Carbon Energy (CRBO) 10-K 2 Apr 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Mar. 23, 2018	Jun. 30, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	Carbon Natural Gas Co
Entity Central Index Key	86,264
Trading Symbol	CRBO
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
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			$ 10
Entity Common Stock, Shares Outstanding		7,533,411

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 1,650	$ 858
Accounts receivable:
Revenue	2,206	2,369
Joint interest billings and other	1,151	2,251
Due from related parties	2,075
Commodity derivative asset	215
Prepaid expense, deposits, and other current assets	783	305
Total current assets	8,080	5,783
Oil and gas properties, full cost method of accounting:
Proved, net	34,178	33,212
Unproved	1,947	1,999
Other property and equipment, net	737	325
Total property and equipment, net	36,862	35,536
Investments in affiliates (Note 6)	14,267	668
Other long-term assets	800	725
Total assets	60,009	42,712
Current liabilities:
Accounts payable and accrued liabilities (Note 10)	11,218	9,121
Firm transportation contract obligations (Note 1)	127	561
Commodity derivative liability		1,341
Total current liabilities	11,345	11,023
Non-current liabilities:
Firm transportation contract obligations (Note 1)	134	261
Commodity derivative liability		591
Production and property taxes payable	520	628
Warrant liability	2,017
Asset retirement obligations (Note 3)	7,357	5,120
Credit facility (Note 7)	22,140	16,230
Total non-current liabilities	32,168	22,716
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, 2017 and 2016
Common stock, $0.01 par value; authorized 10,000,000 shares, 6,005,633 and 5,482,673 shares issued and outstanding at December 31, 2017 and 2016, respectively	60	1,096
Additional paid-in capital	58,813	56,548
Accumulated deficit	(44,218)	(50,536)
Total Carbon stockholders' equity	14,655	7,108
Non-controlling interests	1,841	1,865
Total stockholders' equity	16,496	8,973
Total liabilities and stockholders' equity	$ 60,009	$ 42,712

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
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	10,000,000	10,000,000
Common stock, shares issued	6,005,633	5,482,673
Common stock, shares outstanding	6,005,633	5,482,673

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Revenue:
Natural gas sales	$ 15,298	$ 7,127
Oil sales	4,213	3,316
Commodity derivative gain (loss)	2,928	(2,259)
Other income	34	11
Total revenue	22,473	8,195
Expenses:
Lease operating expenses	6,141	3,175
Transportation and gathering costs	2,172	1,645
Production and property taxes	1,276	820
General and administrative	9,528	8,645
General and administrative-related party reimbursement	(2,703)
Depreciation, depletion, and amortization	2,544	1,953
Accretion of asset retirement obligations	307	176
Impairment of oil and gas properties		4,299
Total expenses	19,265	20,713
Operating income (loss)	3,208	(12,518)
Other income and (expense):
Interest expense	(1,202)	(367)
Warrant derivative gain	3,133
Investment in affiliates	1,158	49
Other	28	17
Total other income and (expense)	3,117	(301)
Income (loss) before income taxes	6,325	(12,819)
Provision for income taxes	(74)
Net income (loss) before non-controlling interest	6,399	(12,819)
Net income (loss) attributable to non-controlling interests	81	(413)
Net income (loss) attributable to controlling interest	$ 6,318	$ (12,406)
Net income (loss) per common share:
Basic	$ 1.12	$ (2.27)
Diluted	$ 0.49	$ (2.27)
Weighted average common shares outstanding (in thousands):
Basic	5,662	5,468
Diluted	6,452	5,468

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
Balances at Dec. 31, 2015	$ 19,640	$ 36	$ 55,434	$ 2,299	$ (38,130)
Balances, 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 and performance units exchanged for tax withholding	(267)	$ (11)	(256)
Restricted stock and performance units exchanged for tax withholding, shares		(50)
Non-controlling interests distributions, net	(14)			(14)
Non-controlling interest purchase	(7)			(7)
Net income (loss)	(12,819)			(413)	(12,406)
Balances at Dec. 31, 2016	8,973	$ 55	57,588	1,865	(50,536)
Balances, shares at Dec. 31, 2016		5,482
Stock-based compensation	1,106		1,106
Restricted stock vested		$ 1	(1)
Restricted stock vested, shares		67
Performance units vested		$ 1	(1)
Performance units vested, shares		80
Restricted stock and performance units exchanged for tax withholding	(399)	$ (1)	(398)
Restricted stock and performance units exchanged for tax withholding, shares		(55)
Shares issued for exercise of warrant (Note 6)	2,791	$ 4	2,787
Shares issued for exercise of warrant (Note 6), shares		432
Warrant derivative extinguishment	2,049		2,049
Class B Fair Value (Note 6)	(4,317)		(4,317)
Non-controlling interests distributions, net	(105)			(105)
Net income (loss)	6,399			81	6,318
Balances at Dec. 31, 2017	$ 16,496	$ 60	$ 58,813	$ 1,841	$ (44,218)
Balances, shares at Dec. 31, 2017		6,006

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities:
Net income (loss)	$ 6,399	$ (12,819)
Items not involving cash:
Depreciation, depletion, and amortization	2,544	1,953
Accretion of asset retirement obligations	307	176
Impairment of oil and gas properties		4,299
Unrealized commodity derivative (gain) loss	(2,158)	2,490
Warrant derivative gain	(3,133)
Stock-based compensation expense	1,106	2,440
Investment in affiliates gain	(1,128)	17
Amortization of debt issuance costs	176
Other	(109)	(47)
Net change in:
Accounts receivable	(812)	(2,925)
Prepaid expenses, deposits and other current assets	(477)	(93)
Accounts payable, accrued liabilities and firm transportation contracts	1,205	1,367
Net cash provided by (used in) operating activities	3,920	(3,142)
Cash flows from investing activities:
Development and acquisition of properties and equipment	(1,591)	(700)
Acquisition of oil and gas properties		(8,117)
Proceeds from sale of oil and gas properties and other assets	16	8
Other long-term assets	(161)	(285)
Investment in affiliates	(6,797)	340
Net cash used in investing activities	(8,533)	(8,754)
Cash flows from financing activities:
Vested restricted stock exchanged for tax withholding	(399)	(267)
Proceeds from credit facility	7,210	16,937
Payments on credit facility	(1,300)	(4,207)
Distribution to non-controlling interests	(106)	(14)
Net cash provided by financing activities	5,405	12,449
Net increase in cash and cash equivalents	792	553
Cash and cash equivalents, beginning of period	858	305
Cash and cash equivalents, end of period	$ 1,650	$ 858

Organization

Organization	12 Months Ended
	Dec. 31, 2017
Organization [Abstract]
Organization	Note 1 – Organization Carbon Natural Gas Company’s and its subsidiaries’ (referred to herein as “we”, “us”, or “Carbon”) business is comprised of the assets and properties of us and our subsidiaries as well as our equity investments in Carbon Appalachian Company, LLC (“Carbon Appalachia”) and Carbon California Company, LLC (“Carbon California”). Appalachian and Illinois Basin Operations In the Appalachian and Illinois Basins, Nytis Exploration Company, LLC (“Nytis LLC”) conducts operations for us and Carbon Appalachia. The following illustrates this relationship as of December 31, 2017. Ventura Basin Operations In California, Carbon California Operating Company, LLC (“CCOC”), conducts Carbon California’s operations. The following illustrates this relationship as of December 31, 2017. On February 1, 2018, Yorktown exercised the California Warrant, resulting in our aggregate sharing percentage in Carbon California increasing from 17.81% to 56.40%. See Note 17. Collectively, references to us include CCOC, Nytis Exploration (USA) Inc. (“Nytis USA”) and Nytis LLC.

Reverse Stock Split

Reverse Stock Split	12 Months Ended
	Dec. 31, 2017
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 our 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. In connection with the reverse stock split, the number of authorized shares of our common stock was decreased from 200,000,000 to 10,000,000.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Summary of Significant Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 3 – Summary of Significant Accounting Policies Accounting policies used by us reflect industry practices and conform to accounting principles generally accepted in the United States of America (“GAAP”). The more significant of such accounting policies are briefly discussed below. Principles of Consolidation The consolidated financial statements include the accounts of us and our consolidated subsidiaries. We own 100% of Nytis USA. Nytis USA owns approximately 99 % of Nytis LLC. Nytis LLC holds interests in various oil and gas partnerships. For partnerships where we have a controlling interest, the partnerships are consolidated. We are currently consolidating 46 partnerships, and we reflect the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on our 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 our consolidated balance sheets. All significant intercompany accounts and transactions have been eliminated. In accordance with established practice in the oil and gas industry, our consolidated financial statements also include our pro-rata share of assets, liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which we have 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 we have the ability to significantly influence the operating decisions of the investee. When we do 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 We grant credit to all qualified customers, which potentially subjects us to credit risk resulting from, among other factors, adverse changes in the industries in which we operate and the financial condition of our customers. We continuously monitor collections and payments from our customers and maintains an allowance for doubtful accounts based upon our historical experience and any specific customer collection issues that it has identified. At December 31, 2017 and 2016, we had not identified any collection issues related to our oil and gas operations and consequently no allowance for doubtful accounts was provided for on those dates. In addition, as of December 31, 2016, accounts receivable included a deposit of $1.7 million made by us on the purchase of assets in the Ventura Basin of California through Carbon California. The deposit was reimbursed to us upon the consummation of the acquisition by Carbon California on February 15, 2017. See Note 4 for additional information. Revenue Our accounts receivable - Revenue is comprised of oil and natural gas revenues from producing activities. Joint Interest Billings and Other Our accounts receivable – joint interest billings and other is comprised of receivables due from other exploration and production companies and individuals who own working interests in the properties that we operate. For receivables from joint interest owners, we typically have the ability to withhold future revenues disbursements to recover any non-payment of joint-interest billings. 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. As of December 31, 2017, there was an imbalance due to us in the amount of approximately $193,000. Due from Related party Our receivables – due from related party are comprised of receivables from Carbon California and Carbon Appalachia in our role as manager and operator of these entities. See Note 16. Prepaid Expense, Deposits, and Other Current Assets Our prepaid expense, deposit, and other current asset account is comprised of prepaid insurance, the current portion of unamortized Credit Facilities issuance costs and deposits. Oil and Natural Gas Sales We sell our 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, 2017 and 2016. There are several purchasers in the areas where we sell our production. We do not believe that changing our primary purchasers or a loss of any other single purchaser would materially impact our business. For the years ended Purchaser 2017 2016 Purchaser A 23 % 4 % Purchaser B 17 % 15 % Purchaser C 12 % 18 % Purchaser D 11 % 16 % Purchaser E 8 % 17 % We recognize 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 we deliver more natural gas than we nominated to deliver to the purchaser and the purchaser pays only for the nominated amount. Conversely, a purchaser imbalance liability occurs when we deliver less natural gas than we nominated to deliver to the purchaser and the purchaser pays for the amount nominated. As of December 31, 2017 and 2016, we had a purchaser imbalance receivable of $193,000 within trade receivables and purchaser imbalance payable of approximately $25,000 within accounts payable and accrued expenses, respectively, which are recognized as a current asset and current liability, respectively, in our consolidated balance sheets. Purchaser A comprises of approximately 23% of total accounts receivable as of December 31, 2017. Accounting for Oil and Gas Operations We use 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 us for our 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. We assess our 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. 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. We perform a ceiling test quarterly. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value-based measurement, rather it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using the un-weighted arithmetic average of the first-day-of-the month price for the previous twelve month period, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down 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 year ended December 31, 2017, we did not recognize a ceiling test impairment as our full cost pool did not exceed the ceiling limitations. For the year ended December 31, 2016, we recognized a ceiling test impairment of approximately $4.3 million as our full cost pool exceeded its ceiling limitations. Future declines in oil and natural gas prices, increases in future operating expenses and future development costs could result in impairments of our oil and gas properties in future periods. Impairment changes are a non-cash charge and accordingly would not affect cash flows but would adversely affect our net income and shareholders’ equity. We capitalize interest in accordance with Financial Accounting Standards Board (“FASB”) ASC 932-835-25, Extractive Activities-Oil and Gas, Interest. Therefore, interest is capitalized for any unusually significant investments in unproved properties or major development projects not currently being depleted. We capitalize the portion of general and administrative costs that is attributable to our acquisition, exploration and development activities. Other Property and Equipment Other property and equipment are recorded at cost upon acquisition and include office equipment, computer equipment, building, field equipment, vehicles, and software. Depreciation of other property and equipment is calculated over three to seven years using the straight-line method. Long-Lived Assets We review our 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. We look primarily to the estimated undiscounted future cash flows in our assessment of whether or not long-lived assets have been impaired. Other Long-Term Assets Our other long-term assets are comprised of bonds, the long-term portion of deferred debt issue and financing costs and the long-term portion of our commodity derivative liability. Investments in Affiliates Investments in non-consolidated affiliates are accounted for under either the cost or equity method of accounting, as appropriate. The cost method of accounting is generally used for investments in affiliates in which we have less than 20% of the voting interests of a corporate affiliate or less than a 3% to 5% interest of a partnership or limited liability company and do not have significant influence. Investments in non-consolidated affiliates, accounted for using the cost method of accounting, are recorded at cost and impairment assessments for each investment are made annually to determine if a decline in the fair value of the investment, other than temporary, has occurred. A permanent impairment is recognized if a decline in the fair value occurs. If we hold between 20% and 50% of the voting interest in non-consolidated corporate affiliates or generally greater than a 3% to 5% interest of a partnership or limited liability company and exert significant influence or control (e.g., through our influence with a seat on the board of directors or management of operations), the equity method of accounting is generally used to account for the investment. Investment in affiliates will increase or decrease by our share of the affiliates’ profits or losses and such profits or losses are recognized in our consolidated statements of operations. If we hold greater than 50% of voting shares, we will generally consolidate the entities under the voting interest model. For our investments in Carbon Appalachia and Carbon California, we use the hypothetical liquidation at book value (“HLBV”) method to recognize our share of profits or losses. We review equity method investments for impairment whenever events or changes in circumstances indicate that “an other than temporary” decline in value has occurred. Related Party Transactions Management Reimbursements In our role as manager of Carbon California and Carbon Appalachia, we receive management reimbursements. These reimbursements are included in general and administrative – related party reimbursement on our consolidated statement of operations. Operating Reimbursements In our role as operator of Carbon California and Carbon Appalachia, we receive reimbursements of operating expenses. These expenses are recorded directly to receivable – related party on our consolidated balance sheets and are therefore not included in our operating expenses on our consolidated statements of operations (see Note 16). Warrant Liability We issued warrants related to investments in Carbon California and Carbon Appalachia. We account for these warrants in accordance with guidance contained in Accounting Standards Codification (“ASC”) 815, Derivatives and Hedging Asset Retirement Obligations Our 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 (see Note 11). The following table is a reconciliation of the ARO for the years ended December 31, 2017 and 2016. Year Ended December 31, (in thousands) 2017 2016 Balance at beginning of year $ 5,120 $ 3,095 Accretion expense 307 176 Change in estimate of cash outflow 2,402 Additions during period - 1,849 Less: sale of wells (92 ) - 7,737 5,120 Less: ARO recognized as accounts payable and accrued liabilities (380 ) (114 ) Balance at end of year $ 7,357 $ 5,006 For the year ended December 31, 2017, we did not have any additions of ARO compared to $1.8 million in 2016, which was primarily due to the acquisition of producing oil and natural gas properties in the Appalachian Basin. During the year ended December 31, 2017, we increased the estimated cost of retirement obligations for certain wells in the Appalachian Basin. Our estimated costs range from $20,000 to $30,000, which is a better representation of current prices of supplies and services. This increase to estimated costs resulted in a $2.4 million increase to our ARO in 2017. Financial Instruments Our financial instruments include cash and cash equivalents, accounts receivables, accounts payables, accrued liabilities, commodity derivative instruments, warrant liability, and our credit facility. The carrying value of cash and cash equivalents, accounts receivable, accounts payables and accrued liabilities are representative of their fair value, due to the short maturity of these instruments. Our commodity derivative instruments are recorded at fair value, as discussed below and in Note 11. The carrying amount of our credit facility approximated fair value since borrowings bear interest at variable rates, which are representative of our credit adjusted borrowing rate. Commodity Derivative Instruments We enter into commodity derivative contracts to manage our exposure to oil and natural gas price volatility with an objective to reduce exposure to downward price fluctuations. Commodity derivative contracts may take the form of futures contracts, swaps, collars or options. We have elected not to designate our 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 We account 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 basis, 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. With the passage of the Tax Cut and Jobs Act (“TCJA”), we are required to remeasure deferred income taxes at the lower 21% corporate rate as of the date the TCJA was signed into law even though the reduced rate is effective January 1, 2018. We account 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). For performance units, since these awards are settled in cash at the end of a defined performance period, they are measured quarterly and expensed over the remaining 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 our net working revenue interest. Earnings Per Common Share Basic earnings per common share is computed by dividing the net income (loss) 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 our officers, directors and employees 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 us 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 income (loss) per share: For the Year Ended (in thousands except per share amounts) 2017 2016 Net income (loss) $ 6,318 $ (12,406 ) Less: warrant derivative gain (3,133 ) - Diluted net income 3,185 (12,406 ) Basic weighted-average common shares outstanding during the period 5,662 5,468 Add dilutive effects of warrants and non-vested shares of restricted stock 790 - Diluted weighted-average common shares outstanding during the period 6,452 5,468 Basic net (loss) income per common share $ 1.12 $ (2.27 ) Diluted net (loss) income per common share $ 0.49 $ (2.27 ) For the year ended December 31, 2017, we had net income and the diluted loss per common share calculation includes the anti-dilutive effects of approximately 519,000 warrants and approximately 271,000 non-vested shares of restricted stock. In addition, approximately 259,000 restricted performance units subject to future contingencies were excluded in the basic and diluted loss per share calculations. For the year ended December 31, 2016, we had a net loss and therefore the diluted loss per common share calculation excludes the anti-dilutive effects of approximately 13,000 warrants and approximately 268,000 non-vested shares of restricted stock. In addition, approximately 296,000 restricted performance units subject to future contingencies were excluded from the basic and diluted loss per share calculations. Oil and Gas Reserves Oil and gas reserves represent theoretical quantities of crude oil, natural gas, and natural gas liquids (“NGL”) which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our control. Accordingly, reserve estimates and the projected economic value of our and our equity investees’ properties will differ from the actual future quantities of oil and gas ultimately recovered and the corresponding value associated with the recovery of these reserves. Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with GAAP 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 warrants, fair value of equity method investments, fair value of assets acquired and liabilities assumed 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 January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805) In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows-Classification of Certain Cash Receipts and Cash Payments In February 2016, the FASB issued ASU 2016-02, Leases. In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2017
Acquisitions and Divestitures [Abstract]
Acquisitions and Divestitures	Note 4 – Acquisitions and Divestitures Acquisitions In October 2016, Nytis LLC completed the EXCO Acquisition consisting of producing natural gas wells and natural gas gathering facilities located in our Appalachian Basin operating area. The natural gas gathering facilities are primarily used to gather our 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 us with proved developed reserves, production and operating cash flow in locations where we have similar assets. The EXCO Acquisition qualified as a business combination and as such, we estimated the fair value of the assets acquired and liabilities assumed as of the Closing Date. We considered various factors in our 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. We 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 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 Below are consolidated results of operations for the year ended December 31, 2016 as though the EXCO Acquisition had been completed as of January 1, 2016. The EXCO Acquisition closed October 3, 2016, and accordingly, our consolidated statement of operations for the year ended December 31, 2017 includes the results of operations for the year ended December 31, 2017 of the EXCO properties acquired. Unaudited Pro Forma Consolidated Results For Year Ended December 31, (in thousands, except per share amounts) 2016 Revenue $ 13,963 Net income (loss) income before non-controlling interests (6,825 ) Net income (loss) attributable to non-controlling interests 413 Net income (loss) attributable to controlling interests $ (6,412 ) Net income (loss) per share (basic) $ (1.17 ) Net income (loss) per share (diluted) $ (1.17 )

Property and Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2017
Property and Equipment [Abstract]
Property and Equipment	Note 5 – Property and Equipment Net property and equipment at December 31, 2017 and 2016 consists of the following: (in thousands) As of December 31, 2017 2016 Oil and gas properties: Proved oil and gas properties $ 114,893 $ 111,771 Unproved properties not subject to depletion 1,947 1,999 Accumulated depreciation, depletion, amortization and impairment (80,715 ) (78,559 ) Net oil and gas properties 36,125 35,211 Furniture and fixtures, computer hardware and software, and other equipment 1,758 990 Accumulated depreciation and amortization (1,021 ) (665 ) Net other property and equipment 737 325 Total property and equipment, net $ 36,862 $ 35,536 We had approximately $1.9 million and $2.0 million, at December 31, 2017 and 2016, respectively, of unproved oil and gas properties not subject to depletion. At December 31, 2017 and 2016, our unproved properties consist principally of leasehold acquisition costs in the following areas: As of December 31, (in thousands) 2017 2016 Illinois Basin: Indiana $ 432 $ 431 Illinois 136 298 Appalachian Basin: Kentucky 915 750 Ohio 66 66 West Virginia 398 454 Total unproved properties not subject to depletion $ 1,947 $ 1,999 During the years ended December 31, 2017 and 2016, expiring leasehold costs reclassified into proved property were approximately $52,000 and $1.3 million, 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. We capitalized overhead applicable to acquisition, development and exploration activities of approximately $66,000 and $562,000 for the years ended December 31, 2017 and 2016, respectively. Depletion expense related to oil and gas properties for the years ended December 31, 2017 and 2016 was approximately $2.2 million and $1.8 million or $0.40 and $0.56 per Mcfe, respectively. Depreciation expense related to furniture and fixtures, computer hardware and software and other equipment for the years ended December 31, 2017 and 2016 was approximately $387,000 and $114,000, respectively.

