Carbon Energy (CRBO) 10-K 30 Mar 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Mar. 16, 2020	Jun. 28, 2019
Document and Entity Information [Abstract]
Entity Registrant Name	Carbon Energy Corp
Entity Central Index Key	0000086264
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Type	10-K
Document Period End Date	Dec. 31, 2019
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2019
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Shell Company	false
Entity Emerging Growth Company	false
Entity Public Float			$ 19,200
Entity Common Stock, Shares Outstanding		7,816,420
Entity File Number	000-02040
Entity Interactive Data Current	Yes
Entity Incorporation State Country Code	DE

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 904	$ 5,736
Accounts receivable:
Revenue	12,886	20,223
Joint interest billings and other	1,552	1,218
Insurance receivable (Note 2)		522
Commodity derivative asset (Note 14)	5,915	3,517
Prepaid expenses, deposits, and other current assets	2,500	1,645
Inventory	2,512	1,149
Total current assets	26,269	34,010
Oil and gas properties, full cost method of accounting:
Proved, net	242,144	248,455
Unproved	4,872	5,416
Other property and equipment, net	15,984	17,563
Total property and equipment, net	263,000	271,434
Investments in affiliates	625	598
Commodity derivative asset - non-current (Note 14)	1,164	3,505
Right-of-use assets (Note 8)	6,104
Other non-current assets	1,092	1,344
Total non-current assets	271,985	276,881
Total assets	298,254	310,891
Current liabilities:
Accounts payable and accrued liabilities (Note 5)	35,157	34,816
Firm transportation contract obligations (Note 15)	5,679	6,129
Lease liability - current (Note 8)	1,625
Commodity derivative liability (Note 14)	469
Credit facilities and notes payable (Note 7)	5,788	11,910
Total current liabilities	48,718	52,855
Non-current liabilities:
Firm transportation contract obligations (Note 15)	8,905	12,729
Lease liability - non-current (Note 8)	4,383
Commodity derivative liability - non-current (Note 14)	87
Production and property taxes payable	2,815	2,914
Asset retirement obligations (Note 6)	17,514	19,211
Credit facilities and notes payable (Note 7)	94,870	97,228
Notes payable - related party (Note 7)	44,741	49,919
Total non-current liabilities	173,315	182,001
Commitments and contingencies (Note 15)
Stockholders' equity:
Preferred stock, $0.01 par value; liquidation preference of $524 and $224 at December 31, 2019 and 2018, respectively; authorized 1,000,000 shares, 50,000 shares issued and outstanding at December 31, 2019 and 2018, respectively	1	1
Common stock, $0.01 par value; authorized 35,000,000 shares, 7,796,085 and 7,655,759 shares issued and outstanding at December 31, 2019 and 2018, respectively	78	77
Additional paid-in capital	85,834	84,612
Accumulated deficit	(35,842)	(36,939)
Total Carbon stockholders' equity	50,071	47,751
Non-controlling interests	26,150	28,284
Total stockholders' equity	76,221	76,035
Total liabilities and stockholders' equity	$ 298,254	$ 310,891

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Preferred stock, par value (in dollars per share)	$ 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	$ 524	$ 224
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	35,000,000	35,000,000
Common stock, shares issued	7,796,085	7,655,759
Common stock, shares outstanding	7,796,085	7,655,759

