Carbon Energy (CRBO) 10-Q 14 May 19 2019 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2019	May 13, 2019
Document and Entity Information [Abstract]
Entity Registrant Name	Carbon Energy Corp
Entity Central Index Key	0000086264
Trading Symbol	CRBO
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Type	10-Q
Document Period End Date	Mar. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Ex Transition Period	false
Entity Common Stock, Shares Outstanding		7,816,030

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 11,016	$ 5,736
Accounts receivable:
Revenue	14,714	19,671
Joint interest billings and other	1,158	1,770
Insurance receivable (Note 2)		522
Commodity derivative asset (Note 13)		3,517
Prepaid expense, deposits and other current assets	1,519	1,894
Inventory	625	900
Total current assets	29,032	34,010
Oil and gas properties, full cost method of accounting:
Proved, net	245,321	248,455
Unproved	5,385	5,416
Other property and equipment, net	17,168	17,563
Total property and equipment, net	267,874	271,434
Investments in affiliates (Note 6)	617	598
Commodity derivative asset - non-current (Note 13)	147	3,505
Right-of-use assets (Note 14)	7,256
Other non-current assets	1,138	1,344
Total non-current assets	277,032	276,881
Total assets	306,064	310,891
Current liabilities:
Accounts payable and accrued liabilities (Note 11)	30,020	34,816
Firm transportation contract obligations (Note 15)	6,012	6,129
Lease liability - current (Note 14)	1,616
Commodity derivative liability (Note 13)	1,657
Credit facilities and notes payable – current (Note 7)	9,910	11,910
Total current liabilities	49,215	52,855
Non-current liabilities:
Firm transportation contract obligations (Note 15)	11,749	12,729
Lease liability - non-current (Note 14)	5,645
Commodity derivative liability - non-current (Note 13)	318
Production and property taxes payable	3,103	2,914
Asset retirement obligations (Note 3)	19,312	19,211
Credit facilities and notes payable (Note 7)	97,168	97,228
Notes payable - related party (Note 7)	49,964	49,919
Total non-current liabilities	187,259	182,001
Commitments and contingencies (Note 15)
Stockholders' equity:
Preferred stock, $0.01 par value; liquidation preference of $299,000 at March 31, 2019 and $224,000 at December 31, 2018; authorized 1,000,000 shares, 50,000 shares issued and outstanding at March 31, 2019 and December 31, 2018	1	1
Common stock, $0.01 par value; authorized 35,000,000 shares, 7,791,292 and 7,655,759 shares issued and outstanding at March 31, 2019 and December 31, 2018, respectively	79	77
Additional paid-in capital	84,833	84,612
Accumulated deficit	(41,039)	(36,939)
Total Carbon stockholders' equity	43,874	47,751
Non-controlling interests	25,716	28,284
Total stockholders' equity	69,590	76,035
Total liabilities and stockholders' equity	$ 306,064	$ 310,891

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	1,000,000	1,000,000
Preferred stock, shares issued	50,000	50,000
Preferred stock, shares outstanding	50,000	50,000
Preferred stock, liquidation preference	$ 299,000	$ 224,000
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	35,000,000	35,000,000
Common stock, shares issued	7,791,292	7,655,759
Common stock, shares outstanding	7,791,292	7,655,759

Consolidated Statements of Oper

Consolidated Statements of Operations (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Revenue:
Natural gas sales	$ 19,316	$ 3,939
Natural gas liquids	247	163
Oil sales	8,989	2,983
Transportation and handling	734
Marketing gas sales	4,944
Commodity derivative loss	(9,306)	(626)
Other income	26	14
Total revenue	24,950	6,473
Expenses:
Lease operating expenses	6,616	2,087
Pipeline operating expenses	3,085
Transportation and gathering costs	1,669	855
Production and property taxes	2,010	433
Marketing gas purchases	6,302
General and administrative	4,689	2,948
General and administrative - related party reimbursement		(1,116)
Depreciation, depletion and amortization	3,980	1,492
Accretion of asset retirement obligations	394	141
Total expenses	28,745	6,840
Total operating loss	(3,795)	(367)
Other income (expense):
Interest expense	(2,914)	(1,002)
Warrant derivative gain		225
Gain on derecognized equity investment in affiliate - Carbon California		5,391
Investment in affiliates	19	437
Total other (expense) income	(2,895)	5,051
(Loss) income before income taxes	(6,690)	4,684
Provision for income taxes
Net (loss) income before non-controlling interests and preferred shares	(6,690)	4,684
Net (loss) income attributable to non-controlling interests	(2,590)	1,115
Net (loss) income attributable to controlling interests before preferred shares	(4,100)	3,569
Net income attributable to preferred shares - preferred return	75
Net (loss) income attributable to common shares	$ (4,175)	$ 3,569
Net (loss) income per common share:
Basic	$ (0.54)	$ 0.51
Diluted	$ (0.54)	$ 0.46
Weighted average common shares outstanding:
Basic	7,663	6,996
Diluted	7,932	7,226

Consolidated Statements of Stoc

Consolidated Statements of Stockholders’ Equity (Unaudited) - USD ($) $ in Thousands	Common Stock	Preferred Stock	Additional Paid-in Capital	Non-Controlling Interests	Accumulated Deficit	Total
Balances at Dec. 31, 2017	$ 60		$ 58,813	$ 1,841	$ (44,218)	$ 16,496
Balances, shares at Dec. 31, 2017	6,006
Stock based compensation			292			292
Restricted stock vested	$ 1					1
Restricted stock vested, shares	38
CCC warrant exercise - share issuance	$ 15		8,311	16,466		24,792
CCC warrant exercise - share issuance, shares	1,528
CCC warrant exercise - liability extinguishment			1,792			1,792
Non-controlling interest distributions, net				(24)		(24)
Net income (loss)				1,115	3,569	4,684
Balances at Mar. 31, 2018	$ 76		69,208	19,398	(40,649)	48,033
Balances, shares at Mar. 31, 2018	7,572
Balances at Dec. 31, 2018	$ 77	$ 1	84,612	28,284	(36,939)	76,035
Balances, shares at Dec. 31, 2018	7,656	50
Stock based compensation			222			222
Restricted stock vested	$ 1					$ 1
Restricted stock vested, shares	40
Performance units vested	$ 1		$ (1)
Performance units vested, shares	95
Non-controlling interest distributions, net				$ 22		$ 22
Net income (loss)				(2,590)	$ (4,100)	(6,690)
Balances at Mar. 31, 2019	$ 79	$ 1	$ 84,833	$ 25,716	$ (41,039)	$ 69,590
Balances, shares at Mar. 31, 2019	7,791	50

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash flows from operating activities:
Net (loss) income	$ (6,690)	$ 4,684
Items not involving cash:
Depreciation, depletion and amortization	3,980	1,492
Accretion of asset retirement obligations	394	141
Unrealized commodity derivative loss	8,850	249
Warrant derivative gain		(225)
Stock-based compensation expense	222	292
Investment in affiliates gain	(19)	(437)
Gain on derecognized equity investment in affiliate - Carbon California		(5,391)
Amortization of debt costs	277	89
Net change in:
Accounts receivable	6,091	(1,611)
Prepaid expenses, deposits and other current assets	375	448
Accounts payable, accrued liabilities and firm transportation contract obligations	(5,485)	907
Other non-current items	316	(543)
Net cash provided by operating activities	8,311	95
Cash flows from investing activities:
Development and acquisition of properties and equipment	(500)	(874)
Proceeds received - disposition of oil and gas properties	164
Proceeds received - Carbon California Acquisition		275
Net cash used in investing activities	(336)	(599)
Cash flows from financing activities:
Proceeds from credit facility and notes payable	3,000	3,000
Payments on credit facility and notes payable	(5,676)	(8)
Debt issuance costs	(41)
Distributions to (contributions from) non-controlling interests	22	(24)
Net cash (used in) provided by financing activities	(2,695)	2,968
Net increase in cash and cash equivalents	5,280	2,464
Cash and cash equivalents, beginning of period	5,736	1,650
Cash and cash equivalents, end of period	$ 11,016	$ 4,114

Organization

Organization	3 Months Ended
	Mar. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Note 1 – Organization An illustrative organizational chart as of March 31, 2019, is below: Appalachian and Illinois Basin Operations In the Appalachian and Illinois Basins, operations are conducted by Nytis Exploration Company, LLC (“ Nytis LLC In December 2018, we completed the acquisition of all of the Class A Units of Carbon Appalachian Company, LLC, a Delaware limited liability company (“ Carbon Appalachia OIE II-A OIE II-B Old Ironsides OIE Membership Acquisition Ventura Basin Operations In California, Carbon California Operating Company, LLC (“ CCOC Carbon California Yorktown Prudential Collectively, references to “us” include Carbon California, CCOC, Nytis Exploration (USA) Inc. (“ Nytis USA

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2019
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2 – Summary of Significant Accounting Policies Basis of Presentation The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“ GAAP Principles of Consolidation The unaudited condensed consolidated financial statements include the accounts of our consolidated subsidiaries. Upon the closing of the OIE Membership Acquisition on December 31, 2018, we own 100% of Carbon Appalachia. In addition, we own 100% of Nytis USA, which owns approximately 98.1% of Nytis LLC. Nytis LLC holds interests in various oil and gas partnerships. Partnerships and subsidiaries in which we have a controlling interest are consolidated. We are currently consolidating 46 partnerships, Carbon Appalachia, and Carbon California, and we reflect the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on our unaudited consolidated statements of operations and also reflect the non-controlling ownership interest in the net assets of the partnerships as non-controlling interests within stockholders’ equity on our unaudited consolidated balance sheets. All significant intercompany accounts and transactions have been eliminated. In accordance with established practice in the oil and gas industry, our unaudited condensed 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 unaudited condensed consolidated financial statements. Reclassifications Certain prior period balances in the consolidated balance sheets and statements of operations have been reclassified to conform to the current year presentation. Specifically, a portion of credit facilities and notes payable balances as of December 31, 2018 were reclassified from non-current liabilities to current liabilities. This reclassification had no impact on net income, cash flows or shareholders’ equity previously reported. Insurance Receivable Insurance receivable is comprised of insurance claims for the loss of property as a result of wildfires that impacted Carbon California in December 2017. The Company filed claims with its insurance provider. In January 2019, we reached a settlement agreement and received an $800,000 payment from our insurance provider related to the damage caused by the California wildfires. As of March 31, 2019, we are in receipt of all funds associated with the claims. Accounting for Oil and Gas Operations We use the full cost method of accounting for oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Overhead costs incurred that are directly identified with acquisition, exploration and development activities undertaken by the Company for its own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized. Unproved properties are excluded from amortized capitalized costs until it is determined if 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 oil to gas at the ratio of one barrel of oil to six thousand cubic feet of natural gas. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves. All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred. 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 would be recognized to the extent of the excess capitalized costs. Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds the capitalized costs in future periods. For the three months ended March 31, 2019 and 2018, we did not recognize a ceiling test impairment as our full cost pool did not exceed the ceiling limitations. Future declines in oil and natural gas prices could result in impairments of our oil and gas properties in future periods. The effect of price declines will impact the ceiling test value until such time commodity prices stabilize or improve. Impairments are a non-cash charge and accordingly would not affect cash flows but would adversely affect our results of operations and members’ equity. We capitalize the portion of general and administrative costs that is attributable to our acquisition, exploration and development activities. Revenue We recognize revenues for sales and services when persuasive evidence of an arrangement exists, when custody is transferred, or services are rendered, fees are fixed or determinable and collectability is reasonably assured. Oil, Natural Gas and Natural Gas Liquid Sales Oil, natural gas and natural gas liquid sales 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. Revenues are recognized based on our net revenue interest. Marketing Gas Sales We sell production purchased from third parties as well as production from our own oil and gas producing properties. Marketing gas sales are recognized on a gross basis as we purchase and take control of the gas prior to sale and are the principal in the transaction. Storage Under fee-based arrangements, we receive a fee for storing natural gas. The revenues earned are directly related to the volume of natural gas that flows through our systems and are not directly dependent on commodity prices. Transportation, gathering, and compression We generally purchase natural gas from producers at the wellhead or other receipt points, gather the wellhead natural gas through our gathering systems, and then sell the natural gas based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of natural gas or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, regardless of the actual amount of the sales proceeds we receive. Our revenues under percent-of-proceeds/index arrangements generally correlate to the price of natural gas. 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 can 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. Equity method investments will increase or decrease by our share of the affiliate’s profits or losses and such profits or losses are recognized in our unaudited consolidated statements of operations. We review equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred. Upon the exercise of the California Warrant on February 1, 2018 and the closing of the OIE Membership Acquisition on December 31, 2018, we consolidate Carbon California and Carbon Appalachia for financial reporting purposes and no longer account for these investments under the equity method. Related Party Transactions Management Reimbursements In our role as manager of Carbon California and Carbon Appalachia we receive reimbursements for management services. Prior to consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, these management service reimbursements were included in general and administrative – related party reimbursement on our unaudited consolidated statements of operations. As we now consolidate both Carbon California and Carbon Appalachia, these reimbursements are eliminated upon consolidation. We received approximately $753,000 and $50,000 for the three months ended March 31, 2018, and for the one month ended January 31, 2018, from Carbon Appalachia and Carbon California, respectively. These reimbursements are included in general and administrative – related party reimbursement on our unaudited consolidated statements of operations. Effective February 1, 2018, the management reimbursements received from Carbon California were eliminated at consolidation. This elimination included $100,000 for the period February 1, 2018, through March 31, 2018. In addition to the management reimbursements, approximately $299,000 and $14,000 in general and administrative expenses were reimbursed for the three months ended March 31, 2018, and for the one month ended January 31, 2018, by Carbon Appalachia and Carbon California, respectively. The elimination of Carbon California in consolidation includes approximately $28,000 for the period February 1, 2018, through March 31, 2018. Operating Reimbursements In our role as operator of Carbon California and Carbon Appalachia, we receive reimbursements of operating expenses. Prior to consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, these operating reimbursements were included in operating expenses on our unaudited consolidated statements of operations. As we now consolidate both Carbon California and Carbon Appalachia, any intercompany receivable and payable balances associated with these reimbursements are eliminated upon consolidation. Carbon California Credit Facilities The credit facilities of Carbon California, including the Senior Revolving Notes, Carbon California Notes and Carbon California 2018 Subordinated Notes (all defined below), are held by Prudential (see Note 7). Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and expenses and disclosure of contingent assets and liabilities. Significant items subject to such estimates and assumptions include the carrying value of oil and gas properties, estimates 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 fair value of commodity derivative instruments, fair value of assets acquired and liabilities assumed qualifying as business combinations or asset acquisitions, estimated lives of other property and equipment, asset retirement obligations, fair value of Class B issuances and accrued liabilities and revenues. There have been no changes in our critical accounting estimates from those that were disclosed in the 2018 Annual Report on Form 10-K. Actual results could differ from these estimates. Earnings (Loss) Per Common Share Basic earnings per common share is computed by dividing the net income or 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). In periods when we report a net loss, all shares of restricted stock are excluded from the calculation of diluted weighted average shares outstanding because of its anti-dilutive effect on loss per share. As a result, approximately 269,000 potentially dilutive restricted stock awards are excluded from the calculation of diluted earnings per common share for the three months ended March 31, 2019. In addition, approximately 200,000 restricted performance units subject to future contingencies were excluded in the basic and diluted income per share calculations. For the three months ended March 31, 2018, we had net income and the diluted income per common share calculation includes the dilutive effects of approximately 230,000 non-vested shares of restricted stock. In addition, approximately 254 ,000 restricted performance units subject to future contingencies were excluded in the basic and diluted income per share calculations. The following table sets forth the calculation of basic and diluted (loss) income per share: Three months ended (in thousands except per share amounts) 2019 2018 Net (loss) income attributable to common shareholders $ (4,175 ) $ 3,569 Less: warrant derivative gain - (225 ) Diluted net income (4,175 ) 3,344 Basic weighted-average common shares outstanding during the period 7,663 6,996 Add dilutive effects of warrants and non-vested shares of restricted stock 269 230 Diluted weighted-average common shares outstanding during the period 7,932 7,226 Basic net (loss) income per common share $ (0.54 ) $ 0.51 Diluted net (loss) income per common share $ (0.54 ) $ 0.46 Recently Adopted Accounting Pronouncement In February 2016, the FASB issued Accounting Standards Update (“ ASU Leases ASC Leases ASC 842 Recently Issued Accounting Pronouncements There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows.