Investments in Affiliates

Investments in Affiliates	12 Months Ended
	Dec. 31, 2017
Investments in Affiliates [Abstract]
Investments in Affiliates	Note 6 – Investments in Affiliates Carbon California Carbon California was formed in 2016 by us, entities managed by Yorktown and Prudential, to acquire producing assets in the Ventura Basin in California. On February 15, 2017, we, Yorktown and Prudential entered into a limited liability company agreement (the “Carbon California LLC Agreement”) of Carbon California, a Delaware limited liability company. Prior to February 1, 2018, we held 17.81% of the voting and profits interests, Yorktown held 38.59% of the voting and profits interests and Prudential held 43.59% of the voting and profits interests in Carbon California. On February 1, 2018, Yorktown exercised the California Warrant, pursuant to which Yorktown obtained additional shares of common stock in us in exchange for the transfer and assignment by Yorktown of all of its rights in Carbon California. Following the exercise of the California Warrant by Yorktown, we own 56.41% of the voting and profits interests, and Prudential holds the remainder of the interests, in Carbon California. Pursuant to the Carbon California LLC Agreement, we initially acquired a 17.81% interest in Carbon California represented by Class B Units. The Class B Units were acquired for no cash consideration. No further equity commitments have been made or are required by us under the Carbon California LLC Agreement, prior to February 1, 2018. On February 15, 2017, Carbon California (i) issued and sold Class A Units to Yorktown and Prudential for an aggregate cash consideration of $22.0 million, (ii) entered into a Note Purchase Agreement (the “Note Purchase Agreement”) with Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America for the issuance and sale of up to $25.0 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 Prudential for the issuance and sale of $10.0 million of Senior Subordinated Notes (the “Subordinated Notes”) due February 15, 2024. We are not a guarantor of the Senior Revolving Notes or the Subordinate Notes. 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 of (i) Senior Revolving Notes in the principal amount of $10.0 million and (ii) Subordinated Notes in the original principal amount of $10.0 million. The maximum principal amount available under the Senior Revolving Notes is based upon the borrowing base attributable to Carbon California’s proved oil and gas reserves which is to be determined at least semi-annually. The current borrowing base is $15.0 million, of which $11.0 million is outstanding as of December 31, 2017. 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, which acquisitions also closed on February 15, 2017. The remainder of the net proceeds may be used to fund field development projects and to fund future complementary acquisitions and for general working capital purposes of Carbon California. Based on our 17.8% interest in Carbon California, as of December 31, 2017, our ability to appoint a member to the board of directors and our role of manager of Carbon California, we are accounting for our investment in Carbon California under the equity method of accounting as we believe we can exert significant influence. We use the HLBV to determine our share of profits or losses in Carbon California and adjusts the carrying value of our investment accordingly. The HLBV is a balance-sheet approach that calculates the amount each member of Carbon California would receive if Carbon California were liquidated at book value at the end of each measurement period. The change in the allocated amount to each member during the period represents the income or loss allocated to that member. In the event of liquidation of Carbon California, to the extent that Carbon California has net income, available proceeds are first distributed to members holding Class A and Class B units and any remaining proceeds are then distributed to members holding Class A units. For the period February 15, 2017 (inception) through December 31, 2017, Carbon California incurred a net loss of which our share (as a holder of Class B units for that period) is zero. Should Carbon California generate net income in future periods, we will not record income (or losses) until our share of such income exceeds the amount of our share of losses not previously reported. While income may be recorded in future periods, the ability of Carbon California to make distributions to its owners, including us, is dependent upon the terms of its credit facilities, which currently prohibit distributions unless agreed to by the lender. In connection with our entry into the Carbon California LLC Agreement, and Carbon California engaging in the transactions described above, we received the aforementioned Class B Units and issued to Yorktown the California Warrant. The exercise price for the California Warrant is payable exclusively with Class A Units of Carbon California held by Yorktown and the number of shares of our common stock for which the California Warrant is exercisable is determined, as of the time of exercise, by dividing (a) the aggregate unreturned capital of Yorktown’s Class A Units of Carbon California by (b) the exercise price. The California Warrant had a term of seven years and included certain standard registration rights with respect to the shares of our common stock issuable upon exercise of the California Warrant. Yorktown exercised the California Warrant on February 1, 2018. The issuance of the Class B Units and the California Warrant were in contemplation of each other, and under non-monetary related party guidance, we accounted for the California Warrant, at issuance, based on the fair value of the California Warrant as of the date of grant (February 15, 2017) and recorded a warrant liability with an associated offset to APIC. Future changes to the fair value of the California Warrant are recognized in earnings. We accounted for the fair value of the Class B Units at their estimated fair value at the date of grant, which became our investment in Carbon California with an offsetting entry to APIC. As of the grant date of the California Warrant, we estimated that the fair market value of the California Warrant was approximately $5.8 million and the fair value of the Class B Units was approximately $1.9 million. As of December 31, 2017, we estimated that the fair value of the California Warrant was approximately $2.0 million. The difference in the fair value of the California Warrant from the grant date though December 31, 2017 was approximately $3.8 million and was recognized in warrant derivative gain in our consolidated statements of operations for the year ended December 31, 2017. As of December 31, 2017, Carbon California was in breach of the covenants for its Senior Revolving Notes and Subordinated Notes; however, it obtained a waiver for the December 31, 2017 and March 31, 2018 covenants. It is anticipated that covenants will be met in the future. See Liquidity and Management’s Plans The following table sets forth selected historical financial data for Carbon California. (in thousands) As of December 31, 2017 Current assets $ 3,968 Total oil and gas properties, net $ 43,458 Current liabilities $ 6,899 Non-current liabilities $ 23,279 Total members’ equity $ 18,549 (in thousands) February 15, 2017 (Inception) through December 31, 2017 Revenues $ 7,235 Operating expenses 9,893 Loss from operations (2,658 ) Net loss (6,552 ) Carbon Appalachia Carbon Appalachia was formed in 2016 by us, Yorktown and Old Ironsides to acquire producing assets in the Appalachian Basin in Kentucky, Tennessee, Virginia and West Virginia. Outlined below is a summary of i) our contributions, ii) our resulting percent of Class A unit ownership and iii) our overall resulting Sharing Percentage of Carbon Appalachia after giving effect of all classes of ownership. Holders of units within each class of units participate in profit or losses and distributions according to their proportionate share of each class of units (“Sharing Percentage”). Each contribution and its use is described in detail following the table. Timing Capital Contribution Resulting Class A Units (%) Resulting Sharing % April 2017 $0.24 million 2.00% 2.98% August 2017 $3.71 million 15.20% 16.04% September 2017 $2.92 million 18.55% 19.37% November 2017 Warrant exercise 26.50% 27.24% On April 3, 2017, we, Yorktown and Old Ironsides Energy, LLC (“ Old Ironsides Pursuant to the Carbon Appalachia LLC Agreement, we acquired a 2.0% interest in Carbon Appalachia for $240,000 of Class A Units associated with our initial equity commitment of $2.0 million. We also have the ability to earn up to an additional 14.7% of Carbon Appalachia distributions (represented by Class B Units) after certain return thresholds to the holders of Class A Units are met. The Class B Units were acquired for no cash consideration. In addition, we acquired a 1.0% interest represented by Class C Units which were obtained in connection with the contribution to Carbon Appalachia of a portion of its working interest in undeveloped properties in Tennessee. If Carbon Appalachia agrees to drill horizontal Chattanooga Shale wells on these properties, it will pay 100% of the cost of drilling and completion of the first 20 wells to earn a 75% working interest in such properties. We, through our subsidiary, Nytis LLC, will retain a 25% working interest in the properties. There was no activity associated with these properties in 2017. In connection with and concurrently with the closing of the acquisition described below, Carbon Appalachia Enterprises, LLC, formerly known as Carbon Tennessee Company, LLC (“Carbon Appalachia Enterprises”), a subsidiary of Carbon Appalachia, entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank with an initial borrowing base of $10.0 million. We are not a guarantor of this credit facility. Borrowings under the credit facility, along with the initial equity contributions made to Carbon Appalachia, were used to complete the acquisition of natural gas producing properties and related facilities located predominantly in Tennessee (the “CNX Acquisition”). The purchase price was $20.0 million, subject to normal and customary closing adjustments, and Carbon Appalachia Enterprises used $8.5 million drawn from the credit facility toward the purchase price. On August 15, 2017, Carbon Appalachia completed the acquisition of natural gas producing properties and related facilities located predominantly in the state of West Virginia (the “Enervest Acquisition”). The purchase price was $21.5 million, subject to normal and customary closing adjustments. On August 15, 2017, the Carbon Appalachia LLC Agreement was amended and restated. Pursuant to the amended and restated Carbon Appalachia LLC Agreement, we increased our capital commitment in Carbon Appalachia from $2.0 million to $23.6 million and our portion of any subsequent capital call from 2.0% to 26.5%. Aggregate capital commitments of all members remained at $100.0 million. As each subsequent capital call is made, Carbon will contribute 26.5%. We are the sole manager of Carbon Appalachia and maintain the ability to earn additional ownership interests of Carbon Appalachia (represented by Class B Units) after certain thresholds to the holders of Class A Units are met. We also maintain our 1.0% carried interest represented by Class C Units. In connection with and concurrently with the closing of the Enervest Acquisition, the borrowing base of its existing credit facility with LegacyTexas Bank increased to $22.0 million and Carbon Appalachia Enterprises borrowed $8.0 million from its existing credit facility with LegacyTexas Bank. Carbon Appalachia received equity funding in the amount of $14.0 million from its members, including $3.7 million from us. The contributed funds and funds drawn from the credit facility were used to pay the purchase price. On September 29, 2017, Carbon Appalachia Enterprises amended its 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank, resulting in a borrowing base of $50.0 million with redeterminations as of April 1 and October 1 each year and the addition of East West Bank as a participating lender. As of December 31, 2017, there was approximately $38.0 million outstanding under the credit facility. On September 29, 2017, Carbon Appalachia completed the acquisition of natural gas producing properties, natural gas gathering pipelines and related facilities located predominantly in the state of West Virginia (the “Cabot Acquisition”). The purchase price was $41.3 million, subject to normal and customary closing adjustments. In connection with and concurrently with the closing of the Cabot Acquisition described above, Carbon Appalachia Enterprises borrowed $20.4 million from its credit facility. Carbon Appalachia received equity funding in the amount of $11.0 million from its members, including $2.9 million from us. The contributed funds and funds drawn from the credit facility were used to pay the purchase price. On November 30, 2017, the CAE Credit Facility was amended to include the addition of Bank SNB as a participating lender. In connection with our entry into the Carbon Appalachia LLC Agreement, and Carbon Appalachia engaging in the transactions described above, we received the aforementioned Class B Units and issued to Yorktown the Appalachia Warrant. The Appalachia Warrant is payable exclusively with Class A Units of Carbon Appalachia held by Yorktown and the number of shares of our common stock for which the Appalachia Warrant is exercisable is determined, as of the time of exercise, by dividing (a) the aggregate unreturned capital of Yorktown’s Class A Units of Carbon Appalachia plus a required 10% internal rate of return by (b) the exercise price. On November 1, 2017, Yorktown exercised the Appalachia Warrant, resulting in the issuance of 432,051 shares of our common stock in exchange for Class A Units representing approximately 7.95% of then outstanding Class A Units of Carbon Appalachia. We accounted for the exercise through extinguishment of the warrant liability associated with the Appalachia Warrant of approximately $1.9 million and the receipt of Yorktown’s Class A Units as an increase to investment in affiliates in the amount of approximately $2.9 million. After giving effect to the exercise, we own 26.5% of Carbon Appalachia’s outstanding Class A Units along with 100% of its Class C Units. The issuance of the Class B Units and the Appalachia Warrant were in contemplation of each other, and under non-monetary related party guidance, we accounted for the Appalachia Warrant, at issuance, based on the fair value of the Appalachia Warrant as of the date of grant (April 3, 2017) and recorded a warrant liability with an associated offset to APIC. Future changes to the fair value of the Appalachia Warrant are recognized in earnings. We accounted for the fair value of the Class B Units at their estimated fair value at the date of grant, which became our investment in Carbon Appalachia with an offsetting entry to APIC. As of the grant date of the Appalachia Warrant, we estimated that the fair market value of the Appalachia Warrant was approximately $1.3 million and the fair value of the Class B Units was approximately $924,000. The difference in the fair value of the Appalachia Warrant from the grant date though its exercise on November 1, 2017, was approximately $619,000 million and was recognized in warrant derivative gain in the Company’s consolidated statements of operations for the year ended December 31, 2017. Based on our 27.24% combined Class A, Class B and Class C interest (and our ability as of December 31, 2017 to earn up to an additional 14.7%) in Carbon Appalachia, our ability to appoint a member to the board of directors and our role of manager of Carbon Appalachia, we are accounting for our investment in Carbon Appalachia under the equity method of accounting as it believes it can exert significant influence. We use the HLBV to determine its share of profits or losses in Carbon Appalachia and adjusts the carrying value of its investment accordingly. Our investment in Carbon Appalachia is represented by our Class A and C interests, which it acquired by contributing approximately $6.9 million in cash and unevaluated property. In the event of liquidation of Carbon Appalachia, available proceeds are first distributed to members holding Class C Units then to holders of Class A Units until their contributed capital is recovered with an internal rate of return of 10%. Any additional distributions would then be shared between holders of Class A, Class B and Class C Units. For the period of April 3, 2017 through December 31, 2017, Carbon Appalachia incurred a net gain, of which our share is approximately $1.1 million. The ability of Carbon Appalachia to make distributions to its owners, including us, is dependent upon the terms of its credit facilities, which currently prohibit distributions unless agreed to by the lender. As of December 31, 2017, Carbon Appalachia is in compliance with all CAE Credit Facility covenants. The following table sets forth, selected historical financial data for Carbon Appalachia. (in thousands) As of December 31, 2017 Current assets $ 20,794 Total oil and gas properties, net $ 84,402 Current liabilities $ 18,207 Non-current liabilities $ 59,420 Total members’ equity $ 40,929 (in thousands) Period April 3, Revenues $ 31,584 Operating expenses 26,764 Income from operations 4,820 Net income 3,005 The following table outlines the changes in our investments in affiliates: (in thousands) Carbon California Carbon Appalachia CCGGC Sullivan (1) Total Balance, December 31, 2016 $ - $ - $ 118 $ 550 $ 668 Investment in affiliates gain (loss) - 1,090 38 - 1,128 Cash distributions - - (68 ) - (68 ) Cash contributions - 6,865 - - 6,865 Class B Units issuance 1,854 924 - - 2,778 Appalachia Warrant exercise - 2,896 2,896 Balance, December 31, 2017 $ 1,854 $ 11,775 $ 88 $ 550 $ 14,267 During 2017, we received distributions of approximately $30,000 from our investment in Sullivan Energy which we account for using the cost method of accounting and, as such, we recognized a gain within investment in affiliates of $30,000 for the year ended December 31, 2017.

Bank Credit Facility

Bank Credit Facility	12 Months Ended
	Dec. 31, 2017
Bank Credit Facility [Abstract]
Bank Credit Facility	Note 7 – Bank Credit Facility In 2016, Carbon entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank (the “Credit Facility”). 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 was $17.0 million. The borrowing base is subject to semi-annual redeterminations in March and September. On March 30, 2017, the borrowing base was increased to $23.0 million. As of December 31, 2017, the borrowing base was $23.0 million. The Credit Facility is guaranteed by each existing and future subsidiary of us (subject to certain exceptions). The obligations of us and the subsidiary guarantors under the Credit Facility are secured by essentially all of our tangible and intangible personal and real property (subject to certain exclusions). 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 our option. The actual margin percentage is dependent on the Credit Facility utilization percentage. We are obligated to pay certain fees and expenses in connection with the Credit Facility, including a commitment fee for any unused amounts of 0.50%. The Credit Facility contains certain affirmative and negative covenants that, among other things, limit our 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 our affiliates; (viii) enter into sales-leaseback transaction; (ix) make optional or voluntary payment of debt; (x) change the nature of our business; (xi) change our 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 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 ended March 31, 2017. In the third quarter of 2017, we contributed approximately $6.6 million to Carbon Appalachia to fund its share of producing oil and gas properties acquired during the third quarter. This funding was provided primarily with borrowings under the Credit Facility. The Debt/EBITDA and current ratio covenants negotiated at the time the credit facility was established did not contemplate our contribution for its investment in Carbon Appalachia and, as a result, we were not in compliance with financial covenants associated with the Credit Facility as of December 31, 2017. However, we have obtained a waiver of the Debt/EBITDA ratio and the current ratio covenants as of December 31, 2017. On March 27, 2018, the Credit Facility was amended to revise the calculation of the Leverage Ratio from a Debt/EBITDA ratio to a Net Debt/Adjusted EBITDA ratio, reset the testing period used in the determination of Adjusted EBITDA, eliminate the minimum current ratio and substitute alternative liquidity requirements, including maximum allowed current liabilities in relation to current assets, minimum cash balance requirements and maximum aged trade payable requirements. We may at any time repay the loans under the credit facility, in whole or in part, without penalty. We must pay down borrowings under the credit facility or provide mortgages of additional oil and natural gas properties to the extent that outstanding loan and letters of credit exceed the borrowing base. As required under the terms of the Credit Facility, we entered into derivative contracts at fixed pricing for a certain percentage of our production. We are party to 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 by us and BP Energy Company is secured by the collateral and backed by the guarantees supporting the Credit Facility. As of December 31, 2017, there were approximately $22.1 million in outstanding borrowings and approximately $0.86 million of additional borrowing capacity available under the Credit Facility. Our effective borrowing rate at December 31, 2017 was approximately 5.67%. We incurred fees directly associated with the issuance of the Credit Facility and amortize these fees over the life of the Credit Facility. The current portion of these fees are included in prepaid expense, deposits and other current assets and the long-term portion is included in other long-term assets for a combined value of $700,000. As of December 31, 2017, and 2016, we have unamortized deferred issuance costs of $484,000 and $596,000, respectively. During the years ended December 31, 2017 and 2016, we amortized $176,000 and $51,000, respectively, as interest expense.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Taxes [Abstract]
Income Taxes	Note 8 – Income Taxes The provision for income taxes for the years ended December 31, 2017 and 2016 consists of the following: (in thousands) For the Year Ended December 31, 2017 2016 Current income tax (benefit) expense $ (74 ) $ - Deferred income tax (benefit) expense 7,080 (4,472 ) Change in valuation allowance (7,080 ) 4,472 Total income tax (benefit) expense $ (74 ) $ - The effective income tax rate for the years ended December 31, 2017 and 2016 differed from the statutory U.S. federal income tax rate as follows: For the Year Ended December 31, 2017 2016 Federal income tax rate 35.0 % 35.0 % State income taxes, net of federal benefit 3.8 3.5 Permanent Differences (20.5 ) 1.1 Non-controlling interest in consolidated partnerships (0.8 ) (0.4 ) True-up of prior year depletion in excess of basis 1.1 .2 Stock-based compensation deficiency 3.1 (2.9 ) Rate changes of prior year deferred (1.8 ) 0.2 True-up of prior year deferred (4.5 ) (1.8 ) Effect of tax cuts and TCJA 91.0 - Increase in valuation allowance and other (107.7 ) (34.9 ) Total income tax expense (benefit) (1.1 )% - % The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities at December 31, 2017 and 2016 are presented below: (in thousands) As of December 31, 2017 2016 Deferred tax assets Net operating loss carryforwards $ 6,407 $ 8,274 Depletion carryforwards 1,934 2,740 Accrual and other 450 726 Stock-based compensation 476 968 Derivatives - 730 Asset retirement obligations 1,944 1,936 Property, plant and equipment 2,972 6,439 Total deferred tax assets 14,183 21,813 Deferred tax liability Interest in partnerships (790 ) (762 ) Derivative and other (57 ) - Less valuation allowance (13,336 ) (21,051 ) Net deferred tax asset $ - $ - As of December 31, 2017, we have net operating loss (“NOL”) carryforwards of approximately $21.4 million available to reduce future years’ federal taxable income. The federal NOLs expire in various years through 2037. We have various state NOL carryforwards available to reduce future years’ state taxable income, which are dependent on apportionment percentages and state laws that can change from year to year and impact the amount of such carryforwards. These state NOL carryforwards will expire in the future based upon 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. We believe that the tax positions taken in our tax returns satisfy the more likely than not threshold for benefit recognition. Accordingly, no liabilities have been recorded by us. Any potential adjustments for uncertain tax positions would be a reclassification between the deferred tax asset related to our NOL carryforwards and another deferred tax asset. Our policy is to classify accrued penalties and interest related to unrecognized tax benefits in our income tax provision. As of December 31, 2017, we did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the current year. On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “TCJA”). The TCJA makes broad and complex changes to the U.S. tax code applicable to certain items in 2017 as well as those applicable to 2018 and subsequent years. ASC 740 requires the recognition of the tax effects of the of the TCJA for annual periods that include December 22, 2017. At December 31, 2017, we have made reasonable estimates of the effects on our existing deferred tax balances. We have remeasured certain federal deferred tax assets and liabilities based upon the rates at which they are expected to reverse in the future, which is generally 21.0% percent. The provisional amount recognized related to the remeasurement of its federal deferred tax balance was $6.0 million, which was subject to a valuation allowance at December 31, 2017. We will continue to analyze the TCJA and future IRS regulations, refine our calculations and gain a more thorough understanding of how individual states are implementing this new law. This further analysis could potentially affect the measurement of deferred tax balances or potentially give rise to new deferred tax amounts. We file income tax returns in the U.S. federal jurisdiction and in various states, each with varying statutes of limitations. The 2014 through 2017 tax years generally remain subject to examination by federal and state tax authorities.

