partnershipshares	Dec. 31, 2015USD ($)shares
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 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.
Percentages by purchaser	10.00%	10.00%
Purchaser imbalance liability | $	$ 25,000
Ceiling test impairment cost | $	4,300,000	$ 5,400,000
Accounts receivable included a deposit | $	1,700,000
Oil and natural gas properties | $	$ 1,800,000
Purchaser imbalance receivable | $		$ 270,000
Warrant [Member]
Summary of Significant Accounting Policies (Textual)
Anti-dilutive earnings per shares | shares	13,000	13,000
Stock Options [Member]
Summary of Significant Accounting Policies (Textual)
Anti-dilutive earnings per shares | shares		8,000
Restricted Stock [Member]
Summary of Significant Accounting Policies (Textual)
Anti-dilutive earnings per shares | shares	268,000
Non-vested shares of restricted stock | shares		248,000
Restricted Performance Units [Member]
Summary of Significant Accounting Policies (Textual)
Common stock equivalent restricted to future contingencies | shares	296,000	314,000
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%
Minimum [Member]
Summary of Significant Accounting Policies (Textual)
Other property and equipment, useful life	3 years
Maximum [Member]
Summary of Significant Accounting Policies (Textual)
Other property and equipment, useful life	7 years

Acquisitions and Divestitures40

Acquisitions and Divestitures (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)
Consideration paid to Sellers:
Cash consideration	$ 8,117
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved oil and gas properties and related support facilities	12,656
Asset retirement obligations	(1,845)
Working capital	(2,694)
Total identified net assets	$ 8,117

Acquisitions and Divestitures41

Acquisitions and Divestitures (Details 1) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Acquisitions and Divestitures [Abstract]
Revenue	$ 13,963	$ 22,178
Net (loss) income before non-controlling interests	(6,825)	(3,627)
Net loss attributable to non-controlling interests	413	636
Net (loss) income attributable to controlling interests	$ (6,412)	$ (2,991)
Net (loss) income per share (basic)	$ (1.17)	$ (0.56)
Net (loss) income per share (diluted)	$ (1.17)	$ (0.56)

Acquisitions and Divestitures42

Acquisitions and Divestitures (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Oct. 03, 2016
Acquisitions and Divestitures (Textual)
Transaction and due diligence costs	$ 501,000
Properties acquired	2,400,000
Cash transferred	$ 8,117,000
Purchase Agreement [Member]
Acquisitions and Divestitures (Textual)
Purchase price of acquired assets				$ 9,000,000
Nytis LLC [Member]
Acquisitions and Divestitures (Textual)
Cash transferred			$ 12,400,000
Additional cash		$ 42,000

Property and Equipment (Details

Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Oil and gas properties:
Accumulated depreciation, depletion, amortization and impairment	$ (78,559)	$ (72,421)
Net oil and gas properties	35,211	28,226
Furniture and fixtures, computer hardware and software, and other equipment	990	825
Accumulated depreciation and amortization	(665)	(587)
Net other property and equipment	325	238
Total net property and equipment	35,536	28,464
Proved oil and gas properties [Member]
Oil and gas properties:
Oil and gas properties, gross	111,771	97,453
Unproved properties not subject to depletion [Member]
Oil and gas properties:
Oil and gas properties, gross	$ 1,999	$ 3,194

Property and Equipment (Detai44

Property and Equipment (Details 1) - Unproved properties not subject to depletion [Member] - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Oil and gas properties, gross	$ 1,999	$ 3,194
Indiana [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Oil and gas properties, gross	431	433
Illinois [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Oil and gas properties, gross	298	309
Kentucky [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Oil and gas properties, gross	750	1,523
Ohio [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Oil and gas properties, gross	66	66
West Virginia [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Oil and gas properties, gross	$ 454	$ 863

Property and Equipment (Detai45

Property and Equipment (Details Textual)	12 Months Ended
	Dec. 31, 2016USD ($)Per_Mcfe	Dec. 31, 2015USD ($)Per_Mcfe
Property and Equipment (Textual)
Proved property	$ 1,300,000	$ 189,000
Capitalized overhead	562,000	576,000
Depletion expense related to oil and gas properties	$ 1,800,000	$ 2,500,000
Depletion expense related to oil and gas properties (in dollars per Mcfe) | Per_Mcfe	0.56	0.93
Depreciation and amortization expense	$ 114,000	$ 140,000
Unproved properties not subject to depletion [Member]
Property and Equipment (Textual)
Depletion expense related to oil and gas properties	$ 2,000,000	$ 3,200,000