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenue:
Commodity derivative gain	$ 3,044	$ 4,894
Other income	892	105
Total revenue	116,625	53,051
Expenses:
Lease operating expenses	29,714	15,960
Pipeline operating expenses	11,153
Transportation and gathering costs	6,086	4,453
Production and property taxes	5,507	1,813
Marketing gas purchases	18,684
General and administrative	16,342	13,779
General and administrative - deferred fees write-down		1,999
General and administrative - related party reimbursement		(4,547)
Depreciation, depletion, and amortization	15,757	8,108
Accretion of asset retirement obligations	1,625	868
Total expenses	104,868	42,433
Operating income	11,757	10,618
Other income and (expense):
Interest expense	(12,848)	(5,920)
Warrant derivative gain		225
Gain on derecognized equity investment in affiliate-Carbon California		5,390
Investments in affiliates	90	2,469
Other		(3)
Total other (expense) income	(12,758)	2,161
(Loss) income before income taxes	(1,001)	12,779
Provision for income taxes
Net (loss) income before non-controlling interests and preferred shares	(1,001)	12,779
Net (loss) income attributable to non-controlling interests	(2,098)	4,375
Net income attributable to controlling interests before preferred shares	1,097	8,404
Net income attributable to preferred shares - beneficial conversion feature		1,125
Net income attributable to preferred shares - preferred return	300	224
Net income attributable to common shares	$ 797	$ 7,055
Net income per common share:
Basic	$ 0.10	$ 0.94
Diluted	$ 0.10	$ 0.87
Weighted average common shares outstanding:
Basic	7,794	7,525
Diluted	8,095	7,839
Natural gas liquids sales [Member]
Revenue:
Total revenue	$ 578	$ 1,143
Oil sales [Member]
Revenue:
Total revenue	36,795	30,891
Transportation and handling [Member]
Revenue:
Total revenue	1,928
Marketing gas sales [Member]
Revenue:
Total revenue	16,920
Natural gas sales [Member]
Revenue:
Total revenue	$ 56,468	$ 16,018

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - 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			1,133			1,133
Stock based compensation, shares
Vested restricted stock	$ 1		(1)
Vested restricted stock, shares	60
Vested performance units	$ 1		(1)
Vested performance units, shares	108
Restricted stock and performance units exchanged for tax withholding			(197)			(197)
Restricted stock and performance units exchanged for tax withholding, shares	(46)
Preferred share issuance		$ 1	4,999			5,000
Preferred share issuance, shares		50
Beneficial conversion feature			1,125		(1,125)
California Warrant exercise - share issuance	$ 15		8,312	16,465		24,792
California Warrant exercise - share issuance, shares	1,528
Majority control of Carbon California (Note 4)			10,429			10,429
Units issued with 2018 Subordinated Notes, related party (Note 7)				489		489
Non-controlling interest distributions (contributions), net				5,114		5,114
Net income (loss)				4,375	8,404	12,779
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			1,448			1,448
Stock based compensation, shares
Vested restricted stock	$ 1		(1)
Vested restricted stock, shares	106
Vested performance units	$ 1		(1)
Vested performance units, shares	95
Restricted stock and performance units exchanged for tax withholding	$ (1)		(224)			(225)
Restricted stock and performance units exchanged for tax withholding, shares	(61)
Non-controlling interest distributions (contributions), net				(36)		(36)
Net income (loss)				(2,098)	1,097	(1,001)
Balances at Dec. 31, 2019	$ 78	$ 1	$ 85,834	$ 26,150	$ (35,842)	$ 76,221
Balances, shares at Dec. 31, 2019	7,796	50

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities:
Net (loss) income	$ (1,001)	$ 12,779
Items not involving cash:
Depreciation, depletion and amortization	15,757	8,108
Accretion of asset retirement obligations	1,625	868
Unrealized commodity derivative loss (gain)	499	(8,742)
Warrant derivative gain		(225)
Stock-based compensation expense	1,448	1,133
Investments in affiliates	(77)	(7,734)
Amortization of debt costs	846	966
Interest expense paid-in-kind	2,481
Other	(57)
Net change in:
Accounts receivable	7,619	545
Prepaid expenses, deposits and other current assets	(809)	1,067
Accounts payable, accrued liabilities and firm transportation contract obligations	(9,033)	2,472
Other non-current assets	(442)	(392)
Net cash provided by operating activities	18,856	10,845
Cash flows from investing activities:
Development and acquisition of properties and equipment	(8,028)	(2,995)
Acquisition of oil and gas properties, asset acquisitions (Note 3)		(46,980)
Acquisition of oil and gas properties, business combinations, net of cash received (Note 3)		(20,461)
Distribution from affiliate	50
Proceeds received - disposition of oil and gas properties and other property and equipment	1,408
Net cash used in investing activities	(6,570)	(70,436)
Cash flows from financing activities:
Vested restricted stock and performance units exchanged for tax withholding	(225)	(197)
Proceeds from credit facilities and notes payable	7,000	118,628
Proceeds from preferred shares		5,000
Payments on credit facilities and notes payable	(23,708)	(64,150)
Payments of debt issuance costs	(149)	(718)
(Distributions to) contributions from non-controlling interests, net	(36)	5,114
Net cash (used in) provided by financing activities	(17,118)	63,677
Net (decrease) increase in cash and cash equivalents	(4,832)	4,086
Cash and cash equivalents, beginning of period	5,736	1,650
Cash and cash equivalents, end of period	$ 904	$ 5,736