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2017
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. In connection with the reverse stock split, the number of authorized shares of our common stock was decreased from 200,000,000 to 10,000,000. As of December 31, 2017, we had 10,000,000 shares of common stock authorized with a par value of $0.01 per share, of which approximately 6,000,000 were issued and outstanding, and 1,000,000 shares of preferred stock authorized with a par value of $0.01 per share, none of which were issued and outstanding. During the year ended December 31, 2017, the increase in our issued and outstanding common stock reflects the exercise by the holder of the Appalachia Warrant (see Note 6), resulting in the issuance of approximately 432,000 shares of our common stock in addition to restricted stock and performance units, net of shares exchanged for payroll tax obligations paid by us, that vested during the year in exchange for Class A Units in Carbon Appalachia representing approximately 7.95% of the then outstanding Class A Units. Carbon Stock Incentive Plans We have 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 our shareholders and in the aggregate provide for the issuance of approximately 1.1 million shares of common stock to our officers, directors, employees or consultants eligible to receive the awards under the Carbon Plans. The Carbon Plans provide for the granting of incentive stock options, non-qualified stock options, restricted stock awards, performance awards and phantom stock awards, or a combination of the foregoing, as to employees, officers, directors or consultants, provided that only employees may be granted incentive stock options and directors may only be granted restricted stock awards and phantom stock awards. 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 us or the date their membership on the Board of Directors is terminated other than for cause. We recognize 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 2017, we 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, we utilized the closing price of our stock on the date of grant to recognize compensation expense. The following table shows a summary of our unvested restricted stock under the Carbon Plans as of December 31, 2017 and 2016 as well as activity during the years then ended. Weighted Avg Number Grant Date of Shares Fair Value Restricted stock awards, unvested, January 1, 2016 199,000 $ 10.37 Granted 134,501 5.40 Vested (64,668 ) 10.84 Forfeited (1,083 ) 6.20 Restricted stock awards, unvested, December 31, 2016 267,750 7.78 Granted 81,050 7.20 Vested (64,915 ) 8.38 Forfeited (13,050 ) 6.19 Restricted stock awards, unvested, December 31, 2017 270,835 $ 7.54 Compensation costs recognized for these restricted stock grants were approximately $664,000 and $742,000 for the years ended December 31, 2017 and 2016, respectively. As of December 31, 2017, there was approximately $1.1 million of unrecognized compensation costs related to these restricted stock grants which we expect to be recognized over the next 6.3 years. Restricted Performance Units Performance units represent a contractual right to receive one share of our 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 as well as, in some cases, continued service requirements. The following table shows a summary of our unvested performance units as of December 31, 2017 and 2016 as well as activity during the years then ended. Number of Shares Restricted performance units, unvested, January 1, 2016 314,311 Granted 80,000 Vested (84,480 ) Forfeited (13,520 ) Restricted performance units, unvested, December 31, 2016 296,311 Granted 60,050 Vested (80,000 ) Forfeited (17,550 ) Restricted performance units, unvested, December 31, 2017 258,811 We account for the performance units granted during 2014 through 2017 at their fair value determined at the date of grant, which were $11.80, $8.00, $5.40 and $7.20 per share, respectively. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At December 31, 2017, we estimated that none of the performance units granted in 2016 and 2017 would vest, and, accordingly, no compensation cost has been recorded for these performance units. During 2016, we estimated that it was probable that the performance units granted in 2014 and 2015 would vest and therefore compensation costs of approximately $442,000 and $1.2 million related to these performance units were recognized for the years ended December 31, 2017 and 2016, respectively. As of December 31, 2017, if change in control and other performance provisions pursuant to the terms and conditions of these award agreements are met in full, the estimated unrecognized compensation cost related to the performance units granted in 2014 through 2017 would be approximately $2.1 million.

Accounts Payable and Accrued Li

Accounts Payable and Accrued Liabilities	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 consist of the following: (in thousands) As of December 31, 2017 2016 Accounts payable $ 3,274 $ 2,315 Oil and gas revenue suspense 1,776 1,415 Gathering and transportation payables 497 468 Production taxes payable 214 113 Drilling advances received from joint venture partner 245 955 Accrued drilling costs - 4 Accrued lease operating costs 684 282 Accrued ad valorem taxes-current 1,054 1,552 Accrued general and administrative expenses 2,473 1,572 Accrued asset retirement obligation-current 380 - Accrued interest 247 184 Other liabilities 374 261 Total accounts payable and accrued liabilities $ 11,218 $ 9,121

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
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 us. Unobservable inputs are inputs that reflect our 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. Our 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. We have consistently applied the valuation techniques discussed below for all periods presented. The following table presents our financial assets and liabilities that were accounted for at fair value on a recurring basis by level within the fair value hierarchy: (in thousands) Fair Value Measurements Using Level 1 Level 2 Level 3 Total December 31, 2017 Asset: Commodity derivatives $ - $ 225 $ - $ 225 Liabilities Warrant derivative liability $ - $ - $ 2,017 $ 2,017 December 31, 2016 Liability: Commodity derivatives $ - $ 1,932 $ - $ 1,932 Commodity Derivative As of December 31, 2017, our commodity derivative financial instruments are comprised of eight natural gas, eight oil swap, and one natural gas costless collar agreements. As of December 31, 2016, our commodity derivative financial instruments were comprised of eight natural gas swap agreements and nine oil swap 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. Our estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, our 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, our derivative instruments are included within the Level 2 fair value hierarchy. The counterparty for all of our outstanding commodity derivative financial instruments as of December 31, 2017 is BP Energy Company. Warrant Derivative A third-party valuation specialist is utilized to determine the fair value of our California Warrant and Appalachia Warrant. These warrants are designated as Level 3. We review these valuations, including the related model inputs and assumptions, and analyze changes in fair value measurements between periods. We corroborate such inputs, calculations and fair value changes using various methodologies, and reviews unobservable inputs for reasonableness utilizing relevant information from other published sources. We estimated the fair value of the California Warrant on February 15, 2017, the grant date of the warrant, to be approximately $5.8 million, using a call option pricing model with the following assumptions: a seven-year term, exercise price of $7.20, volatility rate of 41.8% and a risk-free rate of 2.3%. As we will receive Class A units in Carbon California in the event the holder exercises the California Warrant, we also considered the fair value of the Class A units in its valuation. We remeasured the California Warrant as of December 31, 2017, using a Monte Carlo valuation model which utilized unobservable inputs including the percentage return on our shares at various timelines, the percentage return on the privately-held Carbon California Class A units at various timelines, an exercise price of $7.20, volatility rate of 45%, a risk-free rate of 2.1% and an estimated remaining term of 6.4 years. As of December 31, 2017, the fair value of the California Warrant was approximately $2.0 million. We estimated the fair value of the Appalachia Warrant on April 3, 2017, the grant date of the warrant, to be approximately $1.3 million, using a call option pricing model with the following assumptions: a seven-year term, exercise price of $7.20, volatility rate of 39.3% and a risk-free rate of 2.1%. As we will receive Class A units in Carbon Appalachia in the event the holder exercises the Appalachia Warrant, we also considered the fair value of the Class A units in its valuation. We remeasured the Appalachia Warrant as of November 1, 2017, immediately prior to its exercise, using a Monte Carlo valuation model which utilized unobservable inputs including the percentage return on our shares at various timelines, the percentage return on the privately-held Carbon Appalachia Class A units at various timelines, an exercise price of $7.20, volatility rate of 45%, a risk-free rate of 2.1% and an estimated remaining term of 6.5 years. As of December 31, 2017, the warrant liability had been extinguished. The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy: (in thousands) California Warrant Appalachia Warrant Total Balance, December 31, 2016 $ - $ - $ - Warrant liability 5,769 1,325 7,094 Unrealized (gain) loss included in warrant gain (3,752 ) 619 (3,133 ) Settlement of warrant liability - (1,944 ) (1,944 ) Balance, December 31, 2017 $ 2,017 $ - $ 2,017 Assets and Liabilities 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. We use 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 year ended December 31, 2017, we recorded $2.4 million in additions to asset retirement obligations compared to additions of approximately $1.8 million for the year ended December 31, 2016. See Note 3 for additional information. To determine the fair value of the proved developed properties acquired in the EXCO Acquisition in 2016, we 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 we are 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. We assume, at times, certain firm transportation contracts as part of our acquisitions of oil and natural gas properties. The fair value of the firm transportation obligations was determined based upon the contractual obligations assumed by us and discounted based upon our effective borrowing rate. These contractual obligations are being amortized on a monthly basis as we pay these firm transportation obligations in the future. Asset Retirement Obligation The fair value of our asset retirement obligation liability is recorded in the period in which it is incurred or assumed by taking into account the cost of abandoning oil and gas wells ranging from $20,000 to $30,000, which is based on our historical experience and industry expectations for similar work; the estimated timing of reclamation ranging from one to 75 years based on estimates from reserve engineers; an inflation rate of 1.92%; and a credit adjusted risk-free rate of 7.24%, which takes into account our credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs (see Note 3). During the year ended December 31, 2017, we recorded additions to asset retirement obligations of approximately $2.4 million, which was the result of increases in the costs estimated to perform plugging and reclamation activities within the Appalachian Basin. We use 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. Class B Units We received Class B units from Carbon California and Carbon Appalachia as part of the entry into the Carbon California LLC Agreement and Carbon Appalachia LLC Agreement, respectively. We estimated the fair value of the Class B units, in each case, by utilizing the assistance of third-party valuation specialists. The fair values were based upon enterprise values derived from inputs including estimated future production rates, future commodity prices including price differentials as of the dates of closing, future operating and development costs and comparable market participants.

Physical Delivery Contracts and

Physical Delivery Contracts and Commodity Derivatives	12 Months Ended
	Dec. 31, 2017
Physical Delivery Contracts and Commodity Derivatives [Abstract]
Physical Delivery Contracts and Commodity Derivatives	Note 12 – Physical Delivery Contracts and Commodity Derivatives We historically have used commodity-based derivative contracts to manage exposures to commodity price on certain of our oil and natural gas production. We do not hold or issue derivative financial instruments for speculative or trading purposes. We also have 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 our credit facility with LegacyTexas Bank, we have entered into swap and collar derivative agreements to hedge certain of our oil and natural gas production through 2019. As of December 31, 2017, these derivative agreements consisted of the following: Natural Gas Swaps Natural Gas Collars Oil Swaps Weighted Weighted Weighted Average Average Price Average Year MMBtu Price (a) MMBtu Range (a) Bbl Price (b) 2018 3,390,000 $ 3.01 60,000 $3.00 - $3.48 63,000 $ 53.55 2019 2,596,000 $ 2.86 - - 48,000 $ 53.76 (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 our swap instruments, we receive 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. Costless collars are designed to establish floor and ceiling prices on anticipated future oil and gas production. The ceiling establishes a maximum price that we will receive for the volumes under contract, while the floor establishes a minimum price. The following table summarizes the fair value of the derivatives recorded in the consolidated balance sheets (Note 11). These derivative instruments are not designated as cash flow hedging instruments for accounting purposes: (in thousands) As of December 31, 2017 2016 Commodity derivative contracts: Commodity derivative asset $ 215 $ - Other long-term assets $ 10 $ - Commodity derivative liabilities $ - $ 1,341 Commodity derivative liabilities, non-current $ - $ 591 The table below summarizes the commodity settlements and unrealized gains and losses related to our derivative instruments for the years ended December 31, 2017 and 2016. 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 2017 2016 Commodity derivative contracts: Settlement gains $ 770 $ 231 Unrealized gains (loss) 2,158 (2,490 ) Total settlement and unrealized gains (losses), net $ 2,928 $ (2,259 ) Commodity derivative settlement gains and losses are included in cash flows from operating activities in our consolidated statements of cash flows. The counterparty in all our derivative instruments is BP Energy Company. We have entered into an International Swaps and Derivatives Association (“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 us and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facility. We net our derivative instrument fair value amounts executed with BP Energy Company pursuant to the 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, 2017. Net Gross Recognized Recognized Gross Fair Value Assets/ Amounts Assets/ Balance Sheet Classification Liabilities Offset Liabilities Commodity derivative assets: Commodity derivative $ 624 $ (409 ) $ 215 Other long-term assets 250 (240 ) 10 Total derivative assets $ 874 $ (649 ) $ 225 Commodity derivative liabilities: Commodity derivative $ (409 ) $ 409 $ - Commodity derivative: non-current (240 ) 240 - Total derivative liabilities $ (649 ) $ 649 $ - 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: Commodity derivative $ - $ - $ - Other long-term assets 249 (249 ) - Total derivative assets $ 249 $ (249 ) $ - Commodity derivative liabilities: Commodity derivative $ 1,341 $ - $ 1,341 Commodity derivative: non-current 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 our derivatives are subject to large fluctuations from period to period.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies [Abstract]
Commitments and Contingencies	Note 13 – Commitments and Contingencies We have entered into employment agreements with certain of our executives and officers. The term of the agreements generally ranges from one to two years and provides 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. We have entered into long-term firm transportation contracts to ensure the transport for certain of our gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts at December 31, 2017 are summarized in the table below. Period Dekatherms per day Demand Charges Jan 2018 - 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 $261,000 related to firm transportation contracts assumed in the EXCO Acquisition in 2016, which represents the remaining commitment, is reflected on our Consolidated Balance Sheet as of December 31, 2017. The fair value of these firm transportation obligations was determined based upon the contractual obligations assumed by us and discounted based upon our effective borrowing rate. These contractual obligations are being amortized monthly as we pay these firm transportation obligations in the future. We lease, under an operating lease arrangement, approximately 8,500 square feet of administrative office space in Denver, Colorado that expires in 2023, approximately 5,300 square feet of office space in Lexington, Kentucky that expires in 2019, and 9,500 square feet of office space in Santa Paula, California that expires in 2021. For the years ended December 31, 2017 and 2016, we incurred rental expenses of $255,000 and $220,000, respectively. We have minimum lease payments for our office space and equipment of approximately $436,000 for 2018, $390,000 for 2019, $382,000 for 2020, $275,000 for 2021, and $270,000 for 2022. Capital Commitment In our participation as a Class A member of Carbon Appalachia we made a capital commitment of $23.6 million, of which we have contributed $6.9 million as of December 31, 2017. As of December 31, 2017, we had no capital commitments associated with Carbon California. During March 2018, management became aware that one of our field employees had been misappropriating funds from our suspended revenue accounts, or suspense accounts, over a period of several years. Promptly following the discovery of the misappropriation, we terminated the employee and engaged an external forensic specialist to lead an investigation to determine the extent and impact on our financial statements. That investigation revealed that the employee’s ability to misappropriate funds from the suspense accounts was eliminated in 2017 when we moved our revenue accounting function to our Denver office and instituted our current set of revenue accounting practices and internal controls. As a result, the employee no longer had access to the suspense accounts. The discovery of the misappropriation was made in March 2018 when the employee attempted to misappropriate funds from a different source. This attempt was identified under the Company’s current internal controls. The investigation is still ongoing, but based on the results so far, we have recorded a provision at December 31, 2017 of $250,000 to reflect the estimated loss of suspended revenue. Depending upon the final results of the investigation, which we are seeking to conclude as soon as reasonably practicable, we may determine that the estimate should be increased or decreased. Furthermore, we will no longer be using printed manual checks for payments. Revenue and other checks will require approval from more than one individual and we are evaluating our segregation of duties, specifically related to the cash disbursement process, and will adjust where possible to strengthen the system of internal control. We have determined that this event constituted a significant deficiency, but not a material weakness, at December 31, 2017.

Retirement Savings Plan

Retirement Savings Plan	12 Months Ended
	Dec. 31, 2017
Retirement Savings Plan [Abstract]
Retirement Savings Plan	Note 14 – Retirement Savings Plan We have a 401(k) plan available to eligible employees. The plan provides for 6% matching which vests immediately. For the years ended December 31, 2017 and 2016, we contributed approximately $175,000 and $99,000, respectively, for 401(k) contributions and related administrative expenses.

Supplemental Cash Flow Disclosu

Supplemental Cash Flow Disclosure	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Disclosure [Abstract]
Supplemental Cash Flow Disclosure	Note 15 – Supplemental Cash Flow Disclosure Supplemental cash flow disclosures are presented below: (in thousands) For the Years Ended 2017 2016 Cash paid during the period for: Interest payments $ 967 $ 156 Income taxes - - Non-cash transactions: Increase in asset retirement obligations $ 2,402 $ 1,849 Increase (decrease) in accounts payable and accrued liabilities included in oil and gas properties $ 67 $ 1,099 Obligations assumed with acquisitions $ - $ 2,694 Equity method investments $ 5,674 $ -

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2017
Related Parties [Abstract]
Related Parties	Note 16 – Related Parties During the year ended December 31, 2017, we were engaged in the following transactions with related parties: Carbon California We received 5,077 Class B units of Carbon California, representing 17.81% of the voting and profits interest. Carbon California Operating Company (“CCOC”) is our subsidiary and the operator of Carbon California through an operating agreement. The operating agreement includes reimbursements and allocations made under the agreement. As of December 31, 2017, approximately $300,000 is due from Carbon California and included in accounts receivable – due from related party on the consolidated balance sheets. On February 15, 2017, we entered into a management service agreement with Carbon California whereby we provide general management and administrative services. We receive $600,000 annually, payable in four equal quarterly installments. We also received a one-time reimbursement of $500,000 in connection with the CRC and Mirada Acquisitions. Carbon California reimburses us for all management related expenses such as travel, required third-party geological and/or accounting consulting, and other necessary expenses incurred by us in the normal course of managing Carbon California. For the year ended December 31, 2017, we recorded $1.0 million in total management reimbursements. There were no outstanding management reimbursements unpaid as of December 31, 2017. Carbon Appalachia We received 1,000 Class B units of Carbon Appalachia, representing a future profits interest after certain return thresholds to Class A Units are met. We also received 121 Class C Units of Carbon Appalachia, representing an approximate 1.0% profits interest, in exchange for unevaluated property in Tennessee. Nytis is the operator of Carbon Appalachia through an operating agreement. The operating agreement includes reimbursements and allocations made under the agreement. As of December 31, 2017, approximately $1.8 million is due from Carbon Appalachia and included in accounts receivable – due from related party on the consolidated balance sheets. On April 3, 2017, we entered into a management service agreement with Carbon Appalachia whereby we provide general management and administrative services. We initially received a quarterly reimbursement of $75,000; however, after the Enervest Acquisition in August, the amount of the reimbursement now varies quarterly based upon the percentage of our production in relation to the total of our production and Carbon Appalachia. We also received a one-time reimbursement of $300,000 in connection with the CNX Acquisition. Total reimbursements recorded by us for the year ended December 31, 2017, were approximately $1.6 million, of which approximately $579,000 was included in accounts receivable – due from related party on the consolidated balance sheets as of December 31, 2017. Ohio Basic Minerals During 2017, we received $96,000 in management reimbursements from Ohio Basic Minerals.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	Note 17 – Subsequent Events On February 1, 2018, Yorktown exercised the California Warrant resulting in us receiving 11,000 Class A Units in Carbon California and issuing 1,527,778 shares of its Common Stock to Yorktown. As a result, our ownership of Class A Units of Carbon California increased from zero to 11,000 or from 0% to 46.96% (which equates to a sharing percentage interest of 38.59%). We also hold all of the Class B Units of Carbon California which represent a sharing percentage of 17.81%, resulting in our aggregate sharing percentage increasing from 17.81% to 56.40%. On March 27, 2018, we amended our senior secured asset-based revolving credit facility with LegacyTexas Bank, adjusting certain covenants, the specifics of which are described in the amended agreement. On March 28, 2018, our Credit Facility borrowing base was increased to $25.0 million. Pursuant to the credit agreement amendment entered into on March 27, 2018, we are subject to a minimum liquidity covenant of $750,000.