Equity and Cost Method Invest46

Equity and Cost Method Investment (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Equity and Cost 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	$ (17,000)	$ 16,000
Received cash distributions	340,000
Cost method investment	65,000
Investment Income, Net	$ 65,000

Bank Credit Facility (Details)

Bank Credit Facility (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Mar. 30, 2017	Oct. 03, 2016
Bank Credit Facility (Textual)
Additional borrowing capacity available	$ 800,000
Effective borrowing rate (as a percent)	5.40%
Outstanding borrowings	$ 16,200,000
Line of Credit [Member]
Bank Credit Facility (Textual)
Line of credit facility maximum borrowing capacity			$ 100,000,000
Variable interest rate basis	(i) the base rate plus an applicable margin between 0.50% and 1.50% or (ii) the Adjusted LIBOR rate plus an applicable margin between 3.50% and 4.50% at Carbon's option. The actual margin percentage is dependent on the credit facility utilization percentage. Carbon is obligated to pay certain fees and expenses in connection with the credit facility, including a commitment fee for any unused amounts of 0.50% and an origination fee of 0.75%.
Initial borrowing			17,000,000
Letters of credit			$ 500,000
Line of Credit [Member] | Minimum [Member]
Bank Credit Facility (Textual)
Funded debt ratio required to be maintained	1
Current ratio required to be maintained	1
Line of Credit [Member] | Maximum [Member]
Bank Credit Facility (Textual)
Funded debt ratio required to be maintained	3.5
Current ratio required to be maintained	1
Line of Credit [Member] | LIBOR [Member] | Minimum [Member]
Bank Credit Facility (Textual)
LIBOR rate percentage	3.50%
Line of Credit [Member] | LIBOR [Member] | Maximum [Member]
Bank Credit Facility (Textual)
LIBOR rate percentage	4.50%
Subsequent Event [Member] | Minimum [Member]
Bank Credit Facility (Textual)
Line of credit facility maximum borrowing capacity		$ 17,000,000
Subsequent Event [Member] | Maximum [Member]
Bank Credit Facility (Textual)
Line of credit facility maximum borrowing capacity		23,000,000
Subsequent Event [Member] | Line of Credit [Member]
Bank Credit Facility (Textual)
Line of credit facility maximum borrowing capacity		$ 23,000,000

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Summary of provision for income taxes
Current income tax expense
Deferred income tax (benefit) expense	(4,472)	(3,733)
Change in valuation allowance	4,472	3,773
Total income tax expense

Income Taxes (Details 1)

Income Taxes (Details 1)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Summary of effective income tax rate differed from the statutory U.S. federal income tax rate
Federal income tax rate	35.00%	35.00%
State income taxes, net of federal benefit	3.50%	3.50%
Percentage depletion in excess of basis	1.10%	1.30%
Non-controlling interest in consolidated partnerships	(0.40%)	(0.40%)
True-up of prior year depletion in excess of basis	0.20%	0.20%
Stock-based compensation deficiency	(2.90%)	(1.80%)
Rate changes of prior year deferreds	(1.60%)	4.20%
Increase in valuation allowance and other	(34.90%)	(42.00%)
Total income tax expense

Income Taxes (Details 2)

Income Taxes (Details 2) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Deferred tax assets
Net operating loss carryforwards	$ 8,274	$ 5,433
Depletion carryforwards	2,740	2,570
Accrual and other	1,694	1,318
Derivatives	730	(213)
Asset retirement obligations	1,936	1,168
Property, plant and equipment	6,439	7,185
Total deferred tax assets	21,813	17,461
Deferred tax liability
Interest in partnerships	(762)	(757)
Less valuation allowance	(21,051)	(16,704)
Net deferred tax asset

Income Taxes (Details Textual)

Income Taxes (Details Textual) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Income Taxes (Textual)
Net operating losses	$ 19.7
Federal operating carryforwards expire, description	Beginning in 2031 through 2036.
Net operating losses carryforward	$ 34.4
NOL carryforwards expire, description	Beginning in 2023 through 2036 depending on each jurisdiction's specific law surrounding NOL carryforwards.