Acquisitions and Divestitures

Acquisitions and Divestitures	3 Months Ended
	Mar. 31, 2019
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 3 – Acquisitions and Divestitures Majority Control of Carbon Appalachia On December 16, 2016, Carbon Appalachia was formed by us, entities managed by Yorktown and entities managed by Old Ironsides to acquire producing assets in the Appalachian Basin in Kentucky, Tennessee, Virginia and West Virginia. Carbon Appalachia began substantial operations on April 3, 2017 and is engaged primarily in acquiring, developing, exploiting, producing, processing, marketing, and transporting oil and natural gas in the Appalachian Basin. On April 3, 2017, Carbon, Yorktown and Old Ironsides entered in to a limited liability company agreement (the “ Carbon Appalachia LLC Agreement Carbon Appalachia Enterprises “Revolver” In connection with Carbon entering into the Carbon Appalachia LLC Agreement, and Carbon Appalachia engaging in the transactions described above, Carbon received 1,000 Class B Units and issued to Yorktown a warrant to purchase approximately 408,000 shares of our common stock at an exercise price dictated by the warrant agreement (the “Appalachia Warrant” On August 15, 2017, the Carbon Appalachia LLC Agreement was amended and, as a result, we agreed to contribute an initial commitment of future capital contributions as well as Yorktown’s, and Yorktown will not participate in future capital contributions. Carbon Appalachia issued Class A Units to us and Old Ironsides for an aggregate cash consideration of $14.0 million. The borrowing base of the Revolver increased to $22.0 million and Carbon Appalachia Enterprises borrowed $8.0 million under the Revolver. On September 29, 2017, Carbon Appalachia issued Class A Units to us and Old Ironsides for an aggregate cash consideration of $11.0 million. Prior to the closing of the OIE Membership Acquisition, Old Ironsides held 27,195 Class A Units, which equated to a 72.76% aggregate share ownership of Carbon Appalachia and we held (i) 9,805 Class A Units, (ii) 1,000 Class B Units and (iii) 121 Class C Units, which equated to a 27.24% aggregate share ownership of Carbon Appalachia. On December 31, 2018, we acquired all of Old Ironsides’ Class A Units of Carbon Appalachia for approximately $58.1 million, subject to customary and standard closing adjustments. We paid $33.0 million in cash and delivered promissory notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides (the “Old Ironsides Notes” The OIE Membership Acquisition is accounted for as a business combination in accordance with ASC 805, Business Combinations ASC 805 The Company, utilizing the assistance of third-party valuation specialists, considered various factors in its estimate of fair value of the acquired assets and liabilities including (i) reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, including price differentials, (v) future cash flows, (vi) a market participant-based weighted average cost of capital, and (vii) real estate market conditions. We followed the fair value method to allocate the consideration transferred to the identifiable net assets acquired on a preliminary basis as follows: Amount Cash consideration $ 33,000 Old Ironsides Notes 25,065 Fair value of previously held equity interest 14,158 Fair value of business acquired $ 72,223 Assets acquired and liabilities assumed are as follows: Amount Cash $ 12,283 Accounts receivable: Revenue 12,834 Trade receivable 1,941 Commodity derivative asset 198 Inventory 900 Prepaid expenses, deposits, and other current assets 456 Oil and gas properties: Proved 107,499 Unproved 1,869 Other property, plant and equipment, net 15,626 Other non-current assets 514 Accounts payable and accrued liabilities (19,114 ) Due to related parties (458 ) Firm transportation contract obligations (18,724 ) Asset retirement obligations (5,626 ) Notes payable (37,975 ) Total net assets acquired $ 72,223 The preliminary fair value of the assets acquired and liabilities assumed were determined using various valuation techniques, including an income approach. On the date of the acquisition, we derecognized our equity investment in Carbon Appalachia and recognized a gain of approximately $1.3 million based on the fair value of our previously held interest compared to its carrying value. For assets and liabilities accounted for as business combinations, including the OIE Membership Acquisition, to determine the fair value of the assets acquired, the Company primarily used the income approach and made market assumptions as to projections of estimated quantities of oil and natural gas reserves, future production rates, future commodity prices including price differentials as of the date of closing, future operating and development costs, a market participant weighted average cost of capital, and the condition of vehicles and equipment. The Company used the income approach and made market assumptions as to projections of utilization, future operating costs and a market participant weighted average costs of capital to determine the fair value of the firm transportation obligations as well as the plant facilities. The determination of the fair value of accounts payable and accrued liabilities assumed required significant judgement, including estimates relating to production assets. Consolidation of Carbon Appalachia and OIE Membership Acquisition Unaudited Pro Forma Results of Operations Below are unaudited pro forma consolidated results of operations for the three months ended March 31, 2019 and 2018 as though the OIE Membership Acquisition had been completed as of January 1, 2018. Three Months Ended March 31, Three Months Ended March 31, (in thousands, except per share amounts) 2019 2018 Revenue $ 24,950 $ 32,316 Net (loss) income before non-controlling interests $ (6,690 ) $ 6,912 Net (loss) income attributable to non-controlling interests $ (2,590 ) $ 1,115 Net (loss) income attributable to common shareholders $ (4,175 ) $ 5,797 Net (loss) income per share (basic) $ (0.54 ) $ 0.83 Net (loss) income per share (diluted) $ (0.54 ) $ 0.77 Consolidation of Carbon California Unaudited Pro Forma Results of Operations On February 1, 2018, Yorktown exercised the California Warrant resulting in the issuance of 1,527,778 shares of our common stock in exchange for Yorktown’s Class A Units of Carbon California representing approximately 46.96% of the outstanding Class A Units of Carbon California (a profits interest of approximately 38.59%). After giving effect to the exercise on February 1, 2018, we owned 56.4% of the voting and profits interests of Carbon California. Below are unaudited pro forma consolidated results of operations for the three months ended March 31, 2019 and 2018 as though the Carbon California Acquisition had been completed as of January 1, 2018. The Carbon California Acquisition closed February 1, 2018, and accordingly, the Company’s unaudited consolidated statements of operations for the quarter ended March 31, 2018, includes the results of operations for the period February 1, 2018, through March 31, 2018. Three Months Ended March 31, Three Months Ended March 31, (in thousands, except per share amounts) 2019 2018 Revenue $ 24,950 $ 6,672 Net (loss) income before non-controlling interests $ (6,690 ) $ 3,543 Net (loss) income attributable to non-controlling interests $ (2,590 ) $ 1,115 Net (loss) income attributable to common shareholders $ (4,175 ) $ 2,428 Net (loss) income per share (basic) $ (0.54 ) $ 0.35 Net (loss) income per share (diluted) $ (0.54 ) $ 0.30

Property and Equipment

Property and Equipment	3 Months Ended
	Mar. 31, 2019
Property, Plant and Equipment [Abstract]
Property and Equipment	Note 4 – Property and Equipment Net property and equipment as of March 31, 2019 and December 31, 2018 consists of the following: (in thousands) March 31, December 31, Oil and gas properties: Proved oil and gas properties $ 344,147 $ 343,736 Unproved properties not subject to depletion 5,385 5,416 Accumulated depreciation, depletion, amortization and impairment (98,826 ) (95,281 ) Net oil and gas properties 250,706 253,871 Pipeline facilities and equipment 12,714 12,714 Base gas 2,122 2,122 Furniture and fixtures, computer hardware and software, and other equipment 6,688 6,649 Accumulated depreciation and amortization (4,356 ) (3,922 ) Net other property and equipment 17,168 17,563 Total net property and equipment $ 267,874 $ 271,434 As of March 31, 2019, and December 31, 2018, the Company had approximately $5.4 million of unproved oil and gas properties not subject to depletion. The costs not subject to depletion relate to unproved properties that are excluded from amortized capital costs until it is determined if proved reserves can be assigned to such properties. The excluded properties are assessed for impairment at least annually. Subject to industry conditions, evaluation of most of these properties and the inclusion of their costs in amortized capital costs is expected to be completed within five years. During the three months ended March 31, 2019 and 2018, there were no expiring leasehold costs that were reclassified into proved property. The excluded properties are assessed for impairment at least annually. Subject to industry conditions, evaluations of most of these properties and the inclusion of their costs in amortized capital costs is expected to be completed within five years. We capitalized overhead applicable to acquisition, development and exploration activities of approximately $68,000 and $71,000 for the three months ended March 31, 2019 and 2018, respectively. Depletion expense related to oil and gas properties for the three months ended March 31, 2019 and 2018 was approximately $3.5 million, or $0.54 per Mcfe, and $1.3 million, or $0.82 per Mcfe, respectively.

Asset Retirement Obligation

Asset Retirement Obligation	3 Months Ended
	Mar. 31, 2019
Asset Retirement Obligation [Abstract]
Asset Retirement Obligation	Note 5 – Asset Retirement Obligation Asset Retirement Obligations The Company's asset retirement obligations (" ARO The estimated ARO liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or increased as a result of a reassessment of expected cash flows and assumptions inherent in the estimation of the liability. Upward revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. AROs are valued utilizing Level 3 fair value measurement inputs. The following table is a reconciliation of the ARO for the three months ended March 31, 2019 and 2018: (in thousands) Three Months Ended 2019 2018 Balance at beginning of period $ 22,310 $ 7,737 Accretion expense 394 141 Additions during period - 2,921 22,704 10,799 Less: ARO recognized as a current liability (3,392 ) (767 ) Balance at end of period $ 19,312 $ 10,032

Investments in Affiliates

Investments in Affiliates	3 Months Ended
	Mar. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Investments in Affiliates	Note 6 – Investments in Affiliates Carbon Appalachia For the period April 3, 2017 (inception) through December 31, 2018, based on our 27.24% combined Class A, Class B and Class C interest (and our ability as of December 31, 2018 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 accounted for our investment in Carbon Appalachia under the equity method of accounting as we believed we exerted significant influence. We used the HLBV to determine our share of profits or losses in Carbon Appalachia and adjusted the carrying value of our investment accordingly. Our investment in Carbon Appalachia is represented by our Class A and C interests, which we 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. On December 31, 2018, we acquired all of Old Ironsides’ Class A Units of Carbon Appalachia for approximately $58.1 million, subject to customary and standard closing adjustments. We paid $ 33.0 million in cash and issued the Old Ironsides Notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides. Effective December 31, 2018, upon the closing of the OlE Membership Acquisition, we consolidate Carbon Appalachia in our consolidated financial statements. Carbon California For the period February 15, 2017 (inception) through January 31, 2018, based on our 17.81% interest in Carbon California, our ability to appoint a member to the board of directors and our role of manager of Carbon California, we accounted for our investment in Carbon California under the equity method of accounting as we believed we exerted significant influence. We used the Hypothetical Liquidation at Book Value Method (“ HLBV Effective February 1, 2018, upon the exercise of the California Warrant, we consolidate Carbon California in our consolidated financial statements. Other Affiliates At March 31, 2019 and December 31, 2018, we retained interests in two equity method investments associated with the development and transportation of oil and gas.