Supplemental Financial Data - O

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited)	12 Months Ended
	Dec. 31, 2017
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) [Abstract]
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited)	Note 18– Supplemental Financial Data – Oil and Gas Producing Activities (unaudited) Estimated Proved Oil and Gas Reserves The reserve estimates as of December 31, 2017 and 2016 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, 2017 and 2016 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. Our estimates of our net proved, net proved developed, and net proved undeveloped oil and gas reserves and changes in our net proved oil and gas reserves for 2017 and 2016 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, 2017 and 2016 unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Prices do not include the effects of commodity derivatives. CGA evaluated and prepared independent estimated proved reserves quantities and related pre-tax future cash flows as of December 31, 2017 and 2016. 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 our 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, 2017 and 2016. 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. As of December 31, 2017, we held a 17.81% and 27.24% proportionate share of Carbon California and Carbon Appalachia, respectively. This proportionate share amount reflects our aggregated sharing percentage based on all classes of ownership held in each equity investee. These proportionate share amounts assume each equity investee is operating as a going concern, and no adjustments have been made that could be required based on priority of units and hurdle rates upon liquidation or distributions. A summary of the changes in quantities of proved oil and gas reserves for the years ended December 31, 2017 and 2016 are as follows (in thousands): Company Company’s share of Carbon California Company’s share of Carbon Appalchia Total Oil Natural Gas Total Oil Natural Gas NGL Total Oil Natural Gas Total Oil Natural Gas NGL Total MBbls MMcf MMcfe MBbls MMcf (MBbls) MMcfe MBbls MMcf MMcfe MBbls MMcf (MBbls) MMcfe January 1, 2016 Proved reserves, beginning of year 598 29,958 33,546 - - - - - - - 598 29,958 - 33,546 Revisions of previous estimates 110 2,207 2,867 - - - - - - - 110 2,207 - 2,867 Extensions and discoveries - - - - - - - - - - - - - - Production (79 ) (2,823 ) (3,297 ) - - - - - - - (79 ) (2,823 ) - (3,297 ) Purchases of reserves in-place 253 44,923 46,441 - - - - - - - 253 44,923 - 46,441 Sales of reserves in-place - - - - - - - - - - - - - - December 31, 2016 882 74,265 79,557 - - - - - - - 882 74,265 - 79,557 Revisions of previous estimates 107 12,195 12,835 - - - - - - 107 12,195 - 12,837 Extensions and discoveries 16 138 232 - - - - - - 16 138 - 234 Production (2) (86 ) (4,896 ) (5,414 ) (25 ) (63 ) (4 ) (237 ) (2 ) (1,178 ) (1,328 ) (136 ) (4,984 ) (4 ) (5,824 ) Purchases of reserves in-place (1) - - - 1,650 3,075 231 14,361 74 91,935 101,835 3,300 4,725 231 25,911 Sales of reserves in-place - - - - - - - - - - - - December 31, 2017 919 81,702 87,210 1,625 3,012 227 14,124 72 90,757 100,507 4,169 86,339 227 112,715 (1) Related to Carbon Appalachia the purchases of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14, 2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; and November 1, 2017 through December 31, 2017, respectively. (2) Related to Carbon Appalachia, the net sales (in standard measure change) and production figures were calculated utilizing the same methodology as the purchase of reserves-in-place discussed above. 2017 2016 Oil Natural Gas (MMcf) NGL (MBbls) Total (MMcfe) Oil Natural Gas (MMcf) NGL Total (MMcfe) Company Proved developed reserves at: End of Year 903 81,702 - 87,120 851 74,265 - 79,557 Proved undeveloped reserves at: End of Year 16 - - 96 31 - - 186 Company’s share of Carbon California Proved developed reserves at: End of Year 1,006 2,194 163 9,208 - - - - Proved undeveloped reserves at: End of Year 619 818 63 4,910 - - - - Company’s share of Carbon Appalachia Proved developed reserves at: End of Year (1) (2) 72 90,757 - 91,189 - - - - Proved undeveloped reserves at: End of Year - - - - - - - - Total Proved developed reserves at: - End of Year 1,981 174,653 163 187,517 851 74,265 - 79,557 Proved undeveloped reserves at: - End of Year 635 818 63 5,006 31 - - 186 (1) Related to Carbon Appalachia the purchases of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14, 2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; and November 1, 2017 through December 31, 2017, respectively. (2) Related to Carbon Appalachia, the net sales (in standard measure change) and production figures were calculated utilizing the same methodology as the purchase of reserves-in-place discussed above. 2017 2016 Oil Natural Gas Total Oil Natural Gas Total MBbls MMcf MMcfe MBbls MMcf MMcfe Proved reserves, beginning of year 882 74,265 79,557 598 29,958 33,546 Revisions of previous estimates 107 12,195 12,837 110 2207 2867 Extensions and discoveries 16 138 234 - - - Production (86 ) (4,896 ) (5,412 ) (79 ) (2,823 ) (3,297 ) Purchases of reserves in-place (1) (2) - - - 253 44,923 46,441 Sales of reserves in-place - - - - - - Proved reserves, end of year 919 81,702 87,216 882 74,265 79,557 Proved developed reserves at: End of Year 903 81,702 87,120 882 74,265 79,371 Proved undeveloped reserves at: End of Year 16 - 96 31 - 186 (1) Related to Carbon Appalachia the purchases of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14, 2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; and November 1, 2017 through December 31, 2017, respectively. (2) Related to Carbon Appalachia, the net sales (in standard measure change) and production figures were calculated utilizing the same methodology as the purchase of reserves-in-place discussed above. The estimated proved reserves for December 31, 2017 and 2016 includes approximately 3.0 and 3.1 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: 2017 2016 (in thousands) Oil and gas properties Company Proved oil and gas properties $ 114,893 $ 112,579 Unproved properties not subject to depletion 1,947 1,999 Accumulated depreciation, depletion, amortization and impairment (80,715 ) (78,596 ) Total Company oil and gas properties, net $ 36,125 $ 35,982 Company’s share of Carbon California Proved oil and gas properties $ 7,635 $ - Unproved properties not subject to depletion 266 - Accumulated depreciation, depletion, amortization and impairment (208 ) - Total Company’s share of Carbon California oil and gas properties, net $ 7,693 $ - Company’s share of Carbon Appalachia Proved oil and gas properties $ 22,951 $ - Unproved properties not subject to depletion 485 - Accumulated depreciation, depletion, amortization and impairment (445 ) - Total Company’s share of Carbon Appalachia oil and gas properties, net $ 22,991 $ - 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, 2017 and 2016: 2017 2016 (in thousands) Company Property acquisition costs: Unevaluated properties $ 1 $ 97 Proved properties and gathering facilities 289 8,117 Development costs 952 360 Gathering facilities 43 42 Asset retirement obligation 2,309 1,849 Total costs incurred $ 3,594 $ 10,465 Company’s share of Carbon California Property acquisition costs: Unevaluated properties $ 266 $ - Proved properties and gathering facilities 7,682 - Development costs 412 - Gathering facilities 47 - Asset retirement obligation 483 - Total costs incurred $ 8,890 $ - Company’s share of Carbon Appalachia Property acquisition costs: Unevaluated properties $ 483 $ - Proved properties and gathering facilities 19,286 - Development costs 24 - Gathering facilities 2,544 - Asset retirement obligation 3,592 - Total costs incurred $ 25,929 $ - Our investment in unproved properties as of December 31, 2017, by the year in which such costs were incurred is set forth in the table below: 2017 2016 2015 (in thousands) Acquisition costs Company $ 1 $ 97 $ 1,849 Company’s share of Carbon California 266 - - Company’s share of Carbon Appalachia 485 - - Total acquisition costs $ 752 $ 97 $ 1,849 Results of Operations from Oil and Gas Producing Activities Results of operations from oil and gas producing activities for the years ended December 31, 2017 and 2016 are presented below: (in thousands) 2017 2016 Revenues Oil and gas sales, including commodity derivative gains and losses Company $ 22,439 $ 8,184 Company’s share of Carbon California $ 1,289 $ - Company’s share of Carbon Appalachia 5,273 - Total oil and gas sales, including commodity derivative gains and losses 29,001 8,184 Expenses: Production expenses Company 9,589 5,640 Company’s share of Carbon California 664 - Company’s share of Carbon Appalachia 1,522 - Total production expenses 11,775 5,640 Depletion expense Company 2,157 1,839 Company’s share of Carbon California 208 - Company’s share of Carbon Appalachia 445 - Total depletion expense 2,810 1,839 Accretion of asset retirement obligations Company 307 176 Company’s share of Carbon California 34 - Company’s share of Carbon Appalachia 54 - Total accretion of asset obligation 395 176 Impairment of oil and gas properties Company - 4,299 Company’s share of Carbon California - - Company’s share of Carbon Appalachia - - Total accretion of asset obligation - 4,299 Total expenses 14,979 11,954 Results of operations from oil and gas producing activities $ 14,021 $ (3,770 ) Depletion rate per Mcfe $ 0.47 $ 0.56 Standardized Measure of Discounted Future Net Cash Flows Future oil and gas sales are calculated applying the prices used in estimating our 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. Carbon California and Carbon Appalachia does not include the future net effect of income taxes because Carbon California and Carbon Appalachia is treated as partnerships for tax purposes and is not subject to federal income taxes. 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 our proved reserves. Management does not rely upon the information that follows in making investment decisions. (in thousands) December 31, 2017 2016 Company: Future cash inflows $ 283,664 $ 214,658 Future production costs (119,501 ) (103,252 ) Future development costs (210 ) (315 ) Future income taxes (35,482 ) (14,858 ) Future net cash flows 128,471 96,233 10% annual discount (71,389 ) (51,522 ) Standardized measure of discounted future net cash flows $ 57,082 $ 44,711 Company’s share of Carbon California Future cash inflows $ 97,841 $ - Future production costs (62,187 ) - Future development costs (5,809 ) - Future income taxes (2) - - Future net cash flows 29,845 - 10% annual discount (16,288 ) - Standardized measure of discounted future net cash flows $ 13,557 $ - Company’s share of Carbon Appalachia Future cash inflows (1) (4) $ 271,638 $ - Future production costs (1) (151,501 ) - Future development costs (1) (27 ) - Future income taxes (3) - - Future net cash flows 120,110 - 10% annual discount (73,890 ) - Standardized measure of discounted future net cash flows $ 46,220 $ - (1) Related to Carbon Appalachia the purchases of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14, 2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; November 1, 2017 through December 31, 2017, respectively. (2) Carbon California does not include the net changes in future income taxes because Carbon California is treated as a partnership for taxes and is not subject to federal income taxes. (3) Carbon Appalachia does not include the net changes in future income taxes because Carbon California is treated as a partnership for taxes and is not subject to federal income taxes (4) Related to Carbon Appalachia, the net sales (in standard measure change) and production figures was calculated utilizing the same methodology as the purchase of reserves-in-place discussed above. 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, Company Company’s Share of Carbon California Company’s Share of Carbon Appalachia Total (in thousands) Balance at January 1, 2016 Standardized measure of discounted future net cash flows, beginning of year $ 25,032 $ - $ - $ 25,032 Sales of oil and gas, net of production costs and taxes (4,804 ) - - (4,804 ) Price revisions (786 ) - - (786 ) Extensions, discoveries and improved recovery, less related costs - - - - Changes in estimated future development costs 248 - - 248 Development costs incurred during the period 102 - - 102 Quantity revisions 2,091 - - 2,091 Accretion of discount 2,503 - - 2,503 Net changes in future income taxes (4,633 ) - - (4,633 ) Purchases of reserves-in-place 26,776 - - 26,776 Sales of reserves-in-place - - - - Changes in production rate timing and other (1,818 ) - - (1,818 ) Balance at December 31, 2016 $ 44,711 $ - $ - $ 44,711 Sales of oil and gas, net of production costs and taxes (4) (10,038 ) (516 ) (1,240 ) (12,231 ) Price revisions 17,588 - - 17,588 Extensions, discoveries and improved recovery, less related costs 298 - - 298 Changes in estimated future development costs (324 ) - - (324 ) Development costs incurred during the period 804 - - 804 Quantity revisions 11,196 - - 11,196 Accretion of discount 4,471 - - 4,471 Net changes in future income taxes (2) (3) (7,425 ) - - (7,425 ) Purchases of reserves-in-place (1) - 14,073 47,460 61,533 Sales of reserves-in-place - - - - Changes in production rate timing and other (4,199 ) - - (4,199 ) Standardized measure of discounted future net cash flows, at December 31, 2017 $ 57,082 $ 13,557 $ 46,220 $ 116,422 (1) Related to Carbon Appalachia the purchases of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14, 2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; and November 1, 2017 through December 31, 2017, respectively. (2) Carbon California does not include the net changes in future income taxes because Carbon California is treated as a partnership for taxes and is not subject to federal income taxes. (3) Carbon Appalachia does not include the net changes in future income taxes because Carbon California is treated as a partnership for taxes and is not subject to federal income taxes. (4) Related to Carbon Appalachia, the net sales (in standard measure change) and production figures was calculated utilizing the same methodology as the purchase of reserves-in-place discussed above. The twelve-month weighted averaged adjusted prices in effect at December 31, 2017 and 2016 were as follows: 2017 2016 Oil (per Bbl) $ 51.34 $ 40.40 Natural Gas (per Mcf) $ 2.98 $ 2.41

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Summary of Significant Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The consolidated financial statements include the accounts of us and our consolidated subsidiaries. We own 100% of Nytis USA. Nytis USA owns approximately 99 % of Nytis LLC. Nytis LLC holds interests in various oil and gas partnerships. For partnerships where we have a controlling interest, the partnerships are consolidated. We are currently consolidating 46 partnerships, and we reflect the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on our 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 our consolidated balance sheets. All significant intercompany accounts and transactions have been eliminated. In accordance with established practice in the oil and gas industry, our consolidated financial statements also include our pro-rata share of assets, liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which we have 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 we have the ability to significantly influence the operating decisions of the investee. When we do 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 We grant credit to all qualified customers, which potentially subjects us to credit risk resulting from, among other factors, adverse changes in the industries in which we operate and the financial condition of our customers. We continuously monitor collections and payments from our customers and maintains an allowance for doubtful accounts based upon our historical experience and any specific customer collection issues that it has identified. At December 31, 2017 and 2016, we had not identified any collection issues related to our oil and gas operations and consequently no allowance for doubtful accounts was provided for on those dates. In addition, as of December 31, 2016, accounts receivable included a deposit of $1.7 million made by us on the purchase of assets in the Ventura Basin of California through Carbon California. The deposit was reimbursed to us upon the consummation of the acquisition by Carbon California on February 15, 2017. See Note 4 for additional information. Revenue Our accounts receivable - Revenue is comprised of oil and natural gas revenues from producing activities. Joint Interest Billings and Other Our accounts receivable – joint interest billings and other is comprised of receivables due from other exploration and production companies and individuals who own working interests in the properties that we operate. For receivables from joint interest owners, we typically have the ability to withhold future revenues disbursements to recover any non-payment of joint-interest billings. 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. As of December 31, 2017, there was an imbalance due to us in the amount of approximately $193,000. Due from Related party Our receivables – due from related party are comprised of receivables from Carbon California and Carbon Appalachia in our role as manager and operator of these entities. See Note 16.
Prepaid Expense, Deposits, and Other Current Assets	Prepaid Expense, Deposits, and Other Current Assets Our prepaid expense, deposit, and other current asset account is comprised of prepaid insurance, the current portion of unamortized Credit Facilities issuance costs and deposits.
Oil and Natural Gas Sales	Oil and Natural Gas Sales We sell our 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, 2017 and 2016. There are several purchasers in the areas where we sell our production. We do not believe that changing our primary purchasers or a loss of any other single purchaser would materially impact our business. For the years ended Purchaser 2017 2016 Purchaser A 23 % 4 % Purchaser B 17 % 15 % Purchaser C 12 % 18 % Purchaser D 11 % 16 % Purchaser E 8 % 17 % We recognize 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 we deliver more natural gas than we nominated to deliver to the purchaser and the purchaser pays only for the nominated amount. Conversely, a purchaser imbalance liability occurs when we deliver less natural gas than we nominated to deliver to the purchaser and the purchaser pays for the amount nominated. As of December 31, 2017 and 2016, we had a purchaser imbalance receivable of $193,000 within trade receivables and purchaser imbalance payable of approximately $25,000 within accounts payable and accrued expenses, respectively, which are recognized as a current asset and current liability, respectively, in our consolidated balance sheets. Purchaser A comprises of approximately 23% of total accounts receivable as of December 31, 2017.
Accounting for Oil and Gas Operations	Accounting for Oil and Gas Operations We use 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 us for our 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. We assess our 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. 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. We perform a ceiling test quarterly. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value-based measurement, rather it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using the un-weighted arithmetic average of the first-day-of-the month price for the previous twelve month period, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down 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 year ended December 31, 2017, we did not recognize a ceiling test impairment as our full cost pool did not exceed the ceiling limitations. For the year ended December 31, 2016, we recognized a ceiling test impairment of approximately $4.3 million as our full cost pool exceeded its ceiling limitations. Future declines in oil and natural gas prices, increases in future operating expenses and future development costs could result in impairments of our oil and gas properties in future periods. Impairment changes are a non-cash charge and accordingly would not affect cash flows but would adversely affect our net income and shareholders’ equity. We capitalize interest in accordance with Financial Accounting Standards Board (“FASB”) ASC 932-835-25, Extractive Activities-Oil and Gas, Interest. Therefore, interest is capitalized for any unusually significant investments in unproved properties or major development projects not currently being depleted. We capitalize the portion of general and administrative costs that is attributable to our acquisition, exploration and development activities.
Other Property and Equipment	Other Property and Equipment Other property and equipment are recorded at cost upon acquisition and include office equipment, computer equipment, building, field equipment, vehicles, and software. Depreciation of other property and equipment is calculated over three to seven years using the straight-line method.
Long-Lived Assets	Long-Lived Assets We review our 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. We look primarily to the estimated undiscounted future cash flows in our assessment of whether or not long-lived assets have been impaired.
Other Long-Term Assets	Other Long-Term Assets Our other long-term assets are comprised of bonds, the long-term portion of deferred debt issue and financing costs and the long-term portion of our commodity derivative liability.
Investments in Affiliates	Investments in Affiliates Investments in non-consolidated affiliates are accounted for under either the cost or equity method of accounting, as appropriate. The cost method of accounting is generally used for investments in affiliates in which we have less than 20% of the voting interests of a corporate affiliate or less than a 3% to 5% interest of a partnership or limited liability company and do not have significant influence. Investments in non-consolidated affiliates, accounted for using the cost method of accounting, are recorded at cost and impairment assessments for each investment are made annually to determine if a decline in the fair value of the investment, other than temporary, has occurred. A permanent impairment is recognized if a decline in the fair value occurs. If we hold between 20% and 50% of the voting interest in non-consolidated corporate affiliates or generally greater than a 3% to 5% interest of a partnership or limited liability company and exert significant influence or control (e.g., through our influence with a seat on the board of directors or management of operations), the equity method of accounting is generally used to account for the investment. Investment in affiliates will increase or decrease by our share of the affiliates’ profits or losses and such profits or losses are recognized in our consolidated statements of operations. If we hold greater than 50% of voting shares, we will generally consolidate the entities under the voting interest model. For our investments in Carbon Appalachia and Carbon California, we use the hypothetical liquidation at book value (“HLBV”) method to recognize our share of profits or losses. We review equity method investments for impairment whenever events or changes in circumstances indicate that “an other than temporary” decline in value has occurred.
Related Party Transactions	Related Party Transactions Management Reimbursements In our role as manager of Carbon California and Carbon Appalachia, we receive management reimbursements. These reimbursements are included in general and administrative – related party reimbursement on our consolidated statement of operations. Operating Reimbursements In our role as operator of Carbon California and Carbon Appalachia, we receive reimbursements of operating expenses. These expenses are recorded directly to receivable – related party on our consolidated balance sheets and are therefore not included in our operating expenses on our consolidated statements of operations (see Note 16).
Warrant Liability	Warrant Liability We issued warrants related to investments in Carbon California and Carbon Appalachia. We account for these warrants in accordance with guidance contained in Accounting Standards Codification (“ASC”) 815, Derivatives and Hedging
Asset Retirement Obligations	Asset Retirement Obligations Our 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 (see Note 11). The following table is a reconciliation of the ARO for the years ended December 31, 2017 and 2016. Year Ended December 31, (in thousands) 2017 2016 Balance at beginning of year $ 5,120 $ 3,095 Accretion expense 307 176 Change in estimate of cash outflow 2,402 Additions during period - 1,849 Less: sale of wells (92 ) - 7,737 5,120 Less: ARO recognized as accounts payable and accrued liabilities (380 ) (114 ) Balance at end of year $ 7,357 $ 5,006 For the year ended December 31, 2017, we did not have any additions of ARO compared to $1.8 million in 2016, which was primarily due to the acquisition of producing oil and natural gas properties in the Appalachian Basin. During the year ended December 31, 2017, we increased the estimated cost of retirement obligations for certain wells in the Appalachian Basin. Our estimated costs range from $20,000 to $30,000, which is a better representation of current prices of supplies and services. This increase to estimated costs resulted in a $2.4 million increase to our ARO in 2017.
Financial Instruments	Financial Instruments Our financial instruments include cash and cash equivalents, accounts receivables, accounts payables, accrued liabilities, commodity derivative instruments, warrant liability, and our credit facility. The carrying value of cash and cash equivalents, accounts receivable, accounts payables and accrued liabilities are representative of their fair value, due to the short maturity of these instruments. Our commodity derivative instruments are recorded at fair value, as discussed below and in Note 11. The carrying amount of our credit facility approximated fair value since borrowings bear interest at variable rates, which are representative of our credit adjusted borrowing rate.
Commodity Derivative Instruments	Commodity Derivative Instruments We enter into commodity derivative contracts to manage our exposure to oil and natural gas price volatility with an objective to reduce exposure to downward price fluctuations. Commodity derivative contracts may take the form of futures contracts, swaps, collars or options. We have elected not to designate our 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 We account 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 basis, 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. With the passage of the Tax Cut and Jobs Act (“TCJA”), we are required to remeasure deferred income taxes at the lower 21% corporate rate as of the date the TCJA was signed into law even though the reduced rate is effective January 1, 2018. We account 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). For performance units, since these awards are settled in cash at the end of a defined performance period, they are measured quarterly and expensed over the remaining 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 our net working revenue interest.
Earnings Per Common Share	Earnings Per Common Share Basic earnings per common share is computed by dividing the net income (loss) 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 our officers, directors and employees 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 us 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 income (loss) per share: For the Year Ended (in thousands except per share amounts) 2017 2016 Net income (loss) $ 6,318 $ (12,406 ) Less: warrant derivative gain (3,133 ) - Diluted net income 3,185 (12,406 ) Basic weighted-average common shares outstanding during the period 5,662 5,468 Add dilutive effects of warrants and non-vested shares of restricted stock 790 - Diluted weighted-average common shares outstanding during the period 6,452 5,468 Basic net (loss) income per common share $ 1.12 $ (2.27 ) Diluted net (loss) income per common share $ 0.49 $ (2.27 ) For the year ended December 31, 2017, we had net income and the diluted loss per common share calculation includes the anti-dilutive effects of approximately 519,000 warrants and approximately 271,000 non-vested shares of restricted stock. In addition, approximately 259,000 restricted performance units subject to future contingencies were excluded in the basic and diluted loss per share calculations. For the year ended December 31, 2016, we had a net loss and therefore the diluted loss per common share calculation excludes the anti-dilutive effects of approximately 13,000 warrants and approximately 268,000 non-vested shares of restricted stock. In addition, approximately 296,000 restricted performance units subject to future contingencies were excluded from the basic and diluted loss per share calculations.
Oil and Gas Reserves	Oil and Gas Reserves Oil and gas reserves represent theoretical quantities of crude oil, natural gas, and natural gas liquids (“NGL”) which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our control. Accordingly, reserve estimates and the projected economic value of our and our equity investees’ properties will differ from the actual future quantities of oil and gas ultimately recovered and the corresponding value associated with the recovery of these reserves.
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 GAAP 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 warrants, fair value of equity method investments, fair value of assets acquired and liabilities assumed 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 January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805) In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows-Classification of Certain Cash Receipts and Cash Payments In February 2016, the FASB issued ASU 2016-02, Leases. In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers

Summary of Significant Accoun26

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Summary of Significant Accounting Policies [Abstract]
Summary of percentages by purchaser that account for 10% or more of total oil and natural gas sales	For the years ended Purchaser 2017 2016 Purchaser A 23 % 4 % Purchaser B 17 % 15 % Purchaser C 12 % 18 % Purchaser D 11 % 16 % Purchaser E 8 % 17 %
Summary of reconciliation of the ARO	Year Ended December 31, (in thousands) 2017 2016 Balance at beginning of year $ 5,120 $ 3,095 Accretion expense 307 176 Change in estimate of cash outflow 2,402 Additions during period - 1,849 Less: sale of wells (92 ) - 7,737 5,120 Less: ARO recognized as accounts payable and accrued liabilities (380 ) (114 ) Balance at end of year $ 7,357 $ 5,006
Schedule of basic and diluted (loss) income per share	For the Year Ended (in thousands except per share amounts) 2017 2016 Net income (loss) $ 6,318 $ (12,406 ) Less: warrant derivative gain (3,133 ) - Diluted net income 3,185 (12,406 ) Basic weighted-average common shares outstanding during the period 5,662 5,468 Add dilutive effects of warrants and non-vested shares of restricted stock 790 - Diluted weighted-average common shares outstanding during the period 6,452 5,468 Basic net (loss) income per common share $ 1.12 $ (2.27 ) Diluted net (loss) income per common share $ 0.49 $ (2.27 )

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2017
Acquisitions and Divestitures [Abstract]
Summary of 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
Schedule of unaudited pro-forma consolidated results	Unaudited Pro Forma Consolidated Results For Year Ended December 31, (in thousands, except per share amounts) 2016 Revenue $ 13,963 Net income (loss) income before non-controlling interests (6,825 ) Net income (loss) attributable to non-controlling interests 413 Net income (loss) attributable to controlling interests $ (6,412 ) Net income (loss) per share (basic) $ (1.17 ) Net income (loss) per share (diluted) $ (1.17 )

Property and Equipment (Tables)

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property and Equipment [Abstract]
Summary of net property and equipment	(in thousands) As of December 31, 2017 2016 Oil and gas properties: Proved oil and gas properties $ 114,893 $ 111,771 Unproved properties not subject to depletion 1,947 1,999 Accumulated depreciation, depletion, amortization and impairment (80,715 ) (78,559 ) Net oil and gas properties 36,125 35,211 Furniture and fixtures, computer hardware and software, and other equipment 1,758 990 Accumulated depreciation and amortization (1,021 ) (665 ) Net other property and equipment 737 325 Total property and equipment, net $ 36,862 $ 35,536
Summary of unproved oil and gas properties	As of December 31, (in thousands) 2017 2016 Illinois Basin: Indiana $ 432 $ 431 Illinois 136 298 Appalachian Basin: Kentucky 915 750 Ohio 66 66 West Virginia 398 454 Total unproved properties not subject to depletion $ 1,947 $ 1,999

Investments in Affiliates (Tabl

Investments in Affiliates (Tables)	12 Months Ended
	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Summary of company's contributions	Timing Capital Contribution Resulting Class A Units (%) Resulting Sharing % April 2017 $0.24 million 2.00% 2.98% August 2017 $3.71 million 15.20% 16.04% September 2017 $2.92 million 18.55% 19.37% November 2017 Warrant exercise 26.50% 27.24%
Schedule of changes in ivestments in affiliates	(in thousands) Carbon California Carbon Appalachia CCGGC Sullivan (1) Total Balance, December 31, 2016 $ - $ - $ 118 $ 550 $ 668 Investment in affiliates gain (loss) - 1,090 38 - 1,128 Cash distributions - - (68 ) - (68 ) Cash contributions - 6,865 - - 6,865 Class B Units issuance 1,854 924 - - 2,778 Appalachia Warrant exercise - 2,896 2,896 Balance, December 31, 2017 $ 1,854 $ 11,775 $ 88 $ 550 $ 14,267
Carbon California [Member]
Schedule of Equity Method Investments [Line Items]
Schedule of selected historical financial data	(in thousands) As of December 31, 2017 Current assets $ 3,968 Total oil and gas properties, net $ 43,458 Current liabilities $ 6,899 Non-current liabilities $ 23,279 Total members’ equity $ 18,549 (in thousands) February 15, 2017 (Inception) through December 31, 2017 Revenues $ 7,235 Operating expenses 9,893 Loss from operations (2,658 ) Net loss (6,552 )
Carbon Appalachia [Member]
Schedule of Equity Method Investments [Line Items]
Schedule of selected historical financial data	(in thousands) As of December 31, 2017 Current assets $ 20,794 Total oil and gas properties, net $ 84,402 Current liabilities $ 18,207 Non-current liabilities $ 59,420 Total members’ equity $ 40,929 (in thousands) Period April 3, Revenues $ 31,584 Operating expenses 26,764 Income from operations 4,820 Net income 3,005

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Taxes [Abstract]
Summary of provision for income taxes	(in thousands) For the Year Ended December 31, 2017 2016 Current income tax (benefit) expense $ (74 ) $ - Deferred income tax (benefit) expense 7,080 (4,472 ) Change in valuation allowance (7,080 ) 4,472 Total income tax (benefit) expense $ (74 ) $ -
Summary of effective income tax rate differed from the statutory U.S. federal income tax rate	For the Year Ended December 31, 2017 2016 Federal income tax rate 35.0 % 35.0 % State income taxes, net of federal benefit 3.8 3.5 Permanent Differences (20.5 ) 1.1 Non-controlling interest in consolidated partnerships (0.8 ) (0.4 ) True-up of prior year depletion in excess of basis 1.1 .2 Stock-based compensation deficiency 3.1 (2.9 ) Rate changes of prior year deferred (1.8 ) 0.2 True-up of prior year deferred (4.5 ) (1.8 ) Effect of tax cuts and TCJA 91.0 - Increase in valuation allowance and other (107.7 ) (34.9 ) Total income tax expense (benefit) (1.1 )% - %
Summary of deferred tax assets and liabilities	(in thousands) As of December 31, 2017 2016 Deferred tax assets Net operating loss carryforwards $ 6,407 $ 8,274 Depletion carryforwards 1,934 2,740 Accrual and other 450 726 Stock-based compensation 476 968 Derivatives - 730 Asset retirement obligations 1,944 1,936 Property, plant and equipment 2,972 6,439 Total deferred tax assets 14,183 21,813 Deferred tax liability Interest in partnerships (790 ) (762 ) Derivative and other (57 ) - Less valuation allowance (13,336 ) (21,051 ) Net deferred tax asset $ - $ -

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2017
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, unvested, January 1, 2016 199,000 $ 10.37 Granted 134,501 5.40 Vested (64,668 ) 10.84 Forfeited (1,083 ) 6.20 Restricted stock awards, unvested, December 31, 2016 267,750 7.78 Granted 81,050 7.20 Vested (64,915 ) 8.38 Forfeited (13,050 ) 6.19 Restricted stock awards, unvested, December 31, 2017 270,835 $ 7.54
Restricted Performance Units [Member]
Class of Stock [Line Items]
Summary of Company's unvested restricted stock	Number of Shares Restricted performance units, unvested, January 1, 2016 314,311 Granted 80,000 Vested (84,480 ) Forfeited (13,520 ) Restricted performance units, unvested, December 31, 2016 296,311 Granted 60,050 Vested (80,000 ) Forfeited (17,550 ) Restricted performance units, unvested, December 31, 2017 258,811

Accounts Payable and Accrued 32

Accounts Payable and Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Accounts Payable and Accrued Liabilities [Abstract]
Summary of accounts payable and accrued liabilities	As of December 31, 2017 2016 Accounts payable $ 3,274 $ 2,315 Oil and gas revenue suspense 1,776 1,415 Gathering and transportation payables 497 468 Production taxes payable 214 113 Drilling advances received from joint venture partner 245 955 Accrued drilling costs - 4 Accrued lease operating costs 684 282 Accrued ad valorem taxes-current 1,054 1,552 Accrued general and administrative expenses 2,473 1,572 Accrued asset retirement obligation-current 380 - Accrued interest 247 184 Other liabilities 374 261 Total accounts payable and accrued liabilities $ 11,218 $ 9,121

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 Asset: Commodity derivatives $ - $ 225 $ - $ 225 Liabilities Warrant derivative liability $ - $ - $ 2,017 $ 2,017 December 31, 2016 Liability: Commodity derivatives $ - $ 1,932 $ - $ 1,932
Summary of changes in fair value of financial instruments	(in thousands) California Warrant Appalachia Warrant Total Balance, December 31, 2016 $ - $ - $ - Warrant liability 5,769 1,325 7,094 Unrealized (gain) loss included in warrant gain (3,752 ) 619 (3,133 ) Settlement of warrant liability - (1,944 ) (1,944 ) Balance, December 31, 2017 $ 2,017 $ - $ 2,017

Physical Delivery Contracts a34

Physical Delivery Contracts and Commodity Derivatives (Tables)	12 Months Ended
	Dec. 31, 2017
Physical Delivery Contracts and Commodity Derivatives [Abstract]
Schedule of swap derivative agreements	Natural Gas Swaps Natural Gas Collars Oil Swaps Weighted Weighted Weighted Average Average Price Average Year MMBtu Price (a) MMBtu Range (a) Bbl Price (b) 2018 3,390,000 $ 3.01 60,000 $3.00 - $3.48 63,000 $ 53.55 2019 2,596,000 $ 2.86 - - 48,000 $ 53.76 (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, 2017 2016 Commodity derivative contracts: Commodity derivative asset $ 215 $ - Other long-term assets $ 10 $ - Commodity derivative liabilities $ - $ 1,341 Commodity derivative liabilities, non-current $ - $ 591
Schedule of realized and unrealized gains and losses	(in thousands) For the year ended 2017 2016 Commodity derivative contracts: Settlement gains $ 770 $ 231 Unrealized gains (loss) 2,158 (2,490 ) Total settlement and unrealized gains (losses), net $ 2,928 $ (2,259 )
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: Commodity derivative $ 624 $ (409 ) $ 215 Other long-term assets 250 (240 ) 10 Total derivative assets $ 874 $ (649 ) $ 225 Commodity derivative liabilities: Commodity derivative $ (409 ) $ 409 $ - Commodity derivative: non-current (240 ) 240 - Total derivative liabilities $ (649 ) $ 649 $ - Net Gross Recognized Recognized Gross Fair Value Assets/ Amounts Assets/ Balance Sheet Classification Liabilities Offset Liabilities Commodity derivative assets: Commodity derivative $ - $ - $ - Other long-term assets 249 (249 ) - Total derivative assets $ 249 $ (249 ) $ - Commodity derivative liabilities: Commodity derivative $ 1,341 $ - $ 1,341 Commodity derivative: non-current 840 (249 ) 591 Total derivative liabilities $ 2,181 $ (249 ) $ 1,932

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies [Abstract]
Summary of firm transportation volumes and related demand charges	Period Dekatherms per day Demand Charges Jan 2018 - 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 Disclo36

Supplemental Cash Flow Disclosure (Tables)	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Disclosure [Abstract]
Summary of supplemental cash flow disclosures	(in thousands) For the Years Ended 2017 2016 Cash paid during the period for: Interest payments $ 967 $ 156 Income taxes - - Non-cash transactions: Increase in asset retirement obligations $ 2,402 $ 1,849 Increase (decrease) in accounts payable and accrued liabilities included in oil and gas properties $ 67 $ 1,099 Obligations assumed with acquisitions $ - $ 2,694 Equity method investments $ 5,674 $ -