Stockholders' Equity (Details)

Stockholders' Equity (Details) - Restricted Stock [Member] - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Stockholders' Equity [Line Items]
Restricted stock awards/Restricted performance units, nonvested, Beginning Balance, Number of Shares	199,000	176,167
Granted, Number of Shares	134,501	87,000
Vested, Number of Shares	(64,668)	(64,167)
Forfeited, Number of Shares	(1,083)
Restricted stock awards/Restricted performance units, nonvested, Ending Balance, Number of Shares	267,750	199,000
Restricted stock awards, nonvested, Beginning Balance, Weighted Avg Grant Date Fair Value	$ 10.37	$ 12.26
Granted, Weighted Avg Grant Date Fair Value	5.40	8
Vested, Weighted Avg Grant Date Fair Value	10.84	12.33
Forfeited, Weighted Avg Grant Date Fair Value	6.20
Restricted stock awards, nonvested, Ending Balance, Weighted Avg Grant Date Fair Value	$ 7.78	$ 10.37

Stockholders' Equity (Details 1

Stockholders' Equity (Details 1) - Restricted Performance Units [Member] - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Stockholders' Equity [Line Items]
Restricted stock awards/Restricted performance units, nonvested, Beginning Balance, Number of Shares	314,311	234,311
Granted, Number of Shares	80,000	80,000
Vested, Number of Shares	(84,480)
Forfeited, Number of Shares	(13,520)
Restricted stock awards/Restricted performance units, nonvested, Ending Balance, Number of Shares	296,311	314,311

Stockholders' Equity (Details T

Stockholders' Equity (Details Textual) - USD ($)	Mar. 15, 2017	Jun. 30, 2013	Dec. 31, 2016	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			5,482,673	5,382,796
Common stock, shares outstanding			5,482,673	5,382,796
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
Compensation costs for restricted stock grants			$ 335,000	$ 335,000
Grant date fair value			$ 5.40	$ 8	$ 11.80	$ 12.80
Subsequent Events [Member]
Stockholders' Equity (Textual)
Reverse stock split, description	Reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued.
Restricted Stock Units (RSUs) [Member]
Stockholders' Equity (Textual)
Compensation costs for restricted stock grants			$ 742,000	$ 762,000
Expected period of recognition of unrecognized compensation costs			6 years 3 months 18 days
Restricted Stock [Member]
Stockholders' Equity (Textual)
Unrecognized compensation cost			$ 1,200,000
Restricted stock awards vest peroid			3 years
Restricted Performance Units [Member]
Stockholders' Equity (Textual)
Unrecognized compensation cost			$ 2,500,000	2,500,000	$ 2,500,000	$ 2,500,000
Compensation costs for restricted stock grants			127,000	$ 346,000
Compensation cost recognized			$ 1,200,000
Number of shares of unvested restricted stock granted			80,000	80,000
Grant date fair value			$ 10.80
Expected volatility rate			92.92%
Risk free interest rate			0.39%
Expected term			2 years 10 months 13 days
Equity Plans Prior to Merger [Member] | Warrant [Member]
Stockholders' Equity (Textual)
Number of shares outstanding			12,500
Number of shares exercisable			12,500
Equity Plans Prior to Merger [Member] | Restricted Stock Units (RSUs) [Member]
Stockholders' Equity (Textual)
Number of shares outstanding			24,000
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.
Vesting, percentage		25.00%
Nytis USA Restricted Stock Plan [Member] | Restricted Stock Units (RSUs) [Member]
Stockholders' Equity (Textual)
Number of shares of unvested restricted stock granted			24,000
Carbon Stock Incentive Plans [Member] | Officer [Member]
Stockholders' Equity (Textual)
Stock incentive plan, common stock shares authorized			1,100,000
Nytis USA [Member] | Warrant [Member]
Stockholders' Equity (Textual)
Number of shares outstanding			12,500
Number of shares exercisable			12,500
Exercise price			$ 20
Expiration date			Aug. 31, 2017