Credit Facilities and Notes Pay

Credit Facilities and Notes Payable	3 Months Ended
	Mar. 31, 2019
Debt Disclosure [Abstract]
Credit Facilities and Notes Payable	Note 7 – Credit Facilities and Notes Payable Carbon Appalachia The table below summarizes the outstanding credit facilities and notes payable: (in thousands) March 31, 2019 December 31, 2018 2018 Credit Facility – revolver $ 70,150 $ 69,150 2018 Credit Facility – term note 13,333 15,000 Old Ironsides Notes 23,659 25,065 Other debt 48 57 Total principal 107,190 109,272 Less: unamortized debt discount (112 ) (134 ) Total credit facilities and notes payable $ 107,078 $ 109,138 The current portion of the outstanding credit facilities and notes payable was approximately $9.9 million as of March 31, 2019 and $11.9 million as of December 31, 2018. 2018 Credit Facility In connection with and concurrently with the closing of the OIE Membership Acquisition, the Company and its subsidiaries amended and restated our prior credit facilities for a new $500.0 million senior secured asset-based revolving credit facility maturing December 31, 2022 and a $15.0 million term loan which matures in 2020 (the “2018 Credit Facility” “CAE” “Borrowers” The 2018 Credit Facility is guaranteed by each existing and future direct or indirect subsidiary of the Borrowers and certain other subsidiaries of the Company (subject to various exceptions) and the obligations under the 2018 Credit Facility are secured by essentially all tangible, intangible and real property (subject to certain exclusions). Interest accrues on borrowings under the 2018 Credit Facility at a rate per annum equal to either (i) the base rate plus an applicable margin equal to 0.25% - 0.75% depending on the utilization percentage or (ii) the Adjusted LIBOR rate plus an applicable margin equal to 2.75% - 3.75% depending on the utilization percentage, at the Borrowers’ option. The Borrowers are obligated to pay certain fees and expenses in connection the 2018 Credit Facility, including a commitment fee for any unused amounts of 0.50% and an origination fee of 0.50%. Loans under the 2018 Credit Facility may be prepaid without premium or penalty. The 2018 Credit Facility also provides for a $15.0 million term loan which bears interest at a rate of 6.25% and is payable in 18 equal monthly installments beginning February 1, 2019 with the last payment due on June 30, 2020. The 2018 Credit Facility contains certain affirmative and negative covenants that, among other things, limit the Company’s ability to (i) incur additional debt; (ii) incur additional liens; (iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distribution on, or repurchase of, equity; (vi) make certain investments; (vii) enter into certain transactions with their affiliates; (viii) enter in sale-leaseback transactions; (ix) make optional or voluntary payment of debt other than obligations under the 2018 Credit Facility; (x) change the nature of their business; (xi) change their fiscal year or make changes to the accounting treatment or reporting practices; (xii) amend their 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 2018 Credit Facility requires the Borrowers’ compliance, on a consolidated basis, with a maximum Net Debt (all debt of the Borrowing Parties minus all unencumbered cash and cash equivalents of the Borrowers not to exceed $3.0 million) / EBITDAX (as defined) ratio of 3.50 to 1.00 and a current ratio, as defined, minimum of 1.00 to 1.00, tested quarterly, commencing with the quarter ending March 31, 2019. We are in compliance with our financial covenants as of March 31, 2019 and expect to be in compliance with these covenants throughout the next twelve month period. We are currently engaged in discussions with LegacyTexas Bank to decrease the required hedging period of our expected future production from 30 months to 24 months. As of March 31, 2019, there was approximately $70.2 million in outstanding borrowings and $4.8 million of additional borrowing capacity under the 2018 Credit Facility. The terms of the 2018 Credit Facility require us to enter 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 into by us and BP Energy Company is secured by the collateral and backed by the guarantees supporting the 2018 Credit Facility. Fees paid in connection with the 2018 Credit Facility totaled $779,000, of which $134,000 was associated with the term loan. The current portion of unamortized fees is included in prepaid expense, deposits and other current assets and the non-current portion is included in other non-current assets. The unamortized portion associated with the term loan was $112,000 as of March 31, 2019, and is directly offset against the loan in non-current liabilities. As of March 31, 2019, we had unamortized deferred issuance costs of $604,000 associated with the 2018 Credit Facility. During the three months ended March 31, 2019, we amortized approximately $63,000 as interest expense associated with the 2018 Credit Facility. Old Ironsides Notes On December 31, 2018, as part of the OIE Membership Acquisition, we delivered unsecured, promissory notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides (the “ Old Ironsides Notes The interest payable under the Old Ironsides Notes can be paid-in-kind at the election of the Company. This provision allows the Company to increase the principal balance associated with the Old Ironsides Notes. This election creates a second tranche of principal, which bears interest at 12% per annum. On March 31, 2019, the Company elected to pay-in-kind approximately $594,000. Carbon California The table below summarizes the outstanding notes payable – related party: (in thousands) March 31, 2019 December 31, 2018 Senior Revolving Notes, related party, due February 15, 2022 $ 38,500 $ 38,500 Subordinated Notes, related party, due February 15, 2024 13,000 13,000 Total principal 51,500 51,500 Less: Deferred notes costs (255 ) (235 ) Less: unamortized debt discount (1,281 ) (1,346 ) Total notes payable – related party $ 49,964 $ 49,919 Senior Revolving Notes, Related Party On February 15, 2017, Carbon California entered into a Note Purchase Agreement (the “ Note Purchase Agreement ” Senior Revolving Notes Carbon California may elect to incur interest at either (i) 5.50% plus the London interbank offered rate (“ LIBOR The Senior Revolving Notes are secured by all the assets of Carbon California. The Senior Revolving Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated proved developed production at such time for year one, two and three at a rate of 75%, 65% and 50%, respectively. Carbon California may make principal payments in minimum installments of $500,000. Distributions to equity members are generally restricted. Carbon California incurred fees directly associated with the issuance of the Senior Revolving Notes and amortizes these fees over the life of the Senior Revolving Notes. The current portion of these fees are included in prepaid expense and deposits and the long-term portion is included in other non-current assets for a combined value of approximately $939,000. For the three months ended March 31, 2019, Carbon California amortized fees of $74,000. Carbon California may at any time repay the Senior Revolving Notes, in whole or in part, without penalty. Carbon California must pay down Senior Revolving Notes or provide mortgages of additional oil and natural gas properties to the extent that outstanding loans and letters of credit exceed the borrowing base. Subordinated Notes, Related Party On February 15, 2017, Carbon California entered into a Securities Purchase Agreement (the “ Securities Purchase Agreement Subordinated Notes Prudential received an additional 1,425 Class A Units, representing 5% of total sharing percentage, for the issuance of the Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding Subordinated Notes of $10.0 million. The Company then allocated the non-cash value of the units of approximately $1.3 million, which was recorded as a discount to the Subordinated Notes. As of March 31, 2019, Carbon California has an outstanding discount of approximately $869,000, which is presented net of the Subordinated Notes within Credit facility-related party on the unaudited consolidated balance sheets. During the three months ended March 31, 2019, Carbon California amortized $45,000 associated with the Subordinated Notes. The Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively. Prepayment of the Subordinated Notes is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted. 2018 Subordinated Notes, Related Party On May 1, 2018, Carbon California entered into an agreement with Prudential for the issuance and sale of $3.0 million in Subordinated Notes due February 15, 2024, bearing interest of 12% per annum (the “ 2018 Subordinated Notes Prudential received 585 Class A Units, representing an approximate 2% additional sharing percentage, for the issuance of the Carbon California 2018 Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding 2018 Subordinated Notes of $3.0 million. The Company then allocated the non-cash value of the units of approximately $490,000, which was recorded as a discount to the 2018 Subordinated Notes. As of March 31, 2019, Carbon California had an outstanding discount of $412,000 associated with these notes, which is presented net of the 2018 Subordinated Notes within Credit facility - related party on the unaudited consolidated balance sheets. During the three months ended March 31, 2019, Carbon California amortized $21,000 associated with the 2018 Subordinated Notes. The 2018 Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively. Prepayment of the 2018 Subordinated Notes is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted. Restrictions and Covenants The Senior Revolving Notes, Subordinated Notes and 2018 Subordinated Notes contain affirmative and negative covenants that, among other things, limit Carbon California’s ability to (i) incur additional debt; (ii) incur additional liens; (iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distributions on, or repurchases of, equity; (vi) make certain investments; (vii) enter into certain transactions with our affiliates; (viii) enter into sales-leaseback transactions; (ix) make optional or voluntary payments 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 basket amounts and acceptable transaction levels. In addition, (i) the Senior Revolving Notes require Carbon California’s compliance, on a consolidated basis, with (A) a maximum Debt/EBITDA ratio of 4.0 to 1.0, stepping down to 3.5 to 1.0 starting with the quarter ending June 30, 2018, (B) a maximum Senior Revolving Notes/EBITDA ratio of 2.5 to 1.0, (C) a minimum interest coverage ratio of 3.0 to 1.0 and (D) a minimum current ratio of 1.0 to 1.0 and (ii) the Subordinated Notes require Carbon California’s compliance, on a consolidated basis, with (A) a maximum Debt/EBITDA ratio of 4.5 to 1.0, stepping down to 4.0 to 1.0 starting with the quarter ending June 30, 2018, (B) a maximum Senior Revolving Notes/EBITDA ratio of 3.0 to 1.0, (C) a minimum interest coverage ratio of 2.5 to 1.0, (D) an asset coverage test whereby indebtedness may not exceed the product of 0.65 times Adjusted PV-10 set forth in the most recent reserve report, (E) maintenance of a minimum borrowing base of $10,000,000 under the Senior Revolving Notes and (F) a minimum current ratio of 0.85 to 1.00.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Note 8 – Income Taxes We recognize deferred income tax assets and liabilities for the estimated future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. We have net operating loss carryforwards available in certain jurisdictions to reduce future taxable income. Future tax benefits for net operating loss carryforwards are recognized to the extent that realization of these benefits is considered more likely than not. To the extent that available evidence raises doubt about the realization of a deferred income tax asset, a valuation allowance is established. At March 31, 2019 the Company has established a full valuation allowance against the balance of net deferred tax assets.

Stockholders' Equity

Stockholders' Equity	3 Months Ended
	Mar. 31, 2019
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. On June 1, 2018, we amended our charter to increase the number of authorized shares of our common stock from 10.0 million to 35.0 million. As of March 31, 2019, we had 35.0 million shares of common stock authorized with a par value of $0.01 per share, of which approximately 7.8 million were issued and outstanding, and 1.0 million shares of preferred stock authorized with a par value of $0.01 per share. During the first three months of 2019, the increase in the Company’s issued and outstanding common stock was a result of restricted stock and performance units that vested during the period. 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 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, 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 As of March 31, 2019, approximately 649,000 shares of restricted stock have been granted under the terms of the Carbon Plans. 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. During the three months ended March 31, 2019, approximately 40,000 restricted stock units vested. Compensation costs recognized for these restricted stock grants were approximately $179,000 for the three months ended March 31, 2019. For the three months ended March 31, 2018, we recognized compensation expense of approximately $158,000. As of March 31, 2019, there was approximately $1.2 million unrecognized compensation costs related to these restricted stock grants which we expect to be recognized over the next six years. Restricted Performance Units As of March 31, 2019, approximately 621,000 shares of performance units have been granted under the terms of the Carbon Plans. 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. We account for the performance units granted during 2015 through 2018 at their fair value determined at the date of grant, which were $8.00, $5.40, $7.20 and $9.80 per share, respectively. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At March 31, 2019, we estimated that none of the performance units granted in 2017 and 2018 would vest, and, accordingly, no compensation cost has been recorded for these performance units. We estimated that it was probable that the performance units granted in 2015 and 2016 would vest and therefore compensation costs of approximately $43,000 and $135,000 related to these performance units were recognized for the three months ended March 31, 2019 and 2018, respectively. As of March 31, 2019, compensation costs related to the performance units granted in 2015 and 2016 have been fully recognized. As of March 31, 2019, 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 2012, 2017 and 2018 would be approximately $2.7 million. Preferred Stock Series B Convertible Preferred Stock - Related Party In connection with the closing of the Seneca Acquisition, we raised $5.0 million through the issuance of 50,000 shares of Preferred Stock to Yorktown. The Preferred Stock converts into common stock at the election of the holder or will automatically convert into shares of our common stock upon completion of a qualifying equity financing event. The number of shares of common stock issuable upon conversion is dependent upon the price per share of common stock issued in connection with any such qualifying equity financing but has a floor conversion price equal to $8.00 per share. The conversion ratio at which the Preferred Stock will convert into common stock is equal to an amount per share of $100 plus all accrued but unpaid dividends payable in respect thereof divided by the greater of (i) $8.00 per share or (ii) the price that is 15% less than the lowest price per share of shares sold to the public in the next equity financing. Using the floor of $8.00 per share would yield 12.5 shares of common stock for every unit of Preferred Stock. The conversion price will be proportionately increased or decreased to reflect changes to the outstanding shares of common stock, such as the result of a combination, reclassification, subdivision, stock split, stock dividend or other similar transaction involving the common stock. Additionally, after the third anniversary of the issuance of the Preferred Stock, we have the option to redeem the shares for cash. The Preferred Stock accrues cash dividends at a rate of six percent (6%) of the initial issue price of $100 per share per annum. The holders of the Preferred Stock are entitled to the same number of votes of common stock that such share of Preferred Stock would represent on an as converted basis. The holders of the Preferred Stock receive liquidation preference based on the initial issue price of $100 per share plus a preferred return over common stock holders and the holders of any junior ranking stock. As of March 31, 2019, the preferred return was approximately $299,000. We apply the guidance in ASC 480 “ Distinguishing Liabilities from Equity We have evaluated the Preferred Stock in accordance with ASC 815, “ Derivatives and Hedging BCF APIC Debt

Revenue Recognition

Revenue Recognition	3 Months Ended
	Mar. 31, 2019
Revenue Recognition and Deferred Revenue [Abstract]
Revenue Recognition	Note 10 – Revenue Recognition Revenue from Contracts with Customers The Company recognizes revenue in accordance with FASB ASC Topic 606 – Revenue Recognition ASC 606 Performance Obligations and Significant Judgments We sell oil and natural gas products in the United States through a single reportable segment. We primarily sell products within two regions of the United States: Appalachian Basin and Ventura Basin. We enter into contracts that generally include one type of distinct product in variable quantities and priced based on a specific index related to the type of product. Most of our contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. The oil and natural gas is typically sold in an unprocessed state to third party purchasers. We recognize revenue based on the net proceeds received from the purchaser when control of the oil or natural gas passes to the purchaser. For oil sales, control is typically transferred to the purchaser upon receipt at the wellhead or a contractually agreed upon delivery point. Under our natural gas contracts with purchasers, control transfers upon delivery at the wellhead or the inlet of the purchaser’s system. For our other natural gas contracts, control transfers upon delivery to the inlet or to a contractually agreed upon delivery point. Transfer of control drives the presentation of transportation and gathering costs within the accompanying unaudited consolidated statements of operations. Transportation and gathering costs incurred prior to control transfer are recorded within the transportation and gathering expense line item on the accompanying unaudited consolidated statements of operations, while transportation and gathering costs incurred subsequent to control transfer are recognized as a reduction to the related revenue. A portion of our product sales are short-term in nature. For those contracts, we use the practical expedient in ASC 606 exempting us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606 which states we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to an unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore, future volumes are unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. We have no unsatisfied performance obligations at the end of each reporting period. We do not believe that significant judgments are required with respect to the determination of the transaction price, including any variable consideration identified. There is a low level of uncertainty due to the precision of measurement and use of index-based pricing with predictable differentials. Additionally, any variable consideration identified is not constrained. Disaggregation of Revenues In the following tables, revenue for the three months ended March 31, 2019, is disaggregated by primary region within the United States and major product line. As noted above, we operate as one reportable segment. For the three months ended March 31, 2019: (in thousands) Type Appalachian Basin Ventura Basin Total Natural gas sales $ 18,792 $ 524 $ 19,316 Natural gas liquids sales - 247 247 Oil sales 1,537 7,452 8,989 Transportation and handling 734 - 734 Marketing gas sales 4,944 - 4,944 Total revenue $ 26,007 $ 8,223 $ 34,230 Contract Balances Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not typically give rise to contract assets or liabilities under ASC 606. Prior Period Performance Obligations We record revenue in the month production is delivered to the purchaser, but settlement statements may not be received until 30 to 90 days after the month of production. As such, we estimate the production delivered and the related pricing. Any differences between our initial estimates and actuals are recorded in the month payment is received from the customer. These differences have not historically been material. For the three months ended March 31, 2019, revenue recognized in the reporting period related to prior period performance obligations is immaterial. The estimated revenue is recorded within Accounts receivable – Revenue on the unaudited consolidated balance sheets.