Supplemental Financial Data -37

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
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	Company Company’s share of Carbon California Company’s share of Carbon Appalchia Total Oil Natural Gas Total Oil Natural Gas NGL Total Oil Natural Gas Total Oil Natural Gas NGL Total MBbls MMcf MMcfe MBbls MMcf (MBbls) MMcfe MBbls MMcf MMcfe MBbls MMcf (MBbls) MMcfe January 1, 2016 Proved reserves, beginning of year 598 29,958 33,546 - - - - - - - 598 29,958 - 33,546 Revisions of previous estimates 110 2,207 2,867 - - - - - - - 110 2,207 - 2,867 Extensions and discoveries - - - - - - - - - - - - - - Production (79 ) (2,823 ) (3,297 ) - - - - - - - (79 ) (2,823 ) - (3,297 ) Purchases of reserves in-place 253 44,923 46,441 - - - - - - - 253 44,923 - 46,441 Sales of reserves in-place - - - - - - - - - - - - - - December 31, 2016 882 74,265 79,557 - - - - - - - 882 74,265 - 79,557 Revisions of previous estimates 107 12,195 12,835 - - - - - - 107 12,195 - 12,837 Extensions and discoveries 16 138 232 - - - - - - 16 138 - 234 Production (2) (86 ) (4,896 ) (5,414 ) (25 ) (63 ) (4 ) (237 ) (2 ) (1,178 ) (1,328 ) (136 ) (4,984 ) (4 ) (5,824 ) Purchases of reserves in-place (1) - - - 1,650 3,075 231 14,361 74 91,935 101,835 3,300 4,725 231 25,911 Sales of reserves in-place - - - - - - - - - - - - December 31, 2017 919 81,702 87,210 1,625 3,012 227 14,124 72 90,757 100,507 4,169 86,339 227 112,715 (1) Related to Carbon Appalachia the purchases of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14, 2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; and November 1, 2017 through December 31, 2017, respectively. (2) Related to Carbon Appalachia, the net sales (in standard measure change) and production figures were calculated utilizing the same methodology as the purchase of reserves-in-place discussed above. 2017 2016 Oil Natural Gas (MMcf) NGL (MBbls) Total (MMcfe) Oil Natural Gas (MMcf) NGL Total (MMcfe) Company Proved developed reserves at: End of Year 903 81,702 - 87,120 851 74,265 - 79,557 Proved undeveloped reserves at: End of Year 16 - - 96 31 - - 186 Company’s share of Carbon California Proved developed reserves at: End of Year 1,006 2,194 163 9,208 - - - - Proved undeveloped reserves at: End of Year 619 818 63 4,910 - - - - Company’s share of Carbon Appalachia Proved developed reserves at: End of Year (1) (2) 72 90,757 - 91,189 - - - - Proved undeveloped reserves at: End of Year - - - - - - - - Total Proved developed reserves at: - End of Year 1,981 174,653 163 187,517 851 74,265 - 79,557 Proved undeveloped reserves at: - End of Year 635 818 63 5,006 31 - - 186 (1) Related to Carbon Appalachia the purchases of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14, 2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; and November 1, 2017 through December 31, 2017, respectively. (2) Related to Carbon Appalachia, the net sales (in standard measure change) and production figures were calculated utilizing the same methodology as the purchase of reserves-in-place discussed above. 2017 2016 Oil Natural Gas Total Oil Natural Gas Total MBbls MMcf MMcfe MBbls MMcf MMcfe Proved reserves, beginning of year 882 74,265 79,557 598 29,958 33,546 Revisions of previous estimates 107 12,195 12,837 110 2207 2867 Extensions and discoveries 16 138 234 - - - Production (86 ) (4,896 ) (5,412 ) (79 ) (2,823 ) (3,297 ) Purchases of reserves in-place (1) (2) - - - 253 44,923 46,441 Sales of reserves in-place - - - - - - Proved reserves, end of year 919 81,702 87,216 882 74,265 79,557 Proved developed reserves at: End of Year 903 81,702 87,120 882 74,265 79,371 Proved undeveloped reserves at: End of Year 16 - 96 31 - 186 (1) Related to Carbon Appalachia the purchases of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14, 2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; and November 1, 2017 through December 31, 2017, respectively. (2) Related to Carbon Appalachia, the net sales (in standard measure change) and production figures were calculated utilizing the same methodology as the purchase of reserves-in-place discussed above.
Summary of aggregate capitalized costs relating to oil and gas producing activities	2017 2016 (in thousands) Oil and gas properties Company Proved oil and gas properties $ 114,893 $ 112,579 Unproved properties not subject to depletion 1,947 1,999 Accumulated depreciation, depletion, amortization and impairment (80,715 ) (78,596 ) Total Company oil and gas properties, net $ 36,125 $ 35,982 Company’s share of Carbon California Proved oil and gas properties $ 7,635 $ - Unproved properties not subject to depletion 266 - Accumulated depreciation, depletion, amortization and impairment (208 ) - Total Company’s share of Carbon California oil and gas properties, net $ 7,693 $ - Company’s share of Carbon Appalachia Proved oil and gas properties $ 22,951 $ - Unproved properties not subject to depletion 485 - Accumulated depreciation, depletion, amortization and impairment (445 ) - Total Company’s share of Carbon Appalachia oil and gas properties, net $ 22,991 $ -
Summary of costs incurred in oil and gas property acquisition, exploration, and development activities	2017 2016 (in thousands) Company Property acquisition costs: Unevaluated properties $ 1 $ 97 Proved properties and gathering facilities 289 8,117 Development costs 952 360 Gathering facilities 43 42 Asset retirement obligation 2,309 1,849 Total costs incurred $ 3,594 $ 10,465 Company’s share of Carbon California Property acquisition costs: Unevaluated properties $ 266 $ - Proved properties and gathering facilities 7,682 - Development costs 412 - Gathering facilities 47 - Asset retirement obligation 483 - Total costs incurred $ 8,890 $ - Company’s share of Carbon Appalachia Property acquisition costs: Unevaluated properties $ 483 $ - Proved properties and gathering facilities 19,286 - Development costs 24 - Gathering facilities 2,544 - Asset retirement obligation 3,592 - Total costs incurred $ 25,929 $ -
Summary of company's investment in unproved properties	2017 2016 2015 (in thousands) Acquisition costs Company $ 1 $ 97 $ 1,849 Company’s share of Carbon California 266 - - Company’s share of Carbon Appalachia 485 - - Total acquisition costs $ 752 $ 97 $ 1,849
Summary of results of operations from oil and gas producing activities	2017 2016 Revenues Oil and gas sales, including commodity derivative gains and losses Company $ 22,439 $ 8,184 Company’s share of Carbon California $ 1,289 $ - Company’s share of Carbon Appalachia 5,273 - Total oil and gas sales, including commodity derivative gains and losses 29,001 8,184 Expenses: Production expenses Company 9,589 5,640 Company’s share of Carbon California 664 - Company’s share of Carbon Appalachia 1,522 - Total production expenses 11,775 5,640 Depletion expense Company 2,157 1,839 Company’s share of Carbon California 208 - Company’s share of Carbon Appalachia 445 - Total depletion expense 2,810 1,839 Accretion of asset retirement obligations Company 307 176 Company’s share of Carbon California 34 - Company’s share of Carbon Appalachia 54 - Total accretion of asset obligation 395 176 Impairment of oil and gas properties Company - 4,299 Company’s share of Carbon California - - Company’s share of Carbon Appalachia - - Total accretion of asset obligation - 4,299 Total expenses 14,979 11,954 Results of operations from oil and gas producing activities $ 14,021 $ (3,770 ) Depletion rate per Mcfe $ 0.47 $ 0.56
Summary of estimate of the current market value of the Company's proved reserves	(in thousands) December 31, 2017 2016 Company: Future cash inflows $ 283,664 $ 214,658 Future production costs (119,501 ) (103,252 ) Future development costs (210 ) (315 ) Future income taxes (35,482 ) (14,858 ) Future net cash flows 128,471 96,233 10% annual discount (71,389 ) (51,522 ) Standardized measure of discounted future net cash flows $ 57,082 $ 44,711 Company’s share of Carbon California Future cash inflows $ 97,841 $ - Future production costs (62,187 ) - Future development costs (5,809 ) - Future income taxes (2) - - Future net cash flows 29,845 - 10% annual discount (16,288 ) - Standardized measure of discounted future net cash flows $ 13,557 $ - Company’s share of Carbon Appalachia Future cash inflows (1) (4) $ 271,638 $ - Future production costs (1) (151,501 ) - Future development costs (1) (27 ) - Future income taxes (3) - - Future net cash flows 120,110 - 10% annual discount (73,890 ) - Standardized measure of discounted future net cash flows $ 46,220 $ - (1) Related to Carbon Appalachia the purchases of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14, 2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; November 1, 2017 through December 31, 2017, respectively. (2) Carbon California does not include the net changes in future income taxes because Carbon California is treated as a partnership for taxes and is not subject to federal income taxes. (3) Carbon Appalachia does not include the net changes in future income taxes because Carbon California is treated as a partnership for taxes and is not subject to federal income taxes (4) Related to Carbon Appalachia, the net sales (in standard measure change) and production figures was calculated utilizing the same methodology as the purchase of reserves-in-place discussed above.
Summary of discounted future cash flows relating to proved oil and gas reserves	December 31, Company Company’s Share of Carbon California Company’s Share of Carbon Appalachia Total (in thousands) Balance at January 1, 2016 Standardized measure of discounted future net cash flows, beginning of year $ 25,032 $ - $ - $ 25,032 Sales of oil and gas, net of production costs and taxes (4,804 ) - - (4,804 ) Price revisions (786 ) - - (786 ) Extensions, discoveries and improved recovery, less related costs - - - - Changes in estimated future development costs 248 - - 248 Development costs incurred during the period 102 - - 102 Quantity revisions 2,091 - - 2,091 Accretion of discount 2,503 - - 2,503 Net changes in future income taxes (4,633 ) - - (4,633 ) Purchases of reserves-in-place 26,776 - - 26,776 Sales of reserves-in-place - - - - Changes in production rate timing and other (1,818 ) - - (1,818 ) Balance at December 31, 2016 $ 44,711 $ - $ - $ 44,711 Sales of oil and gas, net of production costs and taxes (4) (10,038 ) (516 ) (1,240 ) (12,231 ) Price revisions 17,588 - - 17,588 Extensions, discoveries and improved recovery, less related costs 298 - - 298 Changes in estimated future development costs (324 ) - - (324 ) Development costs incurred during the period 804 - - 804 Quantity revisions 11,196 - - 11,196 Accretion of discount 4,471 - - 4,471 Net changes in future income taxes (2) (3) (7,425 ) - - (7,425 ) Purchases of reserves-in-place (1) - 14,073 47,460 61,533 Sales of reserves-in-place - - - - Changes in production rate timing and other (4,199 ) - - (4,199 ) Standardized measure of discounted future net cash flows, at December 31, 2017 $ 57,082 $ 13,557 $ 46,220 $ 116,422 (1) Related to Carbon Appalachia the purchases of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14, 2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; and November 1, 2017 through December 31, 2017, respectively. (2) Carbon California does not include the net changes in future income taxes because Carbon California is treated as a partnership for taxes and is not subject to federal income taxes. (3) Carbon Appalachia does not include the net changes in future income taxes because Carbon California is treated as a partnership for taxes and is not subject to federal income taxes. (4) Related to Carbon Appalachia, the net sales (in standard measure change) and production figures was calculated utilizing the same methodology as the purchase of reserves-in-place discussed above.
Summary of weighted averaged adjusted prices	2017 2016 Oil (per Bbl) $ 51.34 $ 40.40 Natural Gas (per Mcf) $ 2.98 $ 2.41

Organization (Details)

Organization (Details)	Feb. 01, 2018
Subsequent Event [Member]
Organization (Textual)
Aggregate sharing percentage, description	Exercised the California Warrant, resulting in our aggregate sharing percentage in Carbon California increasing from 17.81% to 56.40%.

Reverse Stock Split (Details)

Reverse Stock Split (Details) - shares	Mar. 15, 2017	Dec. 31, 2017	Dec. 31, 2016
Reverse Stock Split (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.
Common stock, shares authorized		10,000,000	10,000,000
Minimum [Member]
Reverse Stock Split (Textual)
Common stock, shares authorized		10,000,000
Maximum [Member]
Reverse Stock Split (Textual)
Common stock, shares authorized		200,000,000

Summary of Significant Accoun40

Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Concentration Risk [Line Items]
Percentages by purchaser	10.00%	10.00%
Purchaser A [Member]
Concentration Risk [Line Items]
Percentages by purchaser	23.00%	4.00%
Purchaser B [Member]
Concentration Risk [Line Items]
Percentages by purchaser	17.00%	15.00%
Purchaser C [Member]
Concentration Risk [Line Items]
Percentages by purchaser	12.00%	18.00%
Purchaser D [Member]
Concentration Risk [Line Items]
Percentages by purchaser	11.00%	16.00%
Purchaser E [Member]
Concentration Risk [Line Items]
Percentages by purchaser	8.00%	17.00%

Summary of Significant Accoun41

Summary of Significant Accounting Policies (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Summary of reconciliation of the ARO
Balance at beginning of year	$ 5,120	$ 3,095
Accretion expense	307	176
Change in estimate of cash outflow	2,402
Additions during period		1,849
Less: sale of wells	(92)
Reconciliation of the ARO, Gross	7,737	5,120
Less: ARO recognized as accounts payable and accrued liabilities	(380)	(114)
Balance at end of year	$ 7,357	$ 5,120

Summary of Significant Accoun42

Summary of Significant Accounting Policies (Details 2) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Summary of Significant Accounting Policies [Abstract]
Net income (loss)	$ 6,318	$ (12,406)
Less: warrant derivative gain	(3,133)
Diluted net income	$ 3,185	$ (12,406)
Basic weighted-average common shares outstanding during the period	5,662	5,468
Add dilutive effects of warrants and non-vested shares of restricted stock	790
Diluted weighted-average common shares outstanding during the period	6,452	5,468
Basic net (loss) income per common share	$ 1.12	$ (2.27)
Diluted net (loss) income per common share	$ 0.49	$ (2.27)

Summary of Significant Accoun43

Summary of Significant Accounting Policies (Details Textual)	12 Months Ended
	Dec. 31, 2017USD ($)Partnershipshares	Dec. 31, 2016USD ($)shares
Summary of Significant Accounting Policies (Textual)
Number of consolidated partnerships | Partnership	46
Cost method investments, additional information	The cost method of accounting is generally used for investments in affiliates in which we have less than 20% of the voting interests of a corporate affiliate or less than a 3% to 5% interest of a partnership or limited liability company and does not have significant influence.
Equity method investment, additional information	If we hold between 20% and 50% of the voting interest in non-consolidated corporate affiliates or generally greater than a 3% to 5% interest of a partnership or limited liability company and exert significant influence or control (e.g., through our influence with a seat on the board of directors or management of operations), the equity method of accounting is generally used to account for the investment. Investment in affiliates will increase or decrease by our share of the affiliates' profits or losses and such profits or losses are recognized in our consolidated statements of operations. If we hold greater than 50% of voting shares, we will generally consolidate the entities under the voting interest model.
Percentages by purchaser	10.00%	10.00%
Purchaser imbalance liability		$ 25,000
Ceiling test impairment cost		4,300,000
Accounts receivable included a deposit		$ 1.7
Oil and natural gas properties	$ 1,800,000
Purchaser imbalance receivable	$ 193,000
Discount factor, Percentage	10.00%
Income taxes, description	We are required to remeasure deferred income taxes at the lower 21% corporate rate as of the date the TCJA was signed into law even though the reduced rate is effective January 1, 2018.
Fair value of warrants accounted for gains	$ 3,100,000
Increase to estimated costs of retirement obligations	$ 2,400,000
Purchaser A [Member]
Summary of Significant Accounting Policies (Textual)
Percentages by purchaser	23.00%	4.00%
Warrant [Member]
Summary of Significant Accounting Policies (Textual)
Anti-dilutive earnings per shares | shares	519,000	13,000
Restricted Stock [Member]
Summary of Significant Accounting Policies (Textual)
Anti-dilutive earnings per shares | shares	289,000	268,000
Restricted Performance Units [Member]
Summary of Significant Accounting Policies (Textual)
Common stock equivalent restricted to future contingencies | shares	271,000	296,000
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
Retirement obligations estimated costs	$ 20,000
Maximum [Member]
Summary of Significant Accounting Policies (Textual)
Other property and equipment, useful life	7 years
Retirement obligations estimated costs	$ 30,000

Acquisitions and Divestitures44

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 Divestitures45

Acquisitions and Divestitures (Details 1) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Acquisitions and Divestitures [Abstract]
Revenue		$ 13,963
Net income (loss) income before non-controlling interests		(6,825)
Net income (loss) attributable to non-controlling interests	$ 81	(413)
Net income (loss) attributable to controlling interests		$ (6,412)
Net income (loss) per share (basic)		$ (1.17)
Net income (loss) per share (diluted)		$ (1.17)

Acquisitions and Divestitures46

Acquisitions and Divestitures (Details Textual) - USD ($)	Dec. 31, 2016	Oct. 31, 2016
Acquisitions and Divestitures (Textual)
Transaction and due diligence costs	$ 501,000
Purchase Agreement [Member]
Acquisitions and Divestitures (Textual)
Purchase price of acquired assets		$ 9,000,000

Property and Equipment (Details

Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Oil and gas properties:
Accumulated depreciation, depletion, amortization and impairment	$ (80,715)	$ (78,559)
Net oil and gas properties	36,125	35,211
Furniture and fixtures, computer hardware and software, and other equipment	1,758	990
Accumulated depreciation and amortization	(1,021)	(665)
Net other property and equipment	737	325
Total property and equipment, net	36,862	35,536
Proved oil and gas properties [Member]
Oil and gas properties:
Oil and gas properties, gross	114,893	111,771
Unproved properties not subject to depletion [Member]
Oil and gas properties:
Oil and gas properties, gross	$ 1,947	$ 1,999

Property and Equipment (Detai48

Property and Equipment (Details 1) - Unproved properties not subject to depletion [Member] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Oil and gas properties, gross	$ 1,947	$ 1,999
Indiana [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Oil and gas properties, gross	432	431
Illinois [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Oil and gas properties, gross	136	298
Kentucky [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Oil and gas properties, gross	915	750
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	$ 398	$ 454

Property and Equipment (Detai49

Property and Equipment (Details Textual)	12 Months Ended
	Dec. 31, 2017USD ($)Per_Mcfe	Dec. 31, 2016USD ($)Per_Mcfe
Property and Equipment (Textual)
Proved property	$ 52,000	$ 1,300,000
Capitalized overhead	66,000	562,000
Depletion expense related to oil and gas properties	$ 2,200,000	$ 1,800,000
Depletion expense related to oil and gas properties (in dollars per Mcfe) | Per_Mcfe	0.40	0.56
Depreciation and amortization expense	$ 387,000	$ 114,000
Unproved properties not subject to depletion [Member]
Property and Equipment (Textual)
Depletion expense related to oil and gas properties	$ 1,900,000	$ 2,000,000

Investments in Affiliates (Deta

Investments in Affiliates (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016
Schedule of Equity Method Investments [Line Items]
Current assets	$ 8,080	$ 8,080	$ 5,783
Total oil and gas properties, net	36,862	36,862	35,536
Current liabilities	11,345	11,345	11,023
Non-current liabilities	32,168	32,168	22,716
Total members' equity	14,655	14,655	7,108
Revenues		22,473	8,195
Operating expenses		3,208	(12,518)
Net income		6,318	$ (12,406)
Carbon California [Member]
Schedule of Equity Method Investments [Line Items]
Current assets	3,968	3,968
Total oil and gas properties, net	43,458	43,458
Current liabilities	6,899	6,899
Non-current liabilities	23,279	23,279
Total members' equity	18,549	$ 18,549
Revenues	7,235
Operating expenses	9,893
Loss from operations	(2,658)
Net income	$ (6,552)

Investments in Affiliates (De51

Investments in Affiliates (Details 1) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
April 2017 [Member]
Schedule of Equity Method Investments [Line Items]
Capital Contribution	$ 240
Resulting Class A Units (%)	2.00%
Resulting Sharing %	2.98%
August 2017 [Member]
Schedule of Equity Method Investments [Line Items]
Capital Contribution	$ 3,710
Resulting Class A Units (%)	15.20%
Resulting Sharing %	16.04%
September 2017 [Member]
Schedule of Equity Method Investments [Line Items]
Capital Contribution	$ 2,920
Resulting Class A Units (%)	18.55%
Resulting Sharing %	19.37%
November 2017 [Member]
Schedule of Equity Method Investments [Line Items]
Capital Contribution	Warrant exercise
Resulting Class A Units (%)	26.50%
Resulting Sharing %	27.24%

Investments in Affiliates (De52

Investments in Affiliates (Details 2) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016
Schedule of Equity Method Investments [Line Items]
Current assets	$ 8,080	$ 8,080	$ 5,783
Total oil and gas properties, net	36,862	36,862	35,536
Current liabilities	11,345	11,345	11,023
Non-current liabilities	32,168	32,168	22,716
Total members' equity	14,655	14,655	7,108
Revenues		22,473	8,195
Operating expenses		3,208	(12,518)
Net income		6,318	$ (12,406)
Carbon Appalachia [Member]
Schedule of Equity Method Investments [Line Items]
Current assets	20,794	20,794
Total oil and gas properties, net	84,402	84,402
Current liabilities	18,207	18,207
Non-current liabilities	59,420	59,420
Total members' equity	40,929	$ 40,929
Revenues	31,584
Operating expenses	26,764
Income from operations	4,820
Net income	$ 3,005

Investments in Affiliates (De53

Investments in Affiliates (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Schedule of Equity Method Investments [Line Items]
Beginning balance, Investments	$ 668
Investment in affiliates gain (loss)	1,128	$ (17)
Cash distributions	(68)
Cash contributions	6,865
Class B Units issuance	2,778
Appalachia Warrant exercise	2,896
Ending balance, Investments	14,267	668
Carbon California [Member]
Schedule of Equity Method Investments [Line Items]
Beginning balance, Investments
Investment in affiliates gain (loss)
Cash distributions
Cash contributions
Class B Units issuance	1,854
Appalachia Warrant exercise
Ending balance, Investments	1,854
Carbon Appalachia [Member]
Schedule of Equity Method Investments [Line Items]
Beginning balance, Investments
Investment in affiliates gain (loss)	1,090
Cash distributions
Cash contributions	6,865
Class B Units issuance	924
Appalachia Warrant exercise	2,896
Ending balance, Investments	11,775
CCGGC [Member]
Schedule of Equity Method Investments [Line Items]
Beginning balance, Investments	118
Investment in affiliates gain (loss)	38
Cash distributions	(68)
Cash contributions
Class B Units issuance
Ending balance, Investments	88	118
Sullivan [Member]
Schedule of Equity Method Investments [Line Items]
Beginning balance, Investments	550
Investment in affiliates gain (loss)
Cash distributions
Cash contributions
Class B Units issuance
Ending balance, Investments	$ 550	$ 550

Investments in Affiliates (De54

Investments in Affiliates (Details Textual) - USD ($) $ in Thousands	Feb. 01, 2018	Feb. 15, 2017	Dec. 31, 2017	Dec. 31, 2016
Investments in Affiliates (Textual)
Other income			$ 34	$ 11
Carbon California [Member]
Investments in Affiliates (Textual)
Business acquisitions, description		(i) Issued and sold Class A Units to Yorktown and Prudential for an aggregate cash consideration of $22.0 million, (ii) entered into a Note Purchase Agreement (the "Note Purchase Agreement") with Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America for the issuance and sale of up to $25.0 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 Prudential for the issuance and sale of $10.0 million of Senior Subordinated Notes (the "Subordinated Notes") due February 15, 2024. We are not a guarantor of the Senior Revolving Notes or the Subordinate Notes.
Percentage of interest			17.80%
Carbon California [Member] | Warrant [Member]
Investments in Affiliates (Textual)
Estimated fair market value of warrant			$ 5,800
Carbon California [Member] | Class B Units [Member]
Investments in Affiliates (Textual)
Acquired interest		17.81%
Estimated fair market value of warrant			1,900
Carbon California [Member] | California Warrant [Member]
Investments in Affiliates (Textual)
Estimated fair market value of warrant			2,000
Other income			$ 3,800
Carbon California [Member] | Note Purchase Agreement and the Securities Purchase Agreement [Member]
Investments in Affiliates (Textual)
Business acquisitions, description		(i) Senior Revolving Notes in the principal amount of $10.0 million and (ii) Subordinated Notes in the original principal amount of $10.0 million. The maximum principal amount available under the Senior Revolving Notes is based upon the borrowing base attributable to Carbon California's proved oil and gas reserves which is to be determined at least semi-annually. The current borrowing base is $15.0 million, of which $11.0 million is outstanding as of December 31, 2017.
Carbon California [Member] | Subsequent Events [Member]
Investments in Affiliates (Textual)
Voting and profits interests, percentage	17.81%
Carbon California [Member] | Subsequent Events [Member] | California Warrant [Member]
Investments in Affiliates (Textual)
Voting and profits interests, percentage	56.41%
Carbon California [Member] | Subsequent Events [Member] | Yorktown [Member]
Investments in Affiliates (Textual)
Voting and profits interests, percentage	38.59%
Carbon California [Member] | Subsequent Events [Member] | Prudential [Member]
Investments in Affiliates (Textual)
Voting and profits interests, percentage	43.59%