Accounts Payable and Accrued 55

Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Accounts Payable and Accrued Liabilities [Abstract]
Accounts payable	$ 2,315	$ 577
Oil and gas revenue payable to oil and gas property owners	1,415	862
Gathering and transportation payables	468	359
Production taxes payable	113	59
Drilling advances received from joint venture partner	955	2,115
Accrued drilling costs	4	112
Accrued lease operating costs	282	76
Accrued ad valorem taxes	1,552	496
Accrued general and administrative expenses	1,572	833
Accrued income taxes payable
Accrued interest	184	3
Other liabilities	261	129
Total accounts payable and accrued liabilities	$ 9,121	$ 5,621

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Liabilities:
Commodity derivatives	$ 1,932
Assets:
Commodity derivatives		$ 559
Recurring basis [Member] | Level 1 [Member]
Liabilities:
Commodity derivatives
Assets:
Commodity derivatives
Recurring basis [Member] | Level 2 [Member]
Liabilities:
Commodity derivatives	1,932
Assets:
Commodity derivatives		559
Recurring basis [Member] | Level 3 [Member]
Liabilities:
Commodity derivatives
Assets:
Commodity derivatives

Fair Value Measurements (Deta57

Fair Value Measurements (Details Textual) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Fair Value Measurements (Textual)
Asset retirement obligation	$ 1,800,000	$ 4,000

Physical Delivery Contracts a58

Physical Delivery Contracts and Commodity Derivatives (Details)	Dec. 31, 2016USD_MMBtuUSD_Bbl$ / shares
2017 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	3,360,000
Weighted Average Price	$ 3.30	[1]
2017 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl	60,000
Weighted Average Price	$ 52.98	[2]
2018 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	3,120,000
Weighted Average Price	$ 3.01	[1]
2018 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl	48,000
Weighted Average Price	$ 54.11	[2]
2019 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	1,320,000
Weighted Average Price	$ 2.85	[1]
2019 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl	36,000
Weighted Average Price	$ 54.90	[2]
[1]	NYMEX Henry Hub Natural Gas futures contract for the respective period.
[2]	NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective period.

Physical Delivery Contracts a59

Physical Delivery Contracts and Commodity Derivatives (Details 1) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Commodity derivative contracts:
Current assets		$ 408
Non-current assets		151
Current liabilities	1,341
Non-current liabilities	$ 591

Physical Delivery Contracts a60

Physical Delivery Contracts and Commodity Derivatives (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Commodity derivative contracts:
Unrealized losses	$ (2,490)	$ (763)
Commodity derivative contracts [Member]
Commodity derivative contracts:
Settlement gains	231	1,615
Unrealized losses	(2,490)	(763)
Total settlement and unrealized (losses) gains, net	$ (2,259)	$ 852

Physical Delivery Contracts a61

Physical Delivery Contracts and Commodity Derivatives (Details 3) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Commodity derivative assets:
Current assets		$ 408
Other long-term assets		151
Total derivative assets		559
Commodity derivative liabilities:
Current liability	1,341
Non-current liabilities	591
Total derivative liabilities	1,932
Gross Recognized Assets/Liabilities [Member]
Commodity derivative assets:
Current assets
Other long-term assets	249
Total derivative assets	249
Commodity derivative liabilities:
Current liability	1,341
Non-current liabilities	840
Total derivative liabilities	2,181
Gross Amounts Offset [Member]
Commodity derivative assets:
Current assets
Other long-term assets	(249)
Total derivative assets	(249)
Commodity derivative liabilities:
Current liability
Non-current liabilities	(249)
Total derivative liabilities	(249)
Net Recognized Fair Value Assets/Liabilities [Member]
Commodity derivative assets:
Current assets
Other long-term assets
Total derivative assets
Commodity derivative liabilities:
Current liability	1,341
Non-current liabilities	591
Total derivative liabilities	$ 1,932