Accounts Payable and Accrued Li

Accounts Payable and Accrued Liabilities	3 Months Ended
	Mar. 31, 2019
Payables and Accruals [Abstract]
Accounts Payable and Accrued Liabilities	Note 11 – Accounts Payable and Accrued Liabilities Accounts payable and accrued liabilities at March 31, 2019 and December 31, 2018 consist of the following: (in thousands) March 31, December 31, Accounts payable $ 6,064 $ 7,670 Oil and gas revenue suspense 2,766 2,675 Gathering and transportation payables 1,228 1,774 Production taxes payable 2,411 1,860 Accrued operating costs 2,431 3,155 Accrued ad valorem taxes – current 3,731 3,474 Accrued general and administrative expenses 2,217 3,111 Accrued asset retirement obligation – current 3,392 3,099 Accrued interest 1,543 955 Accrued gas purchases 2,959 5,440 Other liabilities 1,278 1,603 Total accounts payable and accrued liabilities $ 30,020 $ 34,816

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 12 – 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 March 31, 2019 Assets: Commodity derivatives $ - $ 147 $ - $ 147 Liabilities: Commodity derivatives $ - $ 1,975 $ - $ 1,975 December 31, 2018 Asset: Commodity derivatives $ - $ 7,022 $ - $ 7,022 Commodity Derivative As of March 31, 2019, our commodity derivative financial instruments are comprised of natural gas and oil swaps and costless collars. 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 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 our outstanding commodity derivative financial instruments as of March 31, 2019, is BP Energy Company. 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. 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 contract obligations was determined based upon the contractual obligations assumed by us and discounted based upon our effective borrowing rate. These contractual obligations are reduced on a monthly basis as we pay these firm transportation obligations in the future. The fair value measurements associated with the assets acquired and liabilities assumed in the business combination for the OIE Membership Acquisition of Carbon Appalachia are outlined within Note 3. Debt Discount The fair value of the debt discount from the 1,425 and 585 additional Class A Units issued in connection with the Subordinated Notes and 2018 Subordinated Notes was $1.3 million and $490,000, respectively. The debt discount was a Level 3 fair value assessment and was based on the relative fair value of Class A Units. Class A Units were issued contemporaneously at $1,000 per Class A Unit. Asset Retirement Obligation 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.

Commodity Derivatives

Commodity Derivatives	3 Months Ended
	Mar. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivatives	Note 13 – Commodity Derivatives We historically use commodity-based derivative contracts to manage exposures to commodity price on a portion 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, on occasion, oil and natural gas physical 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. These contracts are not recorded at fair value in the unaudited condensed consolidated financial statements. Pursuant to the terms of our credit facilities with LegacyTexas Bank and Prudential, we have entered into swap and costless collar derivative agreements to hedge a portion of our oil and natural gas production through 2021. As of March 31, 2019, these derivative agreements consisted of the following: Natural Gas Swaps Natural Gas Collars Weighted Average Weighted Average Price Year MMBtu Price (a) MMBtu Range (a) 2019 11,762,000, $ 2.82 374,000 $ 2.60 – $3.03 2020 12,433,000 $ 2.73 1,018,000 $ 2.50 – $2.70 2021 6,448,000 $ 2.58 - $ - Oil Swaps Oil Collars Year WTI Bbl Weighted Average Price (b) Brent Bbl Weighted Average Price (c) WTI Bbl Weighted Average Price Brent Bbl Weighted Average Price 2019 180,775 $ 53.46 121,079 $ 66.93 - - 29,800 $ 47.00 - $75.00 2020 121,147 $ 55.37 151,982 $ 66.03 18,000 $ 47.00 - $60.15 37,400 $ 47.00 - $75.00 2021 - $ - 86,341 $ 67.12 30,000 $ 47.00 - $60.15 98,000 $ 47.00 - $75.00 * Includes 100% of Carbon California’s outstanding derivative hedges at March 31, 2019, and not our proportionate share. (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. (c) Brent future contracts for the respective period. For our swap instruments, we receive a fixed price for the hedged commodity and pay 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 the Company 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 unaudited consolidated balance sheets. These derivative instruments are not designated as cash flow hedging instruments for accounting purposes: (in thousands) March 31, 2019 December 31, 2018 Commodity derivative contracts: Commodity derivative asset $ - $ 3,517 Commodity derivative asset – non-current $ 147 $ 3,505 Commodity derivative liability $ 1,657 $ - Commodity derivative liability – non-current $ 318 $ - The table below summarizes the commodity settlements and unrealized gains and losses related to the Company’s derivative instruments for the three months ended March 31, 2019 and 2018. These commodity derivative settlements and unrealized gains and losses are recorded and included in commodity derivative income or loss in the accompanying unaudited consolidated statements of operations. Three Months Ended (in thousands) 2019 2018 Commodity derivative contracts: Settlement losses $ (456 ) $ (377 ) Unrealized losses (8,850 ) (249 ) Total settlement and unrealized losses, net $ (9,306 ) $ (626 ) Commodity derivative settlement gains and losses are included in cash flows from operating activities in our unaudited consolidated statements of cash flows. The counterparty in all of our derivative instruments is BP Energy Company. We have entered into ISDA Master Agreements with BP Energy Company that establishes standard terms for the derivative contracts and inter-creditor agreements with LegacyTexas Bank, Prudential 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 facilities. We net our derivative instrument fair value amounts executed with BP Energy Company pursuant to ISDA master agreements, 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 unaudited consolidated balance sheet, as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited consolidated balance sheet as of March 31, 2019. Net Gross Recognized Recognized Gross Fair Value Assets/ Amounts Assets/ Balance Sheet Classification (in thousands) Liabilities Offset Liabilities Commodity derivative assets: Commodity derivative asset $ 1,063 $ (1,063 ) $ - Commodity derivative asset – non-current 2,049 (1,902 ) 147 Total derivative assets $ 3,112 $ (2,965 ) $ 147 Commodity derivative liabilities: Commodity derivative liability $ 2,720 $ (1,063 ) $ (1,657 ) Commodity derivative liability – non-current 2,220 (1,902 ) (318 ) Total derivative liabilities $ 4,940 $ (2,965 ) $ (1,975 ) Due to the volatility of oil and natural gas prices, the estimated fair value of our derivatives are subject to fluctuations from period to period.

Leases

Leases	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
Leases	Note 14 – Leases On January 1, 2019, we adopted ASC 842. Results for reporting periods beginning January 1, 2019 are presented in accordance with ASC 842, while prior period amounts are reported in accordance with FASB ASC Topic 840 – Leases The lease amounts disclosed herein are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners, and our net share of these costs, once paid, are included in lease operating expenses, pipeline operating expenses or general and administrative expenses, as applicable. During the three months ended March 31, 2019, we did not acquire any right-of-use assets or incur any lease liabilities. Our right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet at $7.3 million as of March 31, 2019. All leases recognized on our unaudited consolidated balance sheet are classified as operating leases, which include leases related to the asset classes reflected in the table below: (in thousands) Right-of-Use Assets Lease Compressors $ 4,178 $ 4,178 Corporate leases 2,433 2,438 Vehicles 645 645 Total $ 7,256 $ 7,261 We recognize lease expense on a straight-line basis excluding short-term and variable lease payments which are recognized as incurred. Short-term lease cost represents payments for leases with a lease term of one year or less, excluding leases with a term of one month or less. Short-term leases include certain compressors and vehicles that have a non-cancellable lease term of less than one year. The following table summarizes the components of our gross operating lease costs incurred during the three months ended March 31, 2019: (in thousands) Three Months Ended March 31, Operating lease cost $ 531 Short-term lease cost 161 Total lease cost $ 692 We do not have any leases with an implicit interest rate that can be readily determined. As a result, we calculate collateralized incremental borrowing rates to use as discount rates. We utilize the benchmark rates defined in our credit facilities, and adjust for facility utilization and term considerations, to establish collateralized incremental borrowing rates. Refer to Note 7 for additional information on our credit facilities. Our weighted-average lease term and discount rate used are as follows: (in thousands) Three Months Ended March 31, Weighted-average lease term (years) 4.3 Weighted-average discount rate 6.34 % The following table summarizes supplemental cash flow information related to leases: Cash paid for amounts included in measurement of lease liabilities (in thousands) Three Months Ended March 31, Operating cash flows for operating leases $ 526 Minimum future commitments by year for our long-term operating leases as of March 31, 2019 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet as follows: (in thousands) Amount Remainder of 2019 $ 1,535 2020 1,946 2021 1,889 2022 1,718 2023 1,222 Thereafter 11 Total lease payments $ 8,321 Less: imputed interest (1,060 ) Total lease liability $ 7,261

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 15 – 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 non-current 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 March 31, 2019 are summarized in the table below. Period Dekatherms per day Demand Charges Apr 2019 – Mar 2020 58,871 $ 0.20 - 0.62 Apr 2020 – May 2020 57,791 $ 0.20 - 0.56 Jun 2020 – Oct 2020 56,641 $ 0.20 - 0.56 Nov 2020 – Aug 2022 50,341 $ 0.20 - 0.56 Sep 2022 – May 2027 30,990 $ 0.20 - 0.21 Jun 2027 – May 2036 1,000 $ 0.20 As of March 31, 2019, the remaining commitment related to the firm transportation contracts assumed in the EXCO Acquisition in 2016 and OIE Membership Acquisition is $17.8 million and reflected in the Company’s unaudited consolidated balance sheet. The fair values of these firm transportation obligations were determined based upon the contractual obligations assumed by the Company and discounted based upon the Company’s effective borrowing rate. These contractual obligations are being reduced monthly as the Company pays these firm transportation obligations in the future. Natural gas processing agreement We have entered into an initial five-year gas processing agreement. We have an option to extend the term of the agreement by another five years. The related demand charges for volume commitments over the remaining term of the agreement at March 31, 2019 are approximately $1.8 million per year. We will pay a processing fee of $2.50 per MCF for the term of the agreement, with a minimum annual volume commitment of 720,000 MCF. Capital Commitments As of March 31, 2019, we had no capital commitments associated with Carbon California.

Supplemental Cash Flow Disclosu

Supplemental Cash Flow Disclosure	3 Months Ended
	Mar. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Disclosure	Note 16 – Supplemental Cash Flow Disclosure Supplemental cash flow disclosures for the three months ended March 31, 2019 and 2018 are presented below: Three Months Ended (in thousands) 2019 2018 Cash paid during the period for: Interest $ 1,875 $ 336 Non-cash transactions: Accounts payable and accrued liabilities $ 82 $ (71 ) Non-cash acquisition of Carbon California interests $ - $ (18,906 ) Carbon California Acquisition on February 1, 2018 $ - $ 17,114 Exercise of warrant derivative $ - $ (1,792 ) Old Ironsides Notes interest paid-in-kind $ 594 -