Investments in Affiliates (De55

Investments in Affiliates (Details Textual 1) - USD ($)	Nov. 01, 2017	Sep. 29, 2017	Aug. 15, 2017	Apr. 03, 2017	Dec. 31, 2017	Dec. 31, 2017	Feb. 15, 2017	Dec. 31, 2016
Investments in Affiliates (Textual)
Credit facility purchase price							$ 15,000,000
Fair value of warrant						$ 3,100,000
Investments in affiliates					$ 14,267,000	$ 14,267,000		$ 668,000
Yorktown [Member] | Class A Units [Member]
Investments in Affiliates (Textual)
Investments in affiliates	$ 2,900,000
Carbon Appalachia [Member]
Investments in Affiliates (Textual)
Ownership interest, percentage					1.00%	1.00%
Percentage of interest				75.00%
Fair value of warrant	$ 1,900,000
Equity method, net gain					$ 1,100,000
Investments in affiliates					$ 11,775,000	$ 11,775,000
Carbon Appalachia [Member] | Warrant [Member]
Investments in Affiliates (Textual)
Fair value of warrant						619,000
Carbon Appalachia [Member] | Senior Revolving Notes [Member]
Investments in Affiliates (Textual)
Senior subordinated notes		$ 100,000,000
Current borrowing base		$ 50,000,000
Revolving credit facility, description		Redeterminations as of April 1 and October 1 each year and the addition of East West Bank as a participating lender.
Outstanding under the credit facility						$ 38,000,000
Carbon Appalachia [Member] | Drilling [Member]
Investments in Affiliates (Textual)
Percentage of interest				100.00%
Carbon Appalachia [Member] | Class A Units [Member]
Investments in Affiliates (Textual)
Ownership interest, percentage	7.95%
Carbon Appalachia [Member] | Class B Units [Member]
Investments in Affiliates (Textual)
Ownership interest, percentage	26.50%
Carbon Appalachia [Member] | Class C Units [Member]
Investments in Affiliates (Textual)
Ownership interest, percentage	100.00%
Carbon Appalachia [Member] | Nytis LLC [Member]
Investments in Affiliates (Textual)
Percentage of interest				25.00%
Carbon Appalachia [Member] | Carbon Appalachia LLC Agreement [Member]
Investments in Affiliates (Textual)
Equity commitment				$ 2,000,000
Percentage of interest					14.70%	14.70%
Senior subordinated notes				100,000,000
Initial borrowing				10,000,000
Purchase price of acquired assets		$ 41,300,000	$ 21,500,000	20,000,000
Credit facility purchase price				8,500,000
Business acquisitions, description			The closing of the Enervest Acquisition, the borrowing base of its existing credit facility with LegacyTexas Bank increased to $22.0 million and Carbon Appalachia Enterprises borrowed $8.0 million from its existing credit facility with LegacyTexas Bank. Carbon Appalachia received equity funding in the amount of $14.0 million from its members, including $3.7 million from us. The contributed funds and funds drawn from the credit facility were used to pay the purchase price.			Cabot Acquisition described above, Carbon Appalachia Enterprises borrowed $20.4 million from its credit facility. Carbon Appalachia received equity funding in the amount of $11.0 million from its members, including $2.9 million from us. The contributed funds and funds drawn from the credit facility were used to pay the purchase price.
Carbon Appalachia [Member] | Carbon Appalachia LLC Agreement [Member] | Warrant [Member]
Investments in Affiliates (Textual)
Fair value of warrant				1,300,000
Carbon Appalachia [Member] | Carbon Appalachia LLC Agreement [Member] | Minimum [Member]
Investments in Affiliates (Textual)
Equity commitment			$ 2,000,000
Percentage of interest			2.00%
Carbon Appalachia [Member] | Carbon Appalachia LLC Agreement [Member] | Maximum [Member]
Investments in Affiliates (Textual)
Equity commitment			$ 23,600,000
Percentage of interest			26.50%
Carbon Appalachia [Member] | Carbon Appalachia LLC Agreement [Member] | Class A Units [Member]
Investments in Affiliates (Textual)
Equity commitment				$ 240,000
Acquired interest				2.00%
Ownership interest, percentage					27.24%	27.24%
Percentage of interest					10.00%	10.00%
Investment in cash and unevaluated property					$ 6,900,000	$ 6,900,000
Carbon Appalachia [Member] | Carbon Appalachia LLC Agreement [Member] | Class B Units [Member]
Investments in Affiliates (Textual)
Ownership interest, percentage				14.70%	27.24%	27.24%
Percentage of interest					10.00%	10.00%
Fair value of warrant				$ 924,000
Carbon Appalachia [Member] | Carbon Appalachia LLC Agreement [Member] | Class C Units [Member]
Investments in Affiliates (Textual)
Equity commitment			$ 100,000,000
Acquired interest			1.00%	1.00%
Ownership interest, percentage			26.50%		27.24%	27.24%
Percentage of interest					10.00%	10.00%
Investment in cash and unevaluated property					$ 6,900,000	$ 6,900,000
Carbon Appalachia [Member] | Yorktown [Member] | Warrant [Member]
Investments in Affiliates (Textual)
Warrant issuance	432,051
Carbon Appalachia [Member] | Yorktown and Old Ironsides Energy, LLC [Member]
Investments in Affiliates (Textual)
Equity commitment				$ 100,000,000	37,000,000	37,000,000
Sullivan Energy [Member]
Investments in Affiliates (Textual)
Investment in cash and unevaluated property					30,000	30,000
Investments in affiliates					$ 30,000	$ 30,000

Bank Credit Facility (Details)

Bank Credit Facility (Details) - USD ($)	3 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Mar. 28, 2018	Mar. 30, 2017
Bank Credit Facility (Textual)
Senior secured asset-based revolving credit facility		$ 7,210,000	$ 16,937,000
Additional borrowing capacity available		$ 860,000
Effective borrowing rate (as a percent)		5.67%
Outstanding borrowings		$ 22,100,000
Other long-term assets value		700,000
Deferred issuance costs		484,000	596,000
Amortized interest expense		176,000	51,000
Carbon California [Member]
Bank Credit Facility (Textual)
Proceeds from contributed capital	$ 6,600,000
Legacy Texas Bank [Member]
Bank Credit Facility (Textual)
Senior secured asset-based revolving credit facility			$ 100,000,000
Bank credit facility, terms			4 years
Minimum [Member]
Bank Credit Facility (Textual)
Line of credit facility maximum borrowing capacity					$ 17,000,000
Maximum [Member]
Bank Credit Facility (Textual)
Line of credit facility maximum borrowing capacity					23,000,000
Line of Credit [Member]
Bank Credit Facility (Textual)
Borrowing base amount		23,000,000			$ 23,000,000
Line of credit facility maximum borrowing capacity		$ 100,000,000
Variable interest rate basis, description		(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 our option. The actual margin percentage is dependent on the credit facility utilization percentage. We are obligated to pay certain fees and expenses in connection with the credit facility, including a commitment fee for any unused amounts of 0.50%.
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]
Bank Credit Facility (Textual)
Borrowing base amount				$ 25,000,000

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Summary of provision for income taxes
Current income tax (benefit) expense	$ (74)
Deferred income tax (benefit) expense	7,080	(4,472)
Change in valuation allowance	(7,080)	4,472
Total income tax (benefit) expense	$ (74)

Income Taxes (Details 1)

Income Taxes (Details 1)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
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	3.80%	3.50%
Permanent Differences	(20.50%)	1.10%
Non-controlling interest in consolidated partnerships	(0.80%)	(0.40%)
True-up of prior year depletion in excess of basis	1.10%	0.20%
Stock-based compensation deficiency	3.10%	(2.90%)
Rate changes of prior year deferred	(1.80%)	0.20%
True-up of prior year deferred	(4.50%)	(1.80%)
Effect of tax cuts and TCJA	91.00%
Increase in valuation allowance and other	(107.70%)	(34.90%)
Total income tax expense	(1.10%)

Income Taxes (Details 2)

Income Taxes (Details 2) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred tax assets
Net operating loss carryforwards	$ 6,407	$ 8,274
Depletion carryforwards	1,934	2,740
Accrual and other	450	726
Stock-based compensation	476	968
Derivatives		730
Asset retirement obligations	1,944	1,936
Property, plant and equipment	2,972	6,439
Total deferred tax assets	14,183	21,813
Deferred tax liability
Interest in partnerships	(790)	(762)
Derivative and other	(57)	0
Less valuation allowance	(13,336)	(21,051)
Net deferred tax asset

Income Taxes (Details Textual)

Income Taxes (Details Textual) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Income Taxes (Textual)
Net operating losses	$ 21.4
NOL carryforwards expire, description	The federal NOLs expire in various years through 2037.
Federal deferred tax balance re-measurement, description	We have remeasured certain federal deferred tax assets and liabilities based upon the rates at which they are expected to reverse in the future, which is generally 21.0% percent. The provisional amount recognized related to the remeasurement of its federal deferred tax balance was $6.0 million, which was subject to a valuation allowance at December 31, 2017.
Tax years examination, description	The 2014 through 2017 tax years generally remain subject to examination by federal and state tax authorities.

Stockholders' Equity (Details)

Stockholders' Equity (Details) - Restricted Stock [Member] - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Stockholders' Equity [Line Items]
Restricted stock awards/Restricted performance units, unvested, Beginning Balance, Number of Shares	267,750	199,000
Granted, Number of Shares	81,050	134,501
Vested, Number of Shares	(64,915)	(64,668)
Forfeited, Number of Shares	(13,050)	(1,083)
Restricted stock awards/Restricted performance units, unvested, Ending Balance, Number of Shares	270,835	267,750
Restricted stock awards, unvested, Beginning Balance, Weighted Avg Grant Date Fair Value	$ 7.78	$ 10.37
Granted, Weighted Avg Grant Date Fair Value	7.20	5.40
Vested, Weighted Avg Grant Date Fair Value	8.38	10.84
Forfeited, Weighted Avg Grant Date Fair Value	6.19	6.20
Restricted stock awards, unvested, Ending Balance, Weighted Avg Grant Date Fair Value	$ 7.54	$ 7.78

Stockholders' Equity (Details 1

Stockholders' Equity (Details 1) - Restricted Performance Units [Member] - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Stockholders' Equity [Line Items]
Restricted stock awards/Restricted performance units, unvested, Beginning Balance, Number of Shares	296,311	314,311
Granted, Number of Shares	60,050	80,000
Vested, Number of Shares	(80,000)	(84,480)
Forfeited, Number of Shares	(17,550)	(13,520)
Restricted stock awards/Restricted performance units, unvested, Ending Balance, Number of Shares	258,811	296,311

Stockholders' Equity (Details T

Stockholders' Equity (Details Textual) - USD ($)	Mar. 15, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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.
Common stock, shares authorized		10,000,000	10,000,000
Common stock, par value (in dollars per share)		$ 0.01	$ 0.01
Common stock, shares issued		6,005,633	5,482,673
Common stock, shares outstanding		6,005,633	5,482,673
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
Grant date fair value		$ 7.20	$ 5.40	$ 8	$ 11.80
Maximum [Member]
Stockholders' Equity (Textual)
Common stock, shares authorized		200,000,000
Minimum [Member]
Stockholders' Equity (Textual)
Common stock, shares authorized		10,000,000
Restricted Stock Units (RSUs) [Member]
Stockholders' Equity (Textual)
Unrecognized compensation cost		$ 1,100,000
Compensation costs for restricted stock grants		$ 664,000	$ 742,000
Expected period of recognition of unrecognized compensation costs		6 years 3 months 18 days
Number of shares of unvested restricted stock granted		432,000
Restricted Stock [Member]
Stockholders' Equity (Textual)
Vesting, percentage		7.95%
Issuance of common stock in addition to restricted stock		432,000
Restricted Performance Units [Member]
Stockholders' Equity (Textual)
Unrecognized compensation cost		$ 2,100,000
Compensation cost recognized		$ 442,000	$ 1,200,000
Number of shares of unvested restricted stock granted		60,050	80,000
Carbon Stock Incentive Plans [Member] | Officer [Member]
Stockholders' Equity (Textual)
Stock incentive plan, common stock shares authorized		1,100,000

Accounts Payable and Accrued 64

Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounts Payable and Accrued Liabilities [Abstract]
Accounts payable	$ 3,274	$ 2,315
Oil and gas revenue suspense	1,776	1,415
Gathering and transportation payables	497	468
Production taxes payable	214	113
Drilling advances received from joint venture partner	245	955
Accrued drilling costs		4
Accrued lease operating costs	684	282
Accrued ad valorem taxes-current	1,054	1,552
Accrued general and administrative expenses	2,473	1,572
Accrued asset retirement obligation-current	380
Accrued interest	247	184
Other liabilities	374	261
Total accounts payable and accrued liabilities	$ 11,218	$ 9,121

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Asset:
Commodity derivatives	$ 225
Liabilities
Warrant derivative liability	2,017
Liabilitiy:
Commodity derivatives	2,017
Fair Value Measurements [Member] | Level 1 [Member]
Asset:
Commodity derivatives
Liabilities
Warrant derivative liability
Liabilitiy:
Commodity derivatives
Fair Value Measurements [Member] | Level 2 [Member]
Asset:
Commodity derivatives	225
Liabilities
Warrant derivative liability
Liabilitiy:
Commodity derivatives		1,932
Fair Value Measurements [Member] | Level 3 [Member]
Asset:
Commodity derivatives
Liabilities
Warrant derivative liability	$ 2,017
Liabilitiy:
Commodity derivatives

Fair Value Measurements (Deta66

Fair Value Measurements (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured On Recurring and Nonrecurring Basis [Line Items]
Balance, December 31, 2016
Warrant liability	2,017
Unrealized (gain) loss included in warrant gain	2,158	$ (2,490)
Settlement of warrant liability	(1,944)
Balance, December 31, 2017	2,017
Level 3 [Member] | California Warrant [Member]
Fair Value, Assets and Liabilities Measured On Recurring and Nonrecurring Basis [Line Items]
Balance, December 31, 2016
Warrant liability	5,769
Unrealized (gain) loss included in warrant gain	(3,752)
Settlement of warrant liability
Balance, December 31, 2017	2,017
Level 3 [Member] | Appalachia Warrant [Member]
Fair Value, Assets and Liabilities Measured On Recurring and Nonrecurring Basis [Line Items]
Balance, December 31, 2016
Warrant liability	1,325
Unrealized (gain) loss included in warrant gain	619
Settlement of warrant liability	(1,944)
Balance, December 31, 2017

Fair Value Measurements (Deta67

Fair Value Measurements (Details Textual) - USD ($)	Apr. 03, 2017	Feb. 15, 2017	Dec. 31, 2017	Dec. 31, 2016
Fair Value Measurements (Textual)
Asset retirement obligation			$ 2,400,000
Asset retirement obligation ,description			The estimated timing of reclamation ranging from one to 75 years based on estimates from reserve engineers; an inflation rate of 1.92%; and a credit adjusted risk-free rate of 7.24%, which takes into account our credit risk and the time value of money.
Class A Units [Member] | California Warrant [Member]
Fair Value Measurements (Textual)
Fair value of warrant			$ 2,000,000
Exercise price			$ 7.20
Volatility rate			45.00%
Risk free rate			2.10%
Term			6 years 4 months 24 days
Class A Units [Member] | California Warrant [Member] | Maximum [Member]
Fair Value Measurements (Textual)
Fair value of warrant			$ 30,000
Class A Units [Member] | California Warrant [Member] | Minimum [Member]
Fair Value Measurements (Textual)
Fair value of warrant			$ 20,000
Class A Units [Member] | Appalachia Warrant [Member]
Fair Value Measurements (Textual)
Exercise price			$ 7.20
Volatility rate			45.00%
Risk free rate			2.10%
Term			6 years 6 months
Level 3 [Member]
Fair Value Measurements (Textual)
Asset retirement obligation			$ 2,400,000	$ 1,800,000
Level 3 [Member] | California Warrant [Member]
Fair Value Measurements (Textual)
Fair value of warrant		$ 5,800,000
Exercise price		$ 7.20
Volatility rate		41.80%
Risk free rate		2.30%
Term		7 years
Level 3 [Member] | Appalachia Warrant [Member]
Fair Value Measurements (Textual)
Fair value of warrant	$ 1,300,000
Exercise price	$ 7.20
Volatility rate	39.30%
Risk free rate	2.10%
Term	7 years

Physical Delivery Contracts a68

Physical Delivery Contracts and Commodity Derivatives (Details)	Dec. 31, 2017USD_MMBtu$ / shares
2018 [Member] | Natural Gas [Member]
Derivative agreements details:
Quantity | USD_MMBtu	3,390,000
Weighted Average Price | $ / shares	$ 3.01	[1]
2018 [Member] | Oil [Member]
Derivative agreements details:
Quantity | USD_MMBtu	63,000
Weighted Average Price | $ / shares	$ 53.55	[2]
2018 [Member] | Natural Gas Collars [Member]
Derivative agreements details:
Quantity | USD_MMBtu	60,000
2018 [Member] | Natural Gas Collars [Member] | Minimum [Member]
Derivative agreements details:
Weighted Average Price | $ / shares	$ 3	[1]
2018 [Member] | Natural Gas Collars [Member] | Maximum [Member]
Derivative agreements details:
Weighted Average Price | $ / shares	$ 3.48	[1]
2019 [Member] | Natural Gas [Member]
Derivative agreements details:
Quantity | USD_MMBtu	2,596,000
Weighted Average Price | $ / shares	$ 2.86	[1]
2019 [Member] | Oil [Member]
Derivative agreements details:
Quantity | USD_MMBtu	48,000
Weighted Average Price | $ / shares	$ 53.76	[2]
2019 [Member] | Natural Gas Collars [Member]
Derivative agreements details:
Quantity | USD_MMBtu
[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 a69

Physical Delivery Contracts and Commodity Derivatives (Details 1) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Commodity derivative contracts:
Commodity derivative asset	$ 215
Other long-term assets	10
Commodity derivative liabilities		1,341
Commodity derivative liabilities, non-current		$ 591

Physical Delivery Contracts a70

Physical Delivery Contracts and Commodity Derivatives (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Commodity derivative contracts:
Unrealized gains (loss)	$ 2,158	$ (2,490)
Commodity derivative contracts [Member]
Commodity derivative contracts:
Settlement gains	770	231
Unrealized gains (loss)	2,158	(2,490)
Total settlement and unrealized gain (losses), net	$ 2,928	$ (2,259)

Physical Delivery Contracts a71

Physical Delivery Contracts and Commodity Derivatives (Details 3) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Commodity derivative assets:
Commodity derivative asset	$ 215
Other long-term assets	10
Total derivative assets	225
Commodity derivative liabilities:
Commodity derivative liabilities		1,341
Commodity derivative liability		591
Total derivative liabilities	2,017
Gross Recognized Assets/Liabilities [Member]
Commodity derivative assets:
Commodity derivative asset	624
Other long-term assets	250	249
Total derivative assets	874	249
Commodity derivative liabilities:
Commodity derivative liabilities	(409)	1,341
Commodity derivative liability	(240)	840
Total derivative liabilities	(649)	2,181
Gross Amounts Offset [Member]
Commodity derivative assets:
Commodity derivative asset	(409)
Other long-term assets	(240)	(249)
Total derivative assets	(649)	(249)
Commodity derivative liabilities:
Commodity derivative liabilities	409
Commodity derivative liability	240	(249)
Total derivative liabilities	649	(249)
Net Recognized Fair Value Assets/Liabilities [Member]
Commodity derivative assets:
Commodity derivative asset	215
Other long-term assets	10
Total derivative assets	225
Commodity derivative liabilities:
Commodity derivative liabilities		1,341
Commodity derivative liability		591
Total derivative liabilities		$ 1,932