Organization

Organization	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION	Note 1 - Organization Carbon Energy Corporation (formerly known as Carbon Natural Gas Company) is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil, natural gas and natural gas liquids properties located in the United States. The terms "we", "us", "our", the "Company" or "Carbon" refer to Carbon Energy Corporation and our consolidated subsidiaries (described below). The following is an organization chart of the key subsidiaries discussed in this report as of December 31, 2019: 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 Old Ironsides OIE Membership Acquisition Ventura Basin Operations In California, Carbon California Operating Company, LLC conducts operations on behalf of Carbon California Company, LLC, a Delaware limited liability company (" Carbon California Yorktown California Warrant Seneca Acquisition Prudential

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	Note 2 - Summary of Significant Accounting Policies Principles of Consolidation The consolidated financial statements include the accounts of Carbon Energy Corporation and its consolidated subsidiaries. In addition to Carbon Appalachia and Carbon California, we consolidate 46 partnerships in which we have a controlling interest. We reflect the non-controlling ownership interest of the portion we do not own on our consolidated balance sheets within stockholders' equity and our consolidated statements of operations. In accordance with established practice in the oil and gas industry, our consolidated financial statements also include our pro-rata share of assets, liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which we have a non-controlling interest. We utilize the equity method to account for investments that do not meet the criteria for pro rata consolidation when we have the ability to significantly influence the operating decisions of the investee. All significant intercompany accounts and transactions have been eliminated. Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with accounting principles generally accepted in the United States (" GAAP 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. The remaining reclassifications include certain immaterial balance sheet and expense accounts. These reclassifications had no impact on net income or stockholders' equity previously reported. Fair Value of Financial Instruments The carrying value of our cash and cash equivalents, accounts receivables, prepaid expenses, deposits and other current assets and accounts payable and accrued liabilities approximate fair value due to the short maturity of these instruments. The carrying value of our notes payable and credit facilities approximate fair value based on the variable nature of interest rates and current market rates available to us. Commodity derivatives are recorded at fair value. Cash and Cash Equivalents Cash and cash equivalents have been generally invested in money market accounts, certificates of deposits and other cash equivalents with maturities of three months or less . Such investments are deemed to be cash equivalents for purposes of the financial statements. At times, the Company may have cash and cash equivalent balances more than federal insured amounts within their accounts. Accounts Receivable We grant credit to all qualified customers, which potentially subjects us to credit risk resulting from, among other factors, adverse changes in the industries in which we operate and the financial condition of our customers. We continuously monitor collections and payments from our customers and, if necessary, maintain an allowance for doubtful accounts based upon our historical experience and any specific customer collection issues that we have identified. At December 31, 2019 and 2018, we had not identified any collection issues related to our oil and gas operations and consequently no allowance for doubtful accounts was provided for on those dates. Revenue Accounts receivable - Revenue is comprised of oil, natural gas and NGL revenues from producing activities. We recognize an asset or a liability, whichever is appropriate, for revenues associated with over-deliveries or under-deliveries of natural gas to purchasers. A purchaser imbalance asset occurs when we deliver more natural gas than we nominated to deliver to the purchaser and the purchaser pays only for the nominated amount. Conversely, a purchaser imbalance liability occurs when we deliver less natural gas than we nominated to deliver to the purchaser and the purchaser pays for the amount nominated. As of December 31, 2019, and 2018, we had a purchaser imbalance receivable of $956,000 and $551,000, respectively, within accounts receivable-revenue. Joint Interest Billings and Other Our accounts receivable - joint interest billings and other is comprised of receivables due from other exploration and production companies and individuals who own working interests in the properties that we operate. For receivables from joint interest owners, we typically have the ability to withhold future revenues disbursements to recover any non-payment of joint-interest billings. 