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2019
Subsequent Events [Abstract]
Subsequent Events	Note 17 – Subsequent Events We evaluated activities from March 31, 2019, to the date these financial statements were available for issuance. We believe there are no subsequent events requiring recognition or disclosure.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2019
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“ GAAP
Principles of Consolidation	Principles of Consolidation The unaudited condensed consolidated financial statements include the accounts of our consolidated subsidiaries. Upon the closing of the OIE Membership Acquisition on December 31, 2018, we own 100% of Carbon Appalachia. In addition, we own 100% of Nytis USA, which owns approximately 98.1% of Nytis LLC. Nytis LLC holds interests in various oil and gas partnerships. Partnerships and subsidiaries in which we have a controlling interest are consolidated. We are currently consolidating 46 partnerships, Carbon Appalachia, and Carbon California, and we reflect the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on our unaudited consolidated statements of operations and also reflect the non-controlling ownership interest in the net assets of the partnerships as non-controlling interests within stockholders’ equity on our unaudited consolidated balance sheets. All significant intercompany accounts and transactions have been eliminated. In accordance with established practice in the oil and gas industry, our unaudited condensed 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 unaudited condensed consolidated financial statements.
Reclassifications	Reclassifications Certain prior period balances in the consolidated balance sheets and statements of operations have been reclassified to conform to the current year presentation. Specifically, a portion of credit facilities and notes payable balances as of December 31, 2018 were reclassified from non-current liabilities to current liabilities. This reclassification had no impact on net income, cash flows or shareholders’ equity previously reported.
Insurance Receivable	Insurance Receivable Insurance receivable is comprised of insurance claims for the loss of property as a result of wildfires that impacted Carbon California in December 2017. The Company filed claims with its insurance provider. In January 2019, we reached a settlement agreement and received an $800,000 payment from our insurance provider related to the damage caused by the California wildfires. As of March 31, 2019, we are in receipt of all funds associated with the claims.
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 incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Overhead costs incurred that are directly identified with acquisition, exploration and development activities undertaken by the Company for its own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized. Unproved properties are excluded from amortized capitalized costs until it is determined if 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 oil to gas at the ratio of one barrel of oil to six thousand cubic feet of natural gas. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves. All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred. 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 would be recognized to the extent of the excess capitalized costs. Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds the capitalized costs in future periods. For the three months ended March 31, 2019 and 2018, we did not recognize a ceiling test impairment as our full cost pool did not exceed the ceiling limitations. Future declines in oil and natural gas prices could result in impairments of our oil and gas properties in future periods. The effect of price declines will impact the ceiling test value until such time commodity prices stabilize or improve. Impairments are a non-cash charge and accordingly would not affect cash flows but would adversely affect our results of operations and members’ equity. We capitalize the portion of general and administrative costs that is attributable to our acquisition, exploration and development activities.
Revenue	Revenue We recognize revenues for sales and services when persuasive evidence of an arrangement exists, when custody is transferred, or services are rendered, fees are fixed or determinable and collectability is reasonably assured. Oil, Natural Gas and Natural Gas Liquid Sales Oil, natural gas and natural gas liquid sales 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. Revenues are recognized based on our net revenue interest. Marketing Gas Sales We sell production purchased from third parties as well as production from our own oil and gas producing properties. Marketing gas sales are recognized on a gross basis as we purchase and take control of the gas prior to sale and are the principal in the transaction. Storage Under fee-based arrangements, we receive a fee for storing natural gas. The revenues earned are directly related to the volume of natural gas that flows through our systems and are not directly dependent on commodity prices. Transportation, gathering, and compression We generally purchase natural gas from producers at the wellhead or other receipt points, gather the wellhead natural gas through our gathering systems, and then sell the natural gas based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of natural gas or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, regardless of the actual amount of the sales proceeds we receive. Our revenues under percent-of-proceeds/index arrangements generally correlate to the price of natural gas.
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 can 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. Equity method investments will increase or decrease by our share of the affiliate’s profits or losses and such profits or losses are recognized in our unaudited consolidated statements of operations. We review equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred. Upon the exercise of the California Warrant on February 1, 2018 and the closing of the OIE Membership Acquisition on December 31, 2018, we consolidate Carbon California and Carbon Appalachia for financial reporting purposes and no longer account for these investments under the equity method.
Related Party Transactions	Related Party Transactions Management Reimbursements In our role as manager of Carbon California and Carbon Appalachia we receive reimbursements for management services. Prior to consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, these management service reimbursements were included in general and administrative – related party reimbursement on our unaudited consolidated statements of operations. As we now consolidate both Carbon California and Carbon Appalachia, these reimbursements are eliminated upon consolidation. We received approximately $753,000 and $50,000 for the three months ended March 31, 2018, and for the one month ended January 31, 2018, from Carbon Appalachia and Carbon California, respectively. These reimbursements are included in general and administrative – related party reimbursement on our unaudited consolidated statements of operations. Effective February 1, 2018, the management reimbursements received from Carbon California were eliminated at consolidation. This elimination included $100,000 for the period February 1, 2018, through March 31, 2018. In addition to the management reimbursements, approximately $299,000 and $14,000 in general and administrative expenses were reimbursed for the three months ended March 31, 2018, and for the one month ended January 31, 2018, by Carbon Appalachia and Carbon California, respectively. The elimination of Carbon California in consolidation includes approximately $28,000 for the period February 1, 2018, through March 31, 2018. Operating Reimbursements In our role as operator of Carbon California and Carbon Appalachia, we receive reimbursements of operating expenses. Prior to consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, these operating reimbursements were included in operating expenses on our unaudited consolidated statements of operations. As we now consolidate both Carbon California and Carbon Appalachia, any intercompany receivable and payable balances associated with these reimbursements are eliminated upon consolidation. Carbon California Credit Facilities The credit facilities of Carbon California, including the Senior Revolving Notes, Carbon California Notes and Carbon California 2018 Subordinated Notes (all defined below), are held by Prudential (see Note 7).
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and expenses and disclosure of contingent assets and liabilities. Significant items subject to such estimates and assumptions include the carrying value of oil and gas properties, estimates 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 fair value of commodity derivative instruments, fair value of assets acquired and liabilities assumed qualifying as business combinations or asset acquisitions, estimated lives of other property and equipment, asset retirement obligations, fair value of Class B issuances and accrued liabilities and revenues. There have been no changes in our critical accounting estimates from those that were disclosed in the 2018 Annual Report on Form 10-K. Actual results could differ from these estimates.
Earnings (Loss) Per Common Share	Earnings (Loss) Per Common Share Basic earnings per common share is computed by dividing the net income or 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). In periods when we report a net loss, all shares of restricted stock are excluded from the calculation of diluted weighted average shares outstanding because of its anti-dilutive effect on loss per share. As a result, approximately 269,000 potentially dilutive restricted stock awards are excluded from the calculation of diluted earnings per common share for the three months ended March 31, 2019. In addition, approximately 200,000 restricted performance units subject to future contingencies were excluded in the basic and diluted income per share calculations. For the three months ended March 31, 2018, we had net income and the diluted income per common share calculation includes the dilutive effects of approximately 230,000 non-vested shares of restricted stock. In addition, approximately 254 ,000 restricted performance units subject to future contingencies were excluded in the basic and diluted income per share calculations. The following table sets forth the calculation of basic and diluted (loss) income per share: Three months ended (in thousands except per share amounts) 2019 2018 Net (loss) income attributable to common shareholders $ (4,175 ) $ 3,569 Less: warrant derivative gain - (225 ) Diluted net income (4,175 ) 3,344 Basic weighted-average common shares outstanding during the period 7,663 6,996 Add dilutive effects of warrants and non-vested shares of restricted stock 269 230 Diluted weighted-average common shares outstanding during the period 7,932 7,226 Basic net (loss) income per common share $ (0.54 ) $ 0.51 Diluted net (loss) income per common share $ (0.54 ) $ 0.46
Recently Adopted Accounting Pronouncement	Recently Adopted Accounting Pronouncement In February 2016, the FASB issued Accounting Standards Update (“ ASU Leases ASC Leases ASC 842
Recently Issued Accounting Pronouncements	Recently Issued Accounting Pronouncements There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2019
Accounting Policies [Abstract]
Schedule of basic and diluted income (loss) per share	Three months ended (in thousands except per share amounts) 2019 2018 Net (loss) income attributable to common shareholders $ (4,175 ) $ 3,569 Less: warrant derivative gain - (225 ) Diluted net income (4,175 ) 3,344 Basic weighted-average common shares outstanding during the period 7,663 6,996 Add dilutive effects of warrants and non-vested shares of restricted stock 269 230 Diluted weighted-average common shares outstanding during the period 7,932 7,226 Basic net (loss) income per common share $ (0.54 ) $ 0.51 Diluted net (loss) income per common share $ (0.54 ) $ 0.46

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	3 Months Ended
	Mar. 31, 2019
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Schedule of unaudited pro-forma consolidated results	Three Months Ended March 31, Three Months Ended March 31, (in thousands, except per share amounts) 2019 2018 Revenue $ 24,950 $ 6,672 Net (loss) income before non-controlling interests $ (6,690 ) $ 3,543 Net (loss) income attributable to non-controlling interests $ (2,590 ) $ 1,115 Net (loss) income attributable to common shareholders $ (4,175 ) $ 2,428 Net (loss) income per share (basic) $ (0.54 ) $ 0.35 Net (loss) income per share (diluted) $ (0.54 ) $ 0.30
OIE Membership Acquisition [Member]
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Schedule of fair value of business acquired	Amount Cash consideration $ 33,000 Old Ironsides Notes 25,065 Fair value of previously held equity interest 14,158 Fair value of business acquired $ 72,223
Schedule of assets acquired and liabilities assumed	Amount Cash $ 12,283 Accounts receivable: Revenue 12,834 Trade receivable 1,941 Commodity derivative asset 198 Inventory 900 Prepaid expenses, deposits, and other current assets 456 Oil and gas properties: Proved 107,499 Unproved 1,869 Other property, plant and equipment, net 15,626 Other non-current assets 514 Accounts payable and accrued liabilities (19,114 ) Due to related parties (458 ) Firm transportation contract obligations (18,724 ) Asset retirement obligations (5,626 ) Notes payable (37,975 ) Total net assets acquired $ 72,223
Schedule of unaudited pro-forma consolidated results	Three Months Ended March 31, Three Months Ended March 31, (in thousands, except per share amounts) 2019 2018 Revenue $ 24,950 $ 32,316 Net (loss) income before non-controlling interests $ (6,690 ) $ 6,912 Net (loss) income attributable to non-controlling interests $ (2,590 ) $ 1,115 Net (loss) income attributable to common shareholders $ (4,175 ) $ 5,797 Net (loss) income per share (basic) $ (0.54 ) $ 0.83 Net (loss) income per share (diluted) $ (0.54 ) $ 0.77

Property and Equipment (Tables)

Property and Equipment (Tables)	3 Months Ended
	Mar. 31, 2019
Property, Plant and Equipment [Abstract]
Schedule of net property and equipment	(in thousands) March 31, December 31, Oil and gas properties: Proved oil and gas properties $ 344,147 $ 343,736 Unproved properties not subject to depletion 5,385 5,416 Accumulated depreciation, depletion, amortization and impairment (98,826 ) (95,281 ) Net oil and gas properties 250,706 253,871 Pipeline facilities and equipment 12,714 12,714 Base gas 2,122 2,122 Furniture and fixtures, computer hardware and software, and other equipment 6,688 6,649 Accumulated depreciation and amortization (4,356 ) (3,922 ) Net other property and equipment 17,168 17,563 Total net property and equipment $ 267,874 $ 271,434

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	3 Months Ended
	Mar. 31, 2019
Asset Retirement Obligation Tables Abstract
Summary of reconciliation of the ARO	(in thousands) Three Months Ended 2019 2018 Balance at beginning of period $ 22,310 $ 7,737 Accretion expense 394 141 Additions during period - 2,921 22,704 10,799 Less: ARO recognized as a current liability (3,392 ) (767 ) Balance at end of period $ 19,312 $ 10,032

Credit Facilities and Notes P_2

Credit Facilities and Notes Payable (Tables)	3 Months Ended
	Mar. 31, 2019
Debt Disclosure [Abstract]
Schedule of outstanding credit facilities and notes payable	(in thousands) March 31, 2019 December 31, 2018 2018 Credit Facility – revolver $ 70,150 $ 69,150 2018 Credit Facility – term note 13,333 15,000 Old Ironsides Notes 23,659 25,065 Other debt 48 57 Total principal 107,190 109,272 Less: unamortized debt discount (112 ) (134 ) Total credit facilities and notes payable $ 107,078 $ 109,138
Schedule of outstanding notes payable – related party	(in thousands) March 31, 2019 December 31, 2018 Senior Revolving Notes, related party, due February 15, 2022 $ 38,500 $ 38,500 Subordinated Notes, related party, due February 15, 2024 13,000 13,000 Total principal 51,500 51,500 Less: Deferred notes costs (255 ) (235 ) Less: unamortized debt discount (1,281 ) (1,346 ) Total notes payable – related party $ 49,964 $ 49,919

Revenue Recognition (Tables)

Revenue Recognition (Tables)	3 Months Ended
	Mar. 31, 2019
Revenue Recognition and Deferred Revenue [Abstract]
Schedule of disaggregation of revenue	(in thousands) Type Appalachian Basin Ventura Basin Total Natural gas sales $ 18,792 $ 524 $ 19,316 Natural gas liquids sales - 247 247 Oil sales 1,537 7,452 8,989 Transportation and handling 734 - 734 Marketing gas sales 4,944 - 4,944 Total revenue $ 26,007 $ 8,223 $ 34,230

Accounts Payable and Accrued _2

Accounts Payable and Accrued Liabilities (Tables)	3 Months Ended
	Mar. 31, 2019
Payables and Accruals [Abstract]
Schedule of accounts payable and accrued liabilities	(in thousands) March 31, December 31, Accounts payable $ 6,064 $ 7,670 Oil and gas revenue suspense 2,766 2,675 Gathering and transportation payables 1,228 1,774 Production taxes payable 2,411 1,860 Accrued operating costs 2,431 3,155 Accrued ad valorem taxes – current 3,731 3,474 Accrued general and administrative expenses 2,217 3,111 Accrued asset retirement obligation – current 3,392 3,099 Accrued interest 1,543 955 Accrued gas purchases 2,959 5,440 Other liabilities 1,278 1,603 Total accounts payable and accrued liabilities $ 30,020 $ 34,816

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2019
Fair Value Disclosures [Abstract]
Schedule of financial assets and liabilities at fair value	(in thousands) Fair Value Measurements Using Level 1 Level 2 Level 3 Total March 31, 2019 Assets: Commodity derivatives $ - $ 147 $ - $ 147 Liabilities: Commodity derivatives $ - $ 1,975 $ - $ 1,975 December 31, 2018 Asset: Commodity derivatives $ - $ 7,022 $ - $ 7,022

Commodity Derivatives (Tables)

Commodity Derivatives (Tables)	3 Months Ended
	Mar. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of swap derivative agreements	Natural Gas Swaps Natural Gas Collars Weighted Average Weighted Average Price Year MMBtu Price (a) MMBtu Range (a) 2019 11,762,000, $ 2.82 374,000 $ 2.60 – $3.03 2020 12,433,000 $ 2.73 1,018,000 $ 2.50 – $2.70 2021 6,448,000 $ 2.58 - $ - Oil Swaps Oil Collars Year WTI Bbl Weighted Average Price (b) Brent Bbl Weighted Average Price (c) WTI Bbl Weighted Average Price Brent Bbl Weighted Average Price 2019 180,775 $ 53.46 121,079 $ 66.93 - - 29,800 $ 47.00 - $75.00 2020 121,147 $ 55.37 151,982 $ 66.03 18,000 $ 47.00 - $60.15 37,400 $ 47.00 - $75.00 2021 - $ - 86,341 $ 67.12 30,000 $ 47.00 - $60.15 98,000 $ 47.00 - $75.00 * Includes 100% of Carbon California’s outstanding derivative hedges at March 31, 2019, and not our proportionate share. (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. (c) Brent future contracts for the respective period.
Schedule of fair value of the derivatives recorded	(in thousands) March 31, 2019 December 31, 2018 Commodity derivative contracts: Commodity derivative asset $ - $ 3,517 Commodity derivative asset – non-current $ 147 $ 3,505 Commodity derivative liability $ 1,657 $ - Commodity derivative liability – non-current $ 318 $ -
Schedule of realized and unrealized gains and losses	Three Months Ended (in thousands) 2019 2018 Commodity derivative contracts: Settlement losses $ (456 ) $ (377 ) Unrealized losses (8,850 ) (249 ) Total settlement and unrealized losses, net $ (9,306 ) $ (626 )
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 (in thousands) Liabilities Offset Liabilities Commodity derivative assets: Commodity derivative asset $ 1,063 $ (1,063 ) $ - Commodity derivative asset – non-current 2,049 (1,902 ) 147 Total derivative assets $ 3,112 $ (2,965 ) $ 147 Commodity derivative liabilities: Commodity derivative liability $ 2,720 $ (1,063 ) $ (1,657 ) Commodity derivative liability – non-current 2,220 (1,902 ) (318 ) Total derivative liabilities $ 4,940 $ (2,965 ) $ (1,975 )