Commitments and Contingencies72

Commitments and Contingencies (Details)	12 Months Ended
	Dec. 31, 2017Per_McfePartnership
Jan 2018 - Apr 2018 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Partnership	5,530
Jan 2018 - Apr 2018 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand charges (in dollars per dekatherm)	0.20
Jan 2018 - 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 Contingencies73

Commitments and Contingencies (Details Textual)	12 Months Ended
	Dec. 31, 2017USD ($)ft²	Dec. 31, 2016USD ($)
Commitments and Contingencies (Textual)
Liability related to firm transportation contracts assumed	$ 261,000
Rental expenses	255,000	$ 220,000
Minimum lease payments 2018	436,000
Minimum lease payments 2019	390,000
Minimum lease payments 2020	382,000
Minimum lease payments 2021	275,000
Minimum lease payments 2022	270,000
Capital commitment	6,900,000
Estimated loss of suspended revenue	250,000
Class A [Member]
Commitments and Contingencies (Textual)
Capital commitment	$ 23,600,000
Colorado [Member]
Commitments and Contingencies (Textual)
Office space | ft²	8,500
Operating lease expiration date	Dec. 31, 2023
Kentucky [Member]
Commitments and Contingencies (Textual)
Office space | ft²	5,300
Operating lease expiration date	Dec. 31, 2019
California [Member]
Commitments and Contingencies (Textual)
Office space | ft²	9,500
Operating lease expiration date	Dec. 31, 2021

Retirement Savings Plan (Detail

Retirement Savings Plan (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Retirement Savings Plan [Abstract]
Matching percentage under retirement savings plan	6.00%
401(K) contributions and related administrative expenses	$ 175,000	$ 99,000

Supplemental Cash Flow Disclo75

Supplemental Cash Flow Disclosure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Cash paid during the period for:
Interest payments	$ 967	$ 156
Income taxes
Non-cash transactions:
Increase in asset retirement obligations	2,402	1,849
Increase (decrease) in accounts payable and accrued liabilities included in oil and gas properties	67	1,099
Obligations assumed with acquisitions		2,694
Equity method investments	$ 5,674

Related Parties (Details)

Related Parties (Details) - USD ($)	Apr. 03, 2017	Feb. 15, 2017	Dec. 31, 2017
Carbon California [Member]
Related Parties (Textual) [Abstract]
Releted partied Class B and C units received			5,077
Related party Class B units, percentage			17.81%
Due from related party			$ 300,000
Related party accounts payable		$ 600,000
One-time reimbursement		500,000
Total management reimbursements		$ 1,000,000
Carbon Appalachia [Member]
Related Parties (Textual) [Abstract]
Releted partied Class B and C units received			1,000
Related party Class B units, percentage			1.00%
Due from related party			$ 1,800,000
Accounts receivable related party			579,000
One-time reimbursement	$ 75,000		1,600,000
Carbon Appalachia One [Member]
Related Parties (Textual) [Abstract]
Releted partied Class B and C units received	121
One-time reimbursement	$ 300,000
Ohio Basic Minerals [Member]
Related Parties (Textual) [Abstract]
One-time reimbursement			$ 96,000

Subsequent Events (Details)

Subsequent Events (Details) - Subsequent Events [Member] - USD ($) $ in Millions	Feb. 01, 2018	Mar. 27, 2018	Mar. 28, 2018
Subsequent Event [Line Items]
Exercisable warrant of company's common stock	1,527,778
Subsequent events, description	Exercised the California Warrant, resulting in our aggregate sharing percentage in Carbon California increasing from 17.81% to 56.40%.
Borrowing base amount			$ 25
Minimum liquidity covenant, description		Pursuant to the credit agreement amendment entered into on March 27, 2018, we are subject to a minimum liquidity covenant of $750,000.
Class A Units [Member]
Subsequent Event [Line Items]
Exercisable warrant of company's common stock	11,000
Subsequent events, description	As a result, our ownership of Class A Units of Carbon California increased from zero to 11,000 or from 0% to 46.96% (which equates to a sharing percentage interest of 38.59%). We also hold all of the Class B Units of Carbon California which represent a sharing percentage of 17.81%, resulting in our aggregate sharing percentage increasing from 17.81% to 56.40%.

Supplemental Financial Data -78

Supplemental Financial Data - Oil and Gas Producing Activities (Unaudited) (Details)		12 Months Ended
		Dec. 31, 2017MMcfMMBbls		Dec. 31, 2016MMcfMMBbls
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year		79,557		33,546
Revisions of previous estimates		12,837		2,867
Extensions and discoveries		234
Production		(5,824)	[1]	(3,297)
Purchases of reserves in-place		25,911	[2]	46,441
Sales of reserves in-place
Proved reserves, end of year		112,715		79,557
Proved developed reserves at:
End of Year		187,517		79,557
Proved undeveloped reserves at:
End of Year		5,006
Carbon California [Member]
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year
Revisions of previous estimates
Extensions and discoveries
Production		(237)	[1]
Purchases of reserves in-place		14,361	[2]
Sales of reserves in-place
Proved reserves, end of year		14,124
Proved developed reserves at:
End of Year		9,208
Proved undeveloped reserves at:
End of Year		4,910
Carbon Appalachia [Member]
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year
Revisions of previous estimates
Extensions and discoveries
Production		(1,328)	[1]
Purchases of reserves in-place		101,835	[2]
Sales of reserves in-place
Proved reserves, end of year		91,189	[1],[2]
Proved developed reserves at:
End of Year		91,189
Proved undeveloped reserves at:
End of Year
Company [Member]
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year		79,557		33,546
Revisions of previous estimates		12,837		2,867
Extensions and discoveries		234
Production		(5,412)	[1]	(3,297)
Purchases of reserves in-place	[2]			46,441	[1]
Sales of reserves in-place
Proved reserves, end of year		87,216		79,557
Proved developed reserves at:
End of Year		87,120		79,557
Proved undeveloped reserves at:
End of Year		96		186
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		882		598
Revisions of previous estimates | MMBbls		107		110
Extensions and discoveries | MMBbls		16
Production | MMBbls		(136)	[1]	(79)
Purchases of reserves in-place | MMBbls	[2]	3,300		253	[1]
Sales of reserves in-place | MMBbls
Proved reserves, end of year | MMBbls		4,169		882
Proved developed reserves at:
End of Year | MMBbls		1,981		851
Proved undeveloped reserves at:
End of Year | MMBbls		635		31
Oil [Member] | Carbon California [Member]
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year | MMBbls
Revisions of previous estimates | MMBbls
Extensions and discoveries | MMBbls
Production | MMBbls		(25)	[1]
Purchases of reserves in-place | MMBbls		1,650	[2]
Sales of reserves in-place | MMBbls
Proved reserves, end of year | MMBbls		1,625
Proved developed reserves at:
End of Year | MMBbls		1,006
Proved undeveloped reserves at:
End of Year | MMBbls		619
Oil [Member] | Carbon Appalachia [Member]
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year | MMBbls
Revisions of previous estimates | MMBbls
Extensions and discoveries | MMBbls
Production | MMBbls		(2)	[1]
Purchases of reserves in-place | MMBbls		74	[2]
Sales of reserves in-place | MMBbls
Proved reserves, end of year | MMBbls		72	[1],[2]
Proved developed reserves at:
End of Year | MMBbls		72			[2]
Proved undeveloped reserves at:
End of Year | MMBbls
Oil [Member] | Company [Member]
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year | MMBbls		882		598
Revisions of previous estimates | MMBbls		107		110
Extensions and discoveries | MMBbls		16
Production | MMBbls		(86)	[1]	(79)
Purchases of reserves in-place | MMBbls			[2]	253
Sales of reserves in-place | MMBbls
Proved reserves, end of year | MMBbls		919		882
Proved developed reserves at:
End of Year | MMBbls		903		882
Proved undeveloped reserves at:
End of Year | MMBbls		16		31
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		74,265		29,958
Revisions of previous estimates		12,195		2,207
Extensions and discoveries		138
Production		(4,984)	[1]	(2,823)
Purchases of reserves in-place	[2]	4,725		44,923	[1]
Sales of reserves in-place
Proved reserves, end of year		86,339		74,265
Proved developed reserves at:
End of Year		174,653		74,265
Proved undeveloped reserves at:
End of Year		818
Natural Gas [Member] | Carbon California [Member]
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year
Revisions of previous estimates
Extensions and discoveries
Production		(63)	[1]
Purchases of reserves in-place		3,075	[2]
Sales of reserves in-place
Proved reserves, end of year		3,012
Proved developed reserves at:
End of Year		2,194
Proved undeveloped reserves at:
End of Year		818
Natural Gas [Member] | Carbon Appalachia [Member]
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year
Revisions of previous estimates
Extensions and discoveries
Production		(1,178)	[1]
Purchases of reserves in-place		91,935	[2]
Sales of reserves in-place
Proved reserves, end of year		90,757	[1],[2]
Proved developed reserves at:
End of Year		90,757			[2]
Proved undeveloped reserves at:
End of Year
Natural Gas [Member] | Company [Member]
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year		74,265		29,958
Revisions of previous estimates		12,195		2,207
Extensions and discoveries		138
Production		(4,896)	[1]	(2,823)
Purchases of reserves in-place			[2]	44,923
Sales of reserves in-place
Proved reserves, end of year		81,702		74,265
Proved developed reserves at:
End of Year		81,702		74,265
Proved undeveloped reserves at:
End of Year
Natural Gas Liquids [Member]
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year | MMBbls
Revisions of previous estimates | MMBbls
Extensions and discoveries | MMBbls
Production | MMBbls		(4)	[1]
Purchases of reserves in-place | MMBbls		231	[2]
Sales of reserves in-place | MMBbls
Proved reserves, end of year | MMBbls		227
Proved developed reserves at:
End of Year | MMBbls		163			[2]
Proved undeveloped reserves at:
End of Year | MMBbls		63
Natural Gas Liquids [Member] | Carbon California [Member]
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year | MMBbls
Revisions of previous estimates | MMBbls
Extensions and discoveries | MMBbls
Production | MMBbls		(4)	[1]
Purchases of reserves in-place | MMBbls		231	[2]
Sales of reserves in-place | MMBbls
Proved reserves, end of year | MMBbls		227
Proved developed reserves at:
End of Year | MMBbls		163
Proved undeveloped reserves at:
End of Year | MMBbls		63
Natural Gas Liquids [Member] | Carbon Appalachia [Member]
Proved developed reserves at:
End of Year | MMBbls
Proved undeveloped reserves at:
End of Year | MMBbls
Natural Gas Liquids [Member] | Company [Member]
Proved developed reserves at:
End of Year | MMBbls
Proved undeveloped reserves at:
End of Year | MMBbls
[1]	Related to Carbon Appalachia, the net sales (in standard measure change) and production figures were calculated utilizing the same methodology as the purchase of reserves-in-place discussed above.
[2]	Related to Carbon Appalachia the purchases of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14, 2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; and November 1, 2017 through December 31, 2017, respectively.

Supplemental Financial Data -79

Supplemental Financial Data - Oil and Gas Producing Activities (Unaudited) (Details 1) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Carbon California [Member]
Oil and gas properties
Proved oil and gas properties	$ 7,635
Unproved properties not subject to depletion	266
Accumulated depreciation, depletion, amortization and impairment	(208)
Net oil and gas properties	7,693
Carbon Appalachia [Member]
Oil and gas properties
Proved oil and gas properties	22,951
Unproved properties not subject to depletion	485
Accumulated depreciation, depletion, amortization and impairment	(445)
Net oil and gas properties	22,991
Parent Company [Member]
Oil and gas properties
Proved oil and gas properties	114,893	112,579
Unproved properties not subject to depletion	1,947	1,999
Accumulated depreciation, depletion, amortization and impairment	(80,715)	(78,596)
Net oil and gas properties	$ 36,125	$ 35,982

Supplemental Financial Data -80

Supplemental Financial Data - Oil and Gas Producing Activities (Unaudited) (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Property acquisition costs:
Asset retirement obligation	$ 2,402	$ 1,849
Carbon California [Member]
Property acquisition costs:
Unevaluated properties	266
Proved properties and gathering facilities	7,682
Development costs	412
Gathering facilities	47
Asset retirement obligation	483
Total costs incurred	8,890
Carbon Appalachia [Member]
Property acquisition costs:
Unevaluated properties	483
Proved properties and gathering facilities	19,286
Development costs	24
Gathering facilities	2,544
Asset retirement obligation	3,592
Total costs incurred	25,929
Company [Member]
Property acquisition costs:
Unevaluated properties	1	97
Proved properties and gathering facilities	289	8,117
Development costs	952	360
Gathering facilities	43	42
Asset retirement obligation	2,309	1,849
Total costs incurred	$ 3,594	$ 10,465

Supplemental Financial Data -81

Supplemental Financial Data - Oil and Gas Producing Activities (Unaudited) (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary of company's investment in unproved properties
Acquisition costs	$ 752	$ 97	$ 1,849
Carbon California [Member]
Summary of company's investment in unproved properties
Acquisition costs	266
Carbon Appalachia [Member]
Summary of company's investment in unproved properties
Acquisition costs	485
Company [Member]
Summary of company's investment in unproved properties
Acquisition costs	$ 1	$ 97	$ 1,849

Supplemental Financial Data -82

Supplemental Financial Data - Oil and Gas Producing Activities (Unaudited) (Details 4) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)MMcf	Dec. 31, 2016USD ($)MMcf
Revenues
Oil and gas sales, including commodity derivative gains and losses	$ 29,001	$ 8,184
Expenses:
Production expenses	11,775	5,640
Depletion expense	2,810	1,839
Accretion of asset retirement obligations	395	176
Impairment of oil and gas properties		4,299
Total expenses	14,979	11,954
Results of operations from oil and gas producing activities	$ 14,021	$ (3,770)
Depletion rate per Mcfe | MMcf	0.47	0.56
Carbon California [Member]
Revenues
Oil and gas sales, including commodity derivative gains and losses	$ 1,289
Expenses:
Production expenses	664
Depletion expense	208
Accretion of asset retirement obligations	34
Impairment of oil and gas properties
Carbon Appalachia [Member]
Revenues
Oil and gas sales, including commodity derivative gains and losses	5,273
Expenses:
Production expenses	1,522
Depletion expense	445
Accretion of asset retirement obligations	54
Impairment of oil and gas properties
Parent Company [Member]
Revenues
Oil and gas sales, including commodity derivative gains and losses	22,439	8,184
Expenses:
Production expenses	9,589	5,640
Depletion expense	2,157	1,839
Accretion of asset retirement obligations	307	176
Impairment of oil and gas properties		$ 4,299

Supplemental Financial Data -83

Supplemental Financial Data - Oil and Gas Producing Activities (Unaudited) (Details 5) - USD ($) $ in Thousands	Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015
Summary of estimate of the current market value of the Company's proved reserves
Standardized measure of discounted future net cash flows	$ 116,856		$ 44,711	$ 25,032
Carbon California [Member]
Summary of estimate of the current market value of the Company's proved reserves
Future cash inflows	97,841
Future production costs	(62,187)
Future development costs	(5,809)
Future income taxes
Future net cash flows	29,845
10% annual discount	(16,288)
Standardized measure of discounted future net cash flows	9,181
Carbon Appalachia [Member]
Summary of estimate of the current market value of the Company's proved reserves
Future cash inflows	271,638	[1],[2]
Future production costs	(151,501)	[1]
Future development costs	(27)	[1]
Future income taxes		[3]
Future net cash flows	120,110
10% annual discount	(73,890)
Standardized measure of discounted future net cash flows	31,706
Company [Member]
Summary of estimate of the current market value of the Company's proved reserves
Future cash inflows	283,664		214,658
Future production costs	(119,501)		(103,252)
Future development costs	(210)		(315)
Future income taxes	(35,482)		(14,858)
Future net cash flows	128,471		96,233
10% annual discount	(71,389)		(51,522)
Standardized measure of discounted future net cash flows	$ 57,082		$ 44,711	$ 25,032
[1]	Related to Carbon Appalachia the purchases of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14, 2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; and November 1, 2017 through December 31, 2017, respectively.
[2]	Related to Carbon Appalachia, the net sales (in standard measure change) and production figures were calculated utilizing the same methodology as the purchase of reserves-in-place discussed above.
[3]	Carbon Appalachia does not include the net changes in future income taxes because Carbon California is treated as a partnership for taxes and is not subject to federal income taxes

Supplemental Financial Data -84

Supplemental Financial Data - Oil and Gas Producing Activities (Unaudited) (Details 6) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016
Summary of discounted future cash flows relating to proved oil and gas reserves
Standardized measure of discounted future net cash flows, beginning of year	$ 44,711		$ 25,032
Sales of oil and gas, net of production costs and taxes	(12,231)		(4,804)
Price revisions	17,588		(786)
Extensions, discoveries and improved recovery, less related costs	298
Changes in estimated future development costs	(324)		248
Development costs incurred during the period	804		102
Quantity revisions	11,196		2,091
Accretion of discount	4,471		2,503
Net changes in future income taxes	(7,425)	[1],[2]	(4,633)
Purchases of reserves-in-place	61,533	[3]	26,776
Sales of reserves-in-place
Changes in production rate timing and other	(4,199)		(1,818)
Standardized measure of discounted future net cash flows, end of year	116,856		44,711
Carbon California [Member]
Summary of discounted future cash flows relating to proved oil and gas reserves
Standardized measure of discounted future net cash flows, beginning of year
Sales of oil and gas, net of production costs and taxes	(516)
Price revisions
Extensions, discoveries and improved recovery, less related costs
Changes in estimated future development costs
Development costs incurred during the period
Quantity revisions
Accretion of discount
Net changes in future income taxes		[1],[2]
Purchases of reserves-in-place	14,073	[3]
Sales of reserves-in-place
Changes in production rate timing and other
Standardized measure of discounted future net cash flows, end of year	9,181
Carbon Appalachia [Member]
Summary of discounted future cash flows relating to proved oil and gas reserves
Standardized measure of discounted future net cash flows, beginning of year
Sales of oil and gas, net of production costs and taxes	(1,240)
Price revisions
Extensions, discoveries and improved recovery, less related costs
Changes in estimated future development costs
Development costs incurred during the period
Quantity revisions
Accretion of discount
Net changes in future income taxes		[1],[2]
Purchases of reserves-in-place	47,460	[3]
Sales of reserves-in-place
Changes in production rate timing and other
Standardized measure of discounted future net cash flows, end of year	31,706
Company [Member]
Summary of discounted future cash flows relating to proved oil and gas reserves
Standardized measure of discounted future net cash flows, beginning of year	44,711		25,032
Sales of oil and gas, net of production costs and taxes	(10,038)		(4,804)
Price revisions	17,588		(786)
Extensions, discoveries and improved recovery, less related costs	298
Changes in estimated future development costs	(324)		248
Development costs incurred during the period	804		102
Quantity revisions	11,196		2,091
Accretion of discount	4,471		2,503
Net changes in future income taxes	(7,425)	[1],[2]	(4,633)
Purchases of reserves-in-place		[3]	26,776
Sales of reserves-in-place
Changes in production rate timing and other	(4,199)		(1,818)
Standardized measure of discounted future net cash flows, end of year	$ 57,082		$ 44,711
[1]	Carbon Appalachia does not include the net changes in future income taxes because Carbon California is treated as a partnership for taxes and is not subject to federal income taxes
[2]	Carbon California does not include the net changes in future income taxes because Carbon California is treated as a partnership for taxes and is not subject to federal income taxes.
[3]	Related to Carbon Appalachia the purchases of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14, 2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; and November 1, 2017 through December 31, 2017, respectively.

Supplemental Financial Data -85

Supplemental Financial Data - Oil and Gas Producing Activities (Unaudited) (Details 7)	12 Months Ended
	Dec. 31, 2017Per_McfeUSD_Bbl	Dec. 31, 2016Per_McfeUSD_Bbl
Oil (per Bbl) [Member]
Summary of weighted averaged adjusted prices
Weighted averaged adjusted prices | USD_Bbl	51.34	40.40
Natural Gas (per Mcf) [Member]
Summary of weighted averaged adjusted prices
Weighted averaged adjusted prices | Per_Mcfe	2.98	2.41

Supplemental Financial Data -86

Supplemental Financial Data - Oil and Gas Producing Activities (Unaudited) (Details Textual)	1 Months Ended		2 Months Ended	4 Months Ended	12 Months Ended
	Oct. 31, 2017	Sep. 28, 2017	Dec. 31, 2017	Aug. 14, 2017	Dec. 31, 2017	Dec. 31, 2016
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Textual)
Estimated proved reserves, description					3.0 Bcfe	3.1 Bcfe
Discount rate, description					All cash flow amounts, including income taxes, are discounted at 10%.
Carbon Appalachia [Member]
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Textual)
Propotionate share, percentage	19.37%	16.04%	27.24%	2.98%