Commitments and Contingencies62

Commitments and Contingencies (Details)	12 Months Ended
	Dec. 31, 2016Per_McfePartnership
Jan 2017 - Apr 2018 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Partnership	5,530
Jan 2017 - Apr 2018 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand charges (in dollars per dekatherm)	0.20
Jan 2017 - Apr 2018 [Member] | Maximum [Member]
Other Commitments [Line Items]
Demand charges (in dollars per dekatherm)	0.65
May 2018 - Mar 2020 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Partnership	3,230
May 2018 - Mar 2020 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand charges (in dollars per dekatherm)	0.20
May 2018 - Mar 2020 [Member] | Maximum [Member]
Other Commitments [Line Items]
Demand charges (in dollars per dekatherm)	0.62
Apr 2020 - 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 and Contingencies63

Commitments and Contingencies (Details Textual)	12 Months Ended
	Dec. 31, 2016USD ($)ft²	Dec. 31, 2015USD ($)
Commitments and Contingencies (Textual)
Liability related to firm transportation contracts assumed	$ 822,000
Operating lease expiration date	Dec. 31, 2019
Rental expenses	$ 220,000	$ 236,000
Minimum lease payments 2017	260,000
Minimum lease payments 2018	263,000
Minimum lease payments 2019	$ 263,000
Colorado [Member]
Commitments and Contingencies (Textual)
Office space | ft²	5,500
Kentucky [Member]
Commitments and Contingencies (Textual)
Office space | ft²	5,300

Retirement Savings Plan (Detail

Retirement Savings Plan (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Retirement Savings Plan [Abstract]
Matching percentage under retirement savings plan	6.00%
401(K) contributions and related administrative expenses	$ 99,000	$ 277,000

Supplemental Cash Flow Disclo65

Supplemental Cash Flow Disclosure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Cash paid during the period for:
Interest payments	$ 156	$ 166
Income taxes		325
Non-cash transactions:
Increase in net asset retirement obligations	1,849	4
Increase (decrease) in accounts payable and accrued liabilities included in oil and gas properties	1,099	(215)
Obligations assumed with acquisitions	$ 2,694

Subsequent Events (Details)

Subsequent Events (Details) - USD ($)	Mar. 15, 2017	Feb. 15, 2017	Mar. 30, 2017	Dec. 31, 2016
Subsequent Events [Member]
Subsequent Event [Line Items]
Reverse stock split, description	Reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued.
Interest of acquisition		17.813%
Acquisitions reimbursed cost		$ 500,000
Subsequent events, description		(i) issued and sold Class A Units to two institutional investors for an aggregate cash consideration of $22 million, (ii) entered into a Note Purchase Agreement (the "Note Purchase Agreement") with two institutional investors for the issuance and sale of up to $25 million of Senior Secured Revolving Notes (the "Senior Revolving Notes") due February 15, 2022 and (iii) entered into a Securities Purchase Agreement (the "Securities Purchase Agreement") with one institutional investor for the issuance and sale of $10 million of Senior Subordinated Notes (the "Subordinated Notes") due February 15, 2024. The closing of the Note Purchase Agreement and the Securities Purchase Agreement on February 15, 2017, resulted in the sale and issuance by Carbon California LLC of (xi) Senior Revolving notes in the principal amount of $10 million and (xii) Subordinated Notes in the original principal amount of $10 million.
Current borrowing amount		$ 15,000,000
Warrant exercise price		$ 7.20
Exercisable warrant of company's common stock		1,527,778
Acquisitions reimbursed cost				$ 501,000
Maximum [Member] | Subsequent Events [Member]
Subsequent Event [Line Items]
Line of credit facility maximum borrowing capacity			$ 23,000,000
Minimum [Member] | Subsequent Events [Member]
Subsequent Event [Line Items]
Line of credit facility maximum borrowing capacity			$ 17,000,000