Leases (Tables)

Leases (Tables)	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
Schedule of operating leases related to the asset classes	(in thousands) Right-of-Use Assets Lease Compressors $ 4,178 $ 4,178 Corporate leases 2,433 2,438 Vehicles 645 645 Total $ 7,256 $ 7,261
Schedule of gross operating lease costs	(in thousands) Three Months Ended March 31, Operating lease cost $ 531 Short-term lease cost 161 Total lease cost $ 692
Schedule of weighted-average lease term and discount rate	(in thousands) Three Months Ended March 31, Weighted-average lease term (years) 4.3 Weighted-average discount rate 6.34 %
Schedule of supplemental cash flow information related to leases	Cash paid for amounts included in measurement of lease liabilities (in thousands) Three Months Ended March 31, Operating cash flows for operating leases $ 526
Schedule of undiscounted values and discounted present value	(in thousands) Amount Remainder of 2019 $ 1,535 2020 1,946 2021 1,889 2022 1,718 2023 1,222 Thereafter 11 Total lease payments $ 8,321 Less: imputed interest (1,060 ) Total lease liability $ 7,261

Commitments and Contingencies (

Commitments and Contingencies (Tables)	3 Months Ended
	Mar. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Schedule of firm transportation volumes and related demand charges	Period Dekatherms per day Demand Charges Apr 2019 – Mar 2020 58,871 $ 0.20 - 0.62 Apr 2020 – May 2020 57,791 $ 0.20 - 0.56 Jun 2020 – Oct 2020 56,641 $ 0.20 - 0.56 Nov 2020 – Aug 2022 50,341 $ 0.20 - 0.56 Sep 2022 – May 2027 30,990 $ 0.20 - 0.21 Jun 2027 – May 2036 1,000 $ 0.20

Supplemental Cash Flow Disclo_2

Supplemental Cash Flow Disclosure (Tables)	3 Months Ended
	Mar. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Schedule of supplemental cash flow disclosures	Three Months Ended (in thousands) 2019 2018 Cash paid during the period for: Interest $ 1,875 $ 336 Non-cash transactions: Accounts payable and accrued liabilities $ 82 $ (71 ) Non-cash acquisition of Carbon California interests $ - $ (18,906 ) Carbon California Acquisition on February 1, 2018 $ - $ 17,114 Exercise of warrant derivative $ - $ (1,792 ) Old Ironsides Notes interest paid-in-kind $ 594 -

Organization (Details)

Organization (Details) - USD ($) $ in Thousands	May 01, 2018	Dec. 31, 2018	Feb. 01, 2018
Delaware Limited Liability Company [Member]
Organization (Textual)
Business acquisation purchase price		$ 58,100
Carbon California [Member]
Organization (Textual)
Divestitures, description	The voting and profits interests and Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America or its affiliates ("Prudential") owns 46.08% of the voting and profits interest in Carbon California.
Carbon California [Member] | Minimum [Member]
Organization (Textual)
Voting percentage			17.81%
Carbon California [Member] | Maximum [Member]
Organization (Textual)
Voting percentage			56.40%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Accounting Policies [Abstract]
Net (loss) income attributable to common shareholders	$ (4,175)	$ 3,569
Less: warrant derivative gain		(225)
Diluted net income	$ (4,175)	$ 3,344
Basic weighted-average common shares outstanding during the period	7,663	6,996
Add dilutive effects of warrants and non-vested shares of restricted stock	269	230
Diluted weighted-average common shares outstanding during the period	7,932	7,226
Basic net (loss) income per common share	$ (0.54)	$ 0.51
Diluted net (loss) income per common share	$ (0.54)	$ 0.46

Summary of Significant Accoun_5

Summary of Significant Accounting Policies (Details Textual) - USD ($)	1 Months Ended	2 Months Ended	3 Months Ended		12 Months Ended
	Jan. 31, 2018	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Summary of Significant Accounting Policies (Textual)
Description of 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 do not have significant influence.
Description of 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 can 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.
Management reimbursement elimination amount		$ 100,000
Carbon Appalachia [Member]
Summary of Significant Accounting Policies (Textual)
Percentage of ownership interest in the subsidiary			100.00%
Management provision reimbursements				$ 299,000
Received related party amount				$ 753,000
Carbon California [Member]
Summary of Significant Accounting Policies (Textual)
Management reimbursement elimination amount		$ 28,000
General and administrative expenses reimbursed amount	$ 14,000
Received related party amount	$ 50,000
Restricted Stock [Member]
Summary of Significant Accounting Policies (Textual)
Anti-dilutive earnings per shares				254,000
Non-vested shares		230,000		230,000
Restricted Performance Units [Member]
Summary of Significant Accounting Policies (Textual)
Common stock equivalent restricted to future contingencies			200,000
Anti-dilutive earnings per shares			269,000
Nytis Usa [Member]
Summary of Significant Accounting Policies (Textual)
Percentage of ownership interest in the subsidiary					100.00%
Nytis Llc [Member]
Summary of Significant Accounting Policies (Textual)
Percentage of ownership interest in the subsidiary					98.10%

Acquisitions and Divestitures_2

Acquisitions and Divestitures (Details) - Old Ironsides [Member] $ in Thousands	Mar. 31, 2019USD ($)
Acquisitions and Divestitures [Line Items]
Cash consideration	$ 33,000
Old Ironsides Notes	25,065
Fair value of previously held equity interest	14,158
Fair value of business acquired	$ 72,223

Acquisitions and Divestitures_3

Acquisitions and Divestitures (Details 1) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Oil and gas properties:
Asset retirement obligations - current	$ (3,392)	$ (3,099)
Asset retirement obligations - non-current	(19,312)	$ (19,211)
Old Ironsides [Member]
Acquisitions and Divestitures [Line Items]
Cash	12,283
Accounts receivable:
Revenue	12,834
Trade receivable	1,941
Commodity derivative asset	198
Inventory	900
Prepaid expense, deposits, and other current assets	456
Oil and gas properties:
Proved	107,499
Unproved	1,869
Other property, plant, and equipment, net	15,626
Other non-current assets	514
Accounts payable and accrued liabilities	(19,114)
Due to related parties	(458)
Firm transportation contract obligations	(18,724)
Asset retirement obligations - current	(5,626)
Notes payable	(37,975)
Total net assets acquired	$ 72,223

Acquisitions and Divestitures_4

Acquisitions and Divestitures (Details 2) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Carbon California [Member]
Acquisitions and Divestitures [Line Items]
Revenue	$ 24,950	$ 6,672
Net (loss) income before non-controlling interests	(6,690)	3,543
Net (loss) income attributable to non-controlling interests	(2,590)	1,115
Net (loss) income attributable to common shareholders	$ (4,100)	$ 2,428
Net (loss) income per share (basic)	$ (0.54)	$ 0.35
Net (loss) income per share (diluted)	$ (0.54)	$ 0.30
OIE Membership Acquisition [Member]
Acquisitions and Divestitures [Line Items]
Revenue	$ 24,950
Net (loss) income before non-controlling interests	(6,690)
Net (loss) income attributable to non-controlling interests	(2,590)
Net (loss) income attributable to common shareholders	$ (4,100)
Net (loss) income per share (basic)	$ (0.54)
Net (loss) income per share (diluted)	$ (0.54)
Old Ironsides [Member]
Acquisitions and Divestitures [Line Items]
Revenue		$ 32,316
Net (loss) income before non-controlling interests		6,912
Net (loss) income attributable to non-controlling interests		1,115
Net (loss) income attributable to common shareholders		$ 5,797
Net (loss) income per share (basic)		$ 0.83
Net (loss) income per share (diluted)		$ 0.46

Acquisitions and Divestitures_5

Acquisitions and Divestitures (Details Textual) - USD ($) $ in Thousands	Feb. 01, 2019	Feb. 01, 2018	Nov. 01, 2017	Apr. 03, 2017	Sep. 29, 2017	Mar. 31, 2019	Dec. 31, 2018	Aug. 15, 2017
Acquisitions and Divestitures (Textual)
Consisting cash paid amount						$ 25,100
Borrowing Revolver Increased								$ 8,000
Old Ironsides [Member]
Acquisitions and Divestitures (Textual)
Principal amount	$ 2,000
Bearing interest of per annum						10.00%
Percentage of identifiable assets acquired and liabilities						72.76%
OIE Membership Acquisition [Member]
Acquisitions and Divestitures (Textual)
Principal amount						$ 25,100
Yorktown Energy Partners [Member] | Class Units [Member]
Acquisitions and Divestitures (Textual)
Warrant to purchase common stock			2,940
Carbon Appalachia [Member]
Acquisitions and Divestitures (Textual)
Recognized gain based on fair value						1,300
Purchase price						5,810
Consisting cash paid amount						$ 33,000
Description of seneca acquisition				i) issued Class A Units to us, Yorktown and Old Ironsides for an aggregate cash consideration of $12.0 million, (ii) issued Class B Units to us, and (iii) issued Class C Units to us. Additionally, Carbon Appalachia Enterprises, LLC, formerly known as Carbon Tennessee Company, LLC ("Carbon Appalachia Enterprises"), a subsidiary of the Company, entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank (the "Revolver") with an initial borrowing base of $10.0 million.
Equity commitment				$ 100,000			$ 37,000
Aggregate cash consideration								14,000
Borrowing Revolver Increased								$ 22,000
Carbon Appalachia [Member] | Class Units [Member]
Acquisitions and Divestitures (Textual)
Acquisitions issuance shares, description					Prior to the closing of the OIE Membership Acquisition, Old Ironsides held 27,195 Class A Units, which equated to a 72.76% aggregate share ownership of Carbon Appalachia and we held (i) 9,805 Class A Units, (ii) 1,000 Class B Units and (iii) 121 Class C Units, which equated to a 27.24% aggregate share ownership of Carbon Appalachia.
Aggregate cash consideration					$ 11,000
Acquired of Class A Units							5,810
Acquired cash paid							$ 33,000
Carbon Appalachia [Member] | Class B Units [Member]
Acquisitions and Divestitures (Textual)
Warrant to purchase common stock				1,000
Carbon Appalachia [Member] | Yorktown Energy Partners [Member]
Acquisitions and Divestitures (Textual)
Warrant to purchase common stock				408,000
Carbon California [Member]
Acquisitions and Divestitures (Textual)
Acquisitions issuance shares, description		Yorktown exercised the California Warrant resulting in the issuance of 1,527,778 shares of our common stock in exchange for Yorktown's Class A Units of Carbon California representing approximately 46.96% of the outstanding Class A Units of Carbon California (a profits interest of approximately 38.59%). After giving effect to the exercise on February 1, 2018, we owned 56.4% of the voting and profits interests of Carbon California.

Property and Equipment (Details

Property and Equipment (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Oil and gas properties:
Accumulated depreciation, depletion, amortization and impairment	$ (98,826)	$ (95,281)
Net oil and gas properties	250,706	253,871
Pipeline facilities and equipment	12,714	12,714
Base gas	2,122	2,122
Furniture and fixtures, computer hardware and software, and other equipment	6,688	6,649
Accumulated depreciation and amortization	(4,356)	(3,922)
Net other property and equipment	17,168	17,563
Total net property and equipment	267,874	271,434
Proved Oil and Gas Properties [Member]
Oil and gas properties:
Oil and gas properties, gross	344,147	343,736
Unproved Properties Not Subject To Depletion [Member]
Oil and gas properties:
Oil and gas properties, gross	$ 5,385	$ 5,416

Property and Equipment (Detai_2

Property and Equipment (Details Textual) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2019USD ($)Per_Mcf	Mar. 31, 2018USD ($)Per_Mcf	Dec. 31, 2018USD ($)
Property and Equipment (Textual)
Capitalized overhead	$ 68	$ 71
Depletion expense related to oil and gas properties	$ 3,500	$ 1,300
Depletion expense related to oil and gas properties (in dollars per Mcfe) | Per_Mcf	0.54	0.82
Unproved Properties Not Subject To Depletion [Member]
Property and Equipment (Textual)
Depletion expense related to oil and gas properties	$ 5,400		$ 5,400

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Asset Retirement Obligation Details Abstract
Balance at beginning of period	$ 22,310	$ 7,737
Accretion expense	394	141
Additions during period		2,921
Less: ARO recognized as a current liability	22,704	10,799
Total	(3,392)	(767)
Balance at end of period	$ 19,312	$ 10,032

Investments in Affiliates (Deta

Investments in Affiliates (Details) - USD ($) $ in Thousands	24 Months Ended
	Dec. 31, 2018	Jan. 31, 2018
Investments in Affiliates (Textual)
Percentage of interests	27.24%
Carbon Appalachia [Member] | Class Units [Member]
Investments in Affiliates (Textual)
Percentage of interests	10.00%
Investment in cash and unevaluated property	$ 6,900
Revolving credit facility, description	We acquired all of Old Ironsides Class A Units of Carbon Appalachia for approximately $58.1 million, subject to certain closing adjustments. We paid $ 33.0 million in cash and issued the Old Ironsides Notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides.
Carbon Appalachia [Member] | Class C Units [Member]
Investments in Affiliates (Textual)
Investment in cash and unevaluated property	$ 6,900
Carbon Appalachia [Member] | Class A Units [Member]
Investments in Affiliates (Textual)
Percentage of interest	14.70%
Carbon California [Member]
Investments in Affiliates (Textual)
Percentage of interests		17.81%

Credit Facilities and Notes P_3

Credit Facilities and Notes Payable (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Line of Credit Facility [Line Items]
Total credit facilities and notes payable	$ 594
Credit Facilities [Member]
Line of Credit Facility [Line Items]
2018 Credit Facility - revolver	70,150	$ 69,150
2018 Credit Facility - term note	13,333	15,000
Old Ironsides Notes	23,659	25,065
Other debt	48	57
Total principal	107,190	109,272
Less: unamortized debt discount	(112)	(134)
Total credit facilities and notes payable	$ 107,078	$ 109,138

Credit Facilities and Notes P_4

Credit Facilities and Notes Payable (Details 1) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Line of Credit Facility [Line Items]
Subordinated Notes, related party, due February 15, 2024	$ 49,964	$ 49,919
Total notes payable – related party	594
Related Party [Member]
Line of Credit Facility [Line Items]
Senior Revolving Notes, related party, due February 15, 2022	38,500	38,500
Subordinated Notes, related party, due February 15, 2024	13,000	13,000
Total principal	51,500	51,500
Less: Deferred notes costs	(255)	(235)
Less: unamortized debt discount	(1,281)	(1,346)
Total notes payable – related party	$ 49,964	$ 49,919

Credit Facilities and Notes P_5

Credit Facilities and Notes Payable (Details Textual) $ in Thousands	May 01, 2018USD ($)	May 01, 2018	Feb. 15, 2017USD ($)	Mar. 31, 2019USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2018USD ($)	Feb. 01, 2018
Credit Facilities and Notes Payable (Textual)
Unamortized deferred issuance costs				$ 604
Senior secured asset-based revolving credit facility				3,000	$ 3,000
Amortized interest expense				$ 63
Business acquisitions, description						The OIE Membership Acquisition, we delivered unsecured, promissory notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides (the "Old Ironsides Notes"). The Old Ironsides Notes bear interest at 10% per annum and have a term of five years, the first three of which require interest-only payments at the end of each calendar quarter beginning with the quarter ending March 31, 2019. At the end of the three-year interest-only period, the then current outstanding principal balance and interest is to be paid in 24 equal monthly payments. The Old Ironsides Notes also require mandatory prepayments upon the occurrence of certain subsequent liquidity events. A mandatory, one-time principal reduction payment in the aggregate amount of $2.0 million was made to Old Ironsides on February 1, 2019. Subsequent to the closing of the OIE Membership Acquisition Old Ironsides ceased to be a related party.
Description of the revolver requirements				A) a maximum Debt/EBITDA ratio of 4.0 to 1.0, stepping down to 3.5 to 1.0 starting with the quarter ending June 30, 2018, (B) a maximum Senior Revolving Notes/EBITDA ratio of 2.5 to 1.0, (C) a minimum interest coverage ratio of 3.0 to 1.0 and (D) a minimum current ratio of 1.0 to 1.0 and (ii) the Subordinated Notes require Carbon California’s compliance, on a consolidated basis, with (A) a maximum Debt/EBITDA ratio of 4.5 to 1.0, stepping down to 4.0 to 1.0 starting with the quarter ending June 30, 2018, (B) a maximum Senior Revolving Notes/EBITDA ratio of 3.0 to 1.0, (C) a minimum interest coverage ratio of 2.5 to 1.0, (D) an asset coverage test whereby indebtedness may not exceed the product of 0.65 times Adjusted PV-10 set forth in the most recent reserve report, (E) maintenance of a minimum borrowing base of $10,000,000 under the Senior Revolving Notes and (F) a minimum current ratio of 0.85 to 1.00.
Incurred fees				$ 779
Credit facility fee, description						The 2018 Credit Facility included origination fees of $450,000 and arrangement fees of $80,000. As of December 31, 2018, there was approximately $70.0 million in outstanding borrowings and letters of credit and $5.0 million of additional borrowing capacity under the 2018 Credit Facility.
Term loan				$ 134
Description of credit facility				Interest accrues on borrowings under the 2018 Credit Facility at a rate per annum equal to either (i) the base rate plus an applicable margin equal to 0.25% - 0.75% depending on the utilization percentage or (ii) the Adjusted LIBOR rate plus an applicable margin equal to 2.75% - 3.75% depending on the utilization percentage, at the Borrowers' option. The Borrowers are obligated to pay certain fees and expenses in connection the 2018 Credit Facility, including a commitment fee for any unused amounts of 0.50% and an origination fee of 0.50%. Loans under the 2018 Credit Facility may be prepaid without premium or penalty. The 2018 Credit Facility also provides for a $15.0 million term loan which bears interest at a rate of 6.25% and is payable in 18 equal monthly installments beginning February 1, 2019 with the last payment due on June 30, 2020.
Bears interest rate				12.00%
Company elected to pay in kind				$ 594
Two Zero One Eight Credit Facility [Member]
Credit Facilities and Notes Payable (Textual)
Covenant description						Payable in 18 equal monthly installments beginning February 1, 2019 with the last payment due on June 30, 2020.
Initial borrowing				75,000
Additional borrowing capacity available				$ 4,800
Effective borrowing rate (as a percent)				6.25%
Letters of credit				$ 70,200
Outstanding borrowings						$ 15,000
Business acquisitions, description						The Company and its subsidiaries amended and restated the Credit Facility and the CAE Credit Facility which provides for a $500.0 million senior secured asset-based revolving credit facility (the "2018 Credit Facility") which matures December 31, 2022 and a $15.0 million term loan which matures in 2020. The 2018 Credit Facility includes a sublimit of $1.5 million for letters of credit.
Cash and cash equivalents of borrowers not to exceed				$ 3,000
Effective borrowing rate				0.00%
Line Of Credit [Member]
Credit Facilities and Notes Payable (Textual)
Unamortized deferred issuance costs				$ 112
Maximum [Member] | Two Zero One Eight Credit Facility [Member]
Credit Facilities and Notes Payable (Textual)
Funded debt ratio required to be maintained				3.5
Current ratio required to be maintained				1
Maximum [Member] | Line Of Credit [Member]
Credit Facilities and Notes Payable (Textual)
Funded debt ratio required to be maintained				3.5
Current ratio required to be maintained				1
Minimum [Member] | Two Zero One Eight Credit Facility [Member]
Credit Facilities and Notes Payable (Textual)
Funded debt ratio required to be maintained				1
Current ratio required to be maintained				1
Minimum [Member] | Line Of Credit [Member]
Credit Facilities and Notes Payable (Textual)
Funded debt ratio required to be maintained				1
Current ratio required to be maintained				1
Carbon California Two Thousand Eighteen Subordinated Notes [Member]
Credit Facilities and Notes Payable (Textual)
Effective borrowing rate (as a percent)	12.00%	12.00%
Description of the revolver requirements	The 2018 Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively.
Amount of unsecured notes issuance	$ 300,000
Description of notes prepayment terms	Prepayment of the Subordinated Notes is available after February 15, 2019. Prepayment is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted.
Notes issuance additional, description	On May 1, 2018, Carbon California entered into an agreement with Prudential for the issuance and sale of $3.0 million in Subordinated Notes due February 15, 2024, bearing interest of 12% per annum (the “2018 Subordinated Notes”), of which $3.0 million remains outstanding as of March 31, 2019. Prudential received 585 Class A Units, representing an approximate 2% additional sharing percentage, for the issuance of the Carbon California 2018 Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding 2018 Subordinated Notes of $3.0 million. The Company then allocated the non-cash value of the units of approximately $490,000, which was recorded as a discount to the 2018 Subordinated Notes. As of March 31, 2019, Carbon California had an outstanding discount of $412,000 associated with these notes, which is presented net of the 2018 Subordinated Notes within Credit facility - related party on the unaudited consolidated balance sheets. During the three months ended March 31, 2019, Carbon California amortized $21,000 associated with the 2018 Subordinated Notes.
Carbon California Notes [Member]
Credit Facilities and Notes Payable (Textual)
Borrowing base amount				$ 38,500
Effective borrowing rate (as a percent)			12.00%
Description of the revolver requirements			The Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively.
Amount of unsecured notes issuance	$ 300,000		$ 10,000
Unsecured notes due date	Feb. 15, 2024		Feb. 15, 2024
Description of notes prepayment terms						Prepayment of the 2018 Subordinated Notes is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted.
Notes issuance additional, description						Prudential received an additional 1,425 Class A Units, representing 5% of total sharing percentage, for the issuance of the Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding Subordinated Notes of $10.0 million. The Company then allocated the non-cash value of the units of approximately $1.3 million, which was recorded as a discount to the Subordinated Notes. As of March 31, 2019, Carbon California has an outstanding discount of approximately $869,000, which is presented net of the Subordinated Notes within Credit facility-related party on the consolidated balance sheets. During the three months ended March 31, 2019, Carbon California amortized $45,000 associated with the Subordinated Notes.
Carbon California [Member]
Credit Facilities and Notes Payable (Textual)
Effective borrowing rate (as a percent)							56.41%
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.
Unsecured notes due date		Feb. 15, 2024
Revolving Notes in the principal amount			$ 10,000
Carbon California [Member] | Maximum [Member]
Credit Facilities and Notes Payable (Textual)
Voting percentage							56.40%
Carbon California [Member] | Minimum [Member]
Credit Facilities and Notes Payable (Textual)
Voting percentage							17.81%
Carbon California Revolver [Member]
Credit Facilities and Notes Payable (Textual)
Borrowing base amount				41,000
Variable interest rate basis, description			(i) 5.50% plus the London interbank offered rate (“LIBOR”) or (ii) 4.50% plus the Prime Rate (which is defined as the interest rate published daily by JPMorgan Chase Bank, N.A.). As of March 31, 2019, the effective borrowing rate for the Senior Revolving Notes was 7.80%. In addition, the Senior Revolving Notes include a commitment fee for any unused amounts at 0.50% as well as an annual administrative fee of $75,000, payable on February 15 each year.
Other non-current assets value				939
Amortized interest expense				74
Business acquisitions, description			Carbon California entered into a Note Purchase Agreement (the “Note Purchase Agreement”) for the issuance and sale of Senior Secured Revolving Notes to Prudential with an initial revolving borrowing capacity of $25.0 million which mature on February 15, 2022 (the “Senior Revolving Notes”). Carbon Energy Corporation is not a guarantor of the Senior Revolving Notes. The closing of the Note Purchase Agreement on February 15, 2017 resulted in the sale and issuance by Carbon California of Senior Revolving Notes in the 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. As of March 31, 2019, the borrowing base was $41.0 million, of which $38.5 million was outstanding.
Description of the revolver requirements			The Senior Revolving Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated proved developed production at such time for year one, two and three at a rate of 75%, 65% and 50%, respectively. Carbon California may make principal payments in minimum installments of $500,000. Distributions to equity members are generally restricted.
Revolving Notes in the principal amount			$ 10,000
Credit Facilities [Member]
Credit Facilities and Notes Payable (Textual)
Outstanding discount amount of notes				$ 112		$ 134

Stockholders' Equity (Details)

Stockholders' Equity (Details) - USD ($) $ / shares in Units, $ in Thousands	Mar. 15, 2017	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jun. 01, 2018
Stockholders' Equity (Textual)
Compensation costs for restricted stock grants				$ 2,700	$ 2,700
Granted, Number of Shares		649,000
Exercise price		$ 100
Grant date fair value				$ 9.80	$ 7.20	$ 5.40	$ 8
Number of shares issued				50,000
Proceeds from issuance of preferred stock		$ 5,000
Conversion of common stock, description		The number of shares of common stock issuable upon conversion is dependent upon the price per share of common stock issued in connection with any such qualifying equity financing but has a floor conversion price equal to $8.00 per share. The conversion ratio at which the Preferred Stock will convert into common stock is equal to an amount per share of $100 plus all accrued but unpaid dividends payable in respect thereof divided by the greater of (i) $8.00 per share or (ii) the price that is 15% less than the lowest price per share of shares sold to the public in the next equity financing. Using the floor of $8.00 per share would yield 12.5 shares of common stock for every unit of Preferred Stock.
Beneficial conversion feature
Accrued dividends		299
Beneficial conversion feature, description		We recorded the BCF as a reduction of retained earnings and an increase to APIC of $1.1 million, which is based on the difference between the floor price of $8.00 and our stock price as of the commitment date multiplied by the number of shares to be issued.
Common stock, shares authorized		35,000,000		35,000,000
Common stock, par value		$ 0.01		$ 0.01
Common stock, shares issued		7,791,292		7,655,759
Common stock, shares outstanding		7,791,292		7,655,759
Preferred stock, shares authorized		1,000,000		1,000,000
Preferred stock, par value		$ 0.01		$ 0.01
Minimum [Member]
Stockholders' Equity (Textual)
Common stock, shares authorized								10,000,000
Maximum [Member]
Stockholders' Equity (Textual)
Common stock, shares authorized								35,000,000
Issued Capital Stock [Member]
Stockholders' Equity (Textual)
Common stock, shares authorized				35,000,000
Common stock, par value				$ 0.01
Common stock, shares issued				7,800,000
Common stock, shares outstanding				7,800,000
Preferred stock, shares authorized				1,000,000
Preferred stock, par value				$ 0.01
Restricted Performance Units [Member]
Stockholders' Equity (Textual)
Unrecognized compensation cost			$ 158
Compensation cost recognized		43	135
Restricted stock vested shares		40,000
Restricted Stock Units (Rsus) [Member]
Stockholders' Equity (Textual)
Unrecognized compensation cost		$ 1,200
Compensation costs for restricted stock grants		$ 179
Expected period of recognition of unrecognized compensation costs		6 years
Granted, Number of Shares		621,000
Accrued dividends		100
Series B Convertible Preferred Stock [Member]
Stockholders' Equity (Textual)
Accrue cash dividends rate		6.00%
Stockholders And Board Of Directors [Member]
Stockholders' Equity (Textual)
Reverse stock split, description	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.