Supplemental Financial Data -67

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details)	12 Months Ended
	Dec. 31, 2016MMcfMMBbls	Dec. 31, 2015MMcfMMBbls
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year	33,546	42,066
Revisions of previous estimates	2,867	(5,780)
Extensions and discoveries		186
Production	(3,297)	(2,646)
Purchases of reserves in-place	46,441	138
Sales of reserves in-place		(418)
Proved reserves, end of year	79,557	33,546
Proved developed reserves at:
End of Year	79,371	33,282
Proved undeveloped reserves at:
End of Year	186	264
Oil [Member]
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year | MMBbls	598	853
Revisions of previous estimates | MMBbls	110	(185)
Extensions and discoveries | MMBbls		31
Production | MMBbls	(79)	(101)
Purchases of reserves in-place | MMBbls	253
Sales of reserves in-place | MMBbls
Proved reserves, end of year | MMBbls	882	598
Proved developed reserves at:
End of Year | MMBbls	851	554
Proved undeveloped reserves at:
End of Year | MMBbls	31	44
Natural Gas [Member]
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year	29,958	36,948
Revisions of previous estimates	2,207	(4,670)
Extensions and discoveries
Production	(2,823)	(2,040)
Purchases of reserves in-place	44,923	138
Sales of reserves in-place		(418)
Proved reserves, end of year	74,265	29,958
Proved developed reserves at:
End of Year	74,265	29,958
Proved undeveloped reserves at:
End of Year

Supplemental Financial Data -68

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 1) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Oil and gas properties
Proved oil and gas properties	$ 112,579	$ 97,453
Unproved properties not subject to depletion	1,999	3,194
Accumulated depreciation, depletion, amortization and impairment	(78,596)	(72,421)
Net oil and gas properties	$ 35,982	$ 28,226

Supplemental Financial Data -69

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Property acquisition costs:
Unevaluated properties	$ 97	$ 341
Proved properties and gathering facilities	8,117
Development costs	360	2,106
Gathering facilities	42	578
Asset retirement obligation	1,849	4
Total costs incurred	$ 10,465	$ 3,029

Supplemental Financial Data -70

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Summary of company's investment in unproved properties
Acquisition costs	$ 97	$ 341	$ 1,561

Supplemental Financial Data -71

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 4) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)MMcf	Dec. 31, 2015USD ($)MMcf
Summary of results of operations from oil and gas producing activities
Oil and gas sales, including commodity derivative gains and losses	$ 8,184	$ 11,560
Expenses:
Production expenses	5,640	5,507
Depletion expense	1,839	2,466
Accretion of asset retirement obligations	176	123
Impairment of oil and gas properties	4,299	5,419
Total expenses	11,954	13,515
Results of operations from oil and gas producing activities	$ (3,770)	$ (1,955)
Depletion rate per Mcfe | MMcf	0.56	0.93

Supplemental Financial Data -72

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 5) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Summary of estimate of the current market value of the Company's proved reserves
Future cash inflows	$ 214,658	$ 102,741
Future production costs	(103,252)	(47,117)
Future development costs	(315)	(420)
Future income taxes	(14,858)
Future net cash flows	96,233	55,204
10% annual discount	(51,522)	(30,172)
Standardized measure of discounted future net cash flows	$ 44,711	$ 25,032	$ 65,006

Supplemental Financial Data -73

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 6) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Summary of discounted future cash flows relating to proved oil and gas reserves
Standardized measure of discounted future net cash flows, beginning of year	$ 25,032	$ 65,006
Sales of oil and gas, net of production costs and taxes	(4,804)	(5,283)
Price revisions	(786)	(37,490)
Extensions, discoveries and improved recovery, less related costs		384
Changes in estimated future development costs	248	3,290
Development costs incurred during the period	102
Quantity revisions	2,091	(4,282)
Accretion of discount	2,503	6,702
Net changes in future income taxes	(4,633)	2,010
Purchases of reserves-in-place	26,776	115
Sales of reserves-in-place		(380)
Changes in production rate timing and other	(1,818)	(5,040)
Standardized measure of discounted future net cash flows, end of year	$ 44,711	$ 25,032

Supplemental Financial Data -74

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 7)	12 Months Ended
	Dec. 31, 2016Per_McfeUSD_Bbl	Dec. 31, 2015Per_McfeUSD_Bbl
Oil (per Bbl) [Member]
Summary of weighted averaged adjusted prices
Weighted averaged adjusted prices | USD_Bbl	40.40	46.12
Natural Gas (per Mcf) [Member]
Summary of weighted averaged adjusted prices
Weighted averaged adjusted prices | Per_Mcfe	2.41	2.50

Supplemental Financial Data -75

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details Textual)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Textual)
Estimated proved reserves	3.1 Bcfe	3.0 Bcfe
Discount rate, description	All cash flow amounts, including income taxes, are discounted at 10%.