Revenue Recognition (Details)

Revenue Recognition (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Revenue Recognition, Multiple-deliverable Arrangements [Line Items]
Natural gas sales	$ 19,316	$ 3,939
Natural gas liquids sales	247
Oil sales	8,989	$ 2,983
Transportation and handling	734
Marketing gas sales	4,944
Total natural gas, natural gas liquids, and oil revenue	34,230
Appalachian Basin [Member]
Revenue Recognition, Multiple-deliverable Arrangements [Line Items]
Natural gas sales	18,792
Natural gas liquids sales
Oil sales	1,537
Transportation and handling	734
Marketing gas sales	4,944
Total natural gas, natural gas liquids, and oil revenue	26,007
Ventura Basin [Member]
Revenue Recognition, Multiple-deliverable Arrangements [Line Items]
Natural gas sales	524
Natural gas liquids sales	247
Oil sales	7,452
Transportation and handling
Marketing gas sales
Total natural gas, natural gas liquids, and oil revenue	$ 8,223

Revenue Recognition (Details Te

Revenue Recognition (Details Textual)	3 Months Ended
	Mar. 31, 2019Segments
Revenue Recognition (Textual)
Number of reportable segment	1

Accounts Payable and Accrued _3

Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Payables and Accruals [Abstract]
Accounts payable	$ 6,064	$ 7,670
Oil and gas revenue suspense	2,766	2,675
Gathering and transportation payables	1,228	1,774
Production taxes payable	2,411	1,860
Accrued operating costs	2,431	3,155
Accrued ad valorem taxes-current	3,731	3,474
Accrued general and administrative expenses	2,217	3,111
Accrued asset retirement obligation-current	3,392	3,099
Accrued interest	1,543	955
Accrued gas purchases	2,959	5,440
Other liabilities	1,278	1,603
Total accounts payable and accrued liabilities	$ 30,020	$ 34,816

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Fair Value Measurements [Member] - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Asset:
Commodity derivatives	$ 147	$ 7,022
Liabilities:
Commodity derivatives	1,975
Level 1 [Member]
Asset:
Commodity derivatives
Liabilities:
Commodity derivatives
Level 2 [Member]
Asset:
Commodity derivatives	147	7,022
Liabilities:
Commodity derivatives	1,975
Level 3 [Member]
Asset:
Commodity derivatives
Liabilities:
Commodity derivatives

Fair Value Measurements (Deta_2

Fair Value Measurements (Details Textual) $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)shares
Fair Value Measurements (Textual)
Asset retirement obligation, description	The estimated timing of reclamation ranging from one to 75 years based on estimates from reserve engineers; an inflation rate between 1.52% to 2.79%; and a credit adjusted risk-free rate between 3.28% to 8.27%, 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 three month period ended March 31, 2019, we did not record any additions to asset retirement obligations.
Minimum [Member]
Fair Value Measurements (Textual)
Fair value of debt discount Issuance | shares	585
Maximum [Member]
Fair Value Measurements (Textual)
Fair value of debt discount Issuance | shares	1,425
Class A Units [Member]
Fair Value Measurements (Textual)
Fair value of debt discount	$ 1
Class A Units [Member] | Subordinated Notes [Member]
Fair Value Measurements (Textual)
Fair value of debt discount	1,300
Class A Units [Member] | Subordinated Notes [Member]
Fair Value Measurements (Textual)
Fair value of debt discount	490
Class A Units [Member] | California Warrant [Member | Minimum [Member]
Fair Value Measurements (Textual)
Fair value of warrant	20
Class A Units [Member] | California Warrant [Member | Maximum [Member]
Fair Value Measurements (Textual)
Fair value of warrant	$ 45

Commodity Derivatives (Details)

Commodity Derivatives (Details)	Mar. 31, 2019USD_BblUSD-MMBtu$ / shares
Natural Gas Swaps [Member] | Carbon Energy Corporation [Member] | 2019 [Member]
Derivative agreements details:
Quantity | USD-MMBtu	11,762,000
Weighted Average Price	$ 2.82	[1]
Natural Gas Swaps [Member] | Carbon Energy Corporation [Member] | 2020 [Member]
Derivative agreements details:
Quantity | USD_Bbl	12,433,000
Weighted Average Price	$ 2.73	[1]
Natural Gas Swaps [Member] | Carbon Energy Corporation [Member] | 2021 [Member]
Derivative agreements details:
Quantity | USD_Bbl	6,448,000
Weighted Average Price	$ 2.58	[1]
Natural Gas Collars [Member] | Carbon Energy Corporation [Member] | 2019 [Member]
Derivative agreements details:
Quantity | USD-MMBtu	374,000
Natural Gas Collars [Member] | Carbon Energy Corporation [Member] | 2020 [Member]
Derivative agreements details:
Quantity | USD_Bbl	1,018,000
Natural Gas Collars [Member] | Carbon Energy Corporation [Member] | 2021 [Member]
Derivative agreements details:
Quantity | USD_Bbl
Weighted Average Price		[1]
Oil Swaps [Member] | Carbon Energy Corporation [Member] | 2019 [Member]
Derivative agreements details:
Quantity | USD_Bbl	180,775
Weighted Average Price	$ 53.46	[2]
Oil Swaps [Member] | Carbon Energy Corporation [Member] | 2020 [Member]
Derivative agreements details:
Quantity | USD_Bbl	121,147
Weighted Average Price	$ 55.37	[2]
Oil Swaps [Member] | Carbon Energy Corporation [Member] | 2021 [Member]
Derivative agreements details:
Quantity | USD_Bbl
Weighted Average Price		[2]
Oil Swaps [Member] | Brent Bbl [Member] | Carbon California [Member] | 2019 [Member]
Derivative agreements details:
Quantity | USD_Bbl	121,079
Weighted Average Price	$ 66.93	[3]
Oil Swaps [Member] | Brent Bbl [Member] | Carbon California [Member] | 2020 [Member]
Derivative agreements details:
Quantity | USD_Bbl	151,982
Weighted Average Price	$ 66.03	[3]
Oil Swaps [Member] | Brent Bbl [Member] | Carbon California [Member] | 2021 [Member]
Derivative agreements details:
Quantity | USD_Bbl	86,341
Weighted Average Price	$ 67.12	[3]
Oil Collars [Member] | Carbon Energy Corporation [Member] | 2020 [Member]
Derivative agreements details:
Quantity | USD_Bbl	18,000
Oil Collars [Member] | Carbon Energy Corporation [Member] | 2021 [Member]
Derivative agreements details:
Quantity | USD_Bbl	30,000
Oil Collars [Member] | Carbon California [Member] | 2019 [Member]
Derivative agreements details:
Quantity | USD_Bbl
Weighted Average Price
Oil Collars [Member] | Brent Bbl [Member] | Carbon California [Member] | 2019 [Member]
Derivative agreements details:
Quantity | USD_Bbl	29,800
Oil Collars [Member] | Brent Bbl [Member] | Carbon California [Member] | 2020 [Member]
Derivative agreements details:
Quantity | USD_Bbl	37,400
Oil Collars [Member] | Brent Bbl [Member] | Carbon California [Member] | 2021 [Member]
Derivative agreements details:
Quantity | USD_Bbl	98,000
Minimum [Member] | Natural Gas Collars [Member] | Carbon Energy Corporation [Member] | 2020 [Member]
Derivative agreements details:
Weighted Average Price	$ 2.50	[1]
Minimum [Member] | Natural Gas Collars [Member] | Carbon California [Member] | 2019 [Member]
Derivative agreements details:
Weighted Average Price	2.60	[1]
Minimum [Member] | Oil Collars [Member] | Carbon Energy Corporation [Member] | 2020 [Member]
Derivative agreements details:
Weighted Average Price	47	[2]
Minimum [Member] | Oil Collars [Member] | Carbon Energy Corporation [Member] | 2021 [Member]
Derivative agreements details:
Weighted Average Price	47	[2]
Minimum [Member] | Oil Collars [Member] | Brent Bbl [Member] | Carbon California [Member] | 2019 [Member]
Derivative agreements details:
Weighted Average Price	47	[3]
Minimum [Member] | Oil Collars [Member] | Brent Bbl [Member] | Carbon California [Member] | 2020 [Member]
Derivative agreements details:
Weighted Average Price	47	[3]
Minimum [Member] | Oil Collars [Member] | Brent Bbl [Member] | Carbon California [Member] | 2021 [Member]
Derivative agreements details:
Weighted Average Price	47	[3]
Maximum [Member] | Natural Gas Collars [Member] | Carbon Energy Corporation [Member] | 2019 [Member]
Derivative agreements details:
Weighted Average Price	3.03	[1]
Maximum [Member] | Natural Gas Collars [Member] | Carbon Energy Corporation [Member] | 2020 [Member]
Derivative agreements details:
Weighted Average Price	2.70	[1]
Maximum [Member] | Oil Collars [Member] | Carbon Energy Corporation [Member] | 2020 [Member]
Derivative agreements details:
Weighted Average Price	60.15	[2]
Maximum [Member] | Oil Collars [Member] | Carbon Energy Corporation [Member] | 2021 [Member]
Derivative agreements details:
Weighted Average Price	60.15	[2]
Maximum [Member] | Oil Collars [Member] | Brent Bbl [Member] | Carbon California [Member] | 2019 [Member]
Derivative agreements details:
Weighted Average Price	75	[3]
Maximum [Member] | Oil Collars [Member] | Brent Bbl [Member] | Carbon California [Member] | 2020 [Member]
Derivative agreements details:
Weighted Average Price	75	[3]
Maximum [Member] | Oil Collars [Member] | Brent Bbl [Member] | Carbon California [Member] | 2021 [Member]
Derivative agreements details:
Weighted Average Price	$ 75	[3]
[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.
[3]	Brent future contracts for the respective period.

Commodity Derivatives (Details

Commodity Derivatives (Details 1) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Commodity derivative contracts:
Commodity derivative asset		$ 3,517
Commodity derivative asset – non-current	147	3,505
Commodity derivative liabilities	1,657
Commodity derivative liabilities, non-current	$ 318

Commodity Derivatives (Detail_2

Commodity Derivatives (Details 2) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Commodity derivative contracts:
Settlement losses	$ (456)	$ (377)
Unrealized losses	(8,850)	(249)
Total settlement and unrealized gains (losses), net	$ (9,306)	$ (626)

Commodity Derivatives (Detail_3

Commodity Derivatives (Details 3) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Commodity derivative assets:
Commodity derivative asset		$ 3,517
Commodity derivative asset - non-current	147	3,505
Commodity derivative liabilities:
Commodity derivative	1,657
Commodity derivative liability - non-current	318
Gross Recognized Assets/Liabilities [Member]
Commodity derivative assets:
Commodity derivative asset	1,063
Commodity derivative asset - non-current	2,049
Total derivative assets	3,112
Commodity derivative liabilities:
Commodity derivative	2,720
Commodity derivative liability - non-current	2,220
Total derivative liabilities	4,940
Gross Amounts Offset [Member]
Commodity derivative assets:
Commodity derivative asset	(1,063)
Commodity derivative asset - non-current	(1,902)
Total derivative assets	(2,965)
Commodity derivative liabilities:
Commodity derivative	(1,063)
Commodity derivative liability - non-current	(1,902)
Total derivative liabilities	(2,965)
Net Recognized Fair Value Assets/Liabilities [Member]
Commodity derivative assets:
Commodity derivative asset
Commodity derivative asset - non-current	147
Total derivative assets	147
Commodity derivative liabilities:
Commodity derivative	(1,657)
Commodity derivative liability - non-current	(318)
Total derivative liabilities	$ (1,975)

Leases (Details)

Leases (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Right-of-use Asset	$ 7,256
Lease Liability	7,261
Compressors [Member]
Right-of-use Asset	4,178
Lease Liability	4,178
Corporate leases [Member]
Right-of-use Asset	2,433
Lease Liability	2,438
Vehicles [Member]
Right-of-use Asset	645
Lease Liability	$ 645

Leases (Details 1)

Leases (Details 1) $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)
Leases [Abstract]
Operating lease cost	$ 531
Short-term lease cost	161
Total lease cost	$ 692

Leases (Details 2)

Leases (Details 2)	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
Weighted-average lease term (years)	4 years 3 months 19 days
Weighted-average discount rate	6.34%

Leases (Details 3)

Leases (Details 3) $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)
Cash paid for amounts included in measurement of lease liabilities:
Operating cash flows for operating leases	$ 526

Leases (Details 4)

Leases (Details 4) $ in Thousands	Mar. 31, 2019USD ($)
Leases [Abstract]
Remainder of 2019	$ 1,535
2020	1,946
2021	1,889
2022	1,718
2023	1,222
Thereafter	11
Total lease payments	8,321
Less: imputed interest	(1,060)
Total lease liability	$ 7,261

Leases (Details Textual)

Leases (Details Textual) - USD ($)	3 Months Ended
	Mar. 31, 2019	Jan. 03, 2019
Leases (Textual)
Right-of-use assets		$ 7,700,000
Right-of-use lease liabilities		$ 7,700,000
Right-of-use assets and liabilities discounted present value	$ 7,300,000
Straight-line basis description	Short-term lease cost represents payments for leases with a lease term of one year or less, excluding leases with a term of one month or less. Short-term leases include certain compressors and vehicles that have a non-cancellable lease term of less than one year.

Commitments and Contingencies_2

Commitments and Contingencies (Details)	3 Months Ended
	Mar. 31, 2019$ / sharesPartnership
Apr 2019 - Mar 2020 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Partnership	58,871
Apr 2019 - Mar 2020 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.20
Apr 2019 - 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	57,791
Apr 2020 - May 2020 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.20
Apr 2020 - May 2020 [Member] | Maximum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.56
Jun 2020 - Oct 2020 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Partnership	56,641
Jun 2020 - Oct 2020 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.20
Jun 2020 - Oct 2020 [Member] | Maximum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.56
Nov 2020 - Aug 2022 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Partnership	50,341
Nov 2020 - Aug 2022 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.20
Nov 2020 - Aug 2022 [Member] | Maximum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.56
Sep 2022 - May 2027 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Partnership	30,990
Sep 2022 - May 2027 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.20
Sep 2022 - May 2027 [Member] | Maximum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.21
Jun 2027 - 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 Contingencies_3

Commitments and Contingencies (Details Textual) $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)
Commitment and Contingencies (Textual)
Acquisition amount	$ 17,800
Description of natural gas processing agreement	We have an option to extend the term of the agreement by another five years. The related demand charges for volume commitments over the remaining term of the agreement at March 31, 2019 are approximately $1.8 million per year. We will pay a processing fee of $2.50 per MCF for the term of the agreement, with a minimum annual volume commitment of 720,000 MCF.

Supplemental Cash Flow Disclo_3

Supplemental Cash Flow Disclosure (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash paid during the period for:
Interest	$ 1,875	$ 336
Non-cash transactions:
Accounts payable and accrued liabilities	82	(71)
Non-cash acquisition of Carbon California interests		(18,906)
Carbon California Acquisition on February 1, 2018		17,114
Exercise of warrant derivative		$ (1,792)
Old Ironsides Notes interest paid-in-kind	$ 594