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 final settlement payment from our insurance provider related to the damage caused by the California wildfires. As of December 31, 2019, we were in receipt of all funds associated with the claims. Revenue Recognition Oil, natural gas and natural gas liquids revenues are recognized when the performance obligation to deliver the production volumes is met and control is transferred to the customer. All product revenues are recognized on the basis of our net revenue interest. Oil and natural gas are 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 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 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 consolidated statements of operations, while transportation and gathering costs incurred subsequent to control transfer are recognized as a reduction to the related revenue. 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. The estimated revenue is recorded within Accounts receivable – Revenue on the consolidated balance sheets. 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. Purchaser Concentration We sell our oil, natural gas and natural gas liquids production to various purchasers in the industry. The table below presents purchasers that account for 10% or more of total oil, natural gas, and natural gas liquids sales for the years ended December 31, 2019 and 2018. There are several purchasers in the areas where we sell our production. We do not believe that changing our primary purchasers or a loss of any other single purchaser would materially impact our business. Year Ended Purchaser 2019 2018 Purchaser A 18 % * Purchaser B 11 % * Purchaser C * 17 % Purchaser D * 16 % Purchaser E * 12 % * less than 10% As of December 31, 2019, none of the above purchasers comprised more than 10% of total accounts receivable. One purchaser's receivable acquired with the closing of the OIE Membership Acquisition accounted for approximately 10% of accounts receivable as of December 31, 2018. Inventory Inventory includes natural gas, which is recorded at the lower of weighted average cost or market value. Inventory also consists of material and supplies used in connection with the Company's maintenance, storage and handling and gas that is available for immediate use, referred to as working gas, which are stated at the lower of cost or net realizable value. Accounting for Oil and Gas Operations We use the full cost method of accounting for oil and gas properties. Accordingly, all costs related to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Overhead costs incurred that are directly identified with acquisition, exploration and development activities undertaken by us for our own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized. Unproved properties are excluded from amortized capitalized costs until it is determined whether or not proved reserves can be assigned to such properties. We assess our unproved properties for impairment at least annually. Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves. All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred. We perform a ceiling test quarterly. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value-based measurement, rather it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using the un-weighted arithmetic average of the first-day-of-the month price for the previous twelve month period, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down or impairment would be recognized to the extent of the excess capitalized costs. Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds capitalized costs in future periods. For the years ended December 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, increases in future operating expenses and future development costs could result in impairments of our oil and gas properties in future periods. Impairment changes are a non-cash charge and accordingly would not affect cash flows but would adversely affect our net income and stockholders' equity. We capitalize interest in accordance with Financial Accounting Standards Board (" FASB Extractive Activities-Oil and Gas, Interest Other Property and Equipment Other property and equipment are recorded at cost or, in the case of assets acquired in a business combination, at fair value. Costs of renewals and improvements that substantially extend the useful lives of assets are capitalized. Maintenance and repair costs which do not extend the useful lives of property and equipment are charged to expense as incurred. Depreciation and amortization are computed using the straight-line method over the estimated useful lives of assets. Office furniture, automobiles, and computer hardware and software are depreciated over three to five years. Buildings are depreciated over 27.5 years, and pipeline facilities and equipment are depreciated over twenty years. Leasehold improvements are capitalized and amortized over the shorter of the lease term or the estimated useful life of the asset. We review our property and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered. We look primarily to the estimated undiscounted future cash flows in our assessment of whether or not property and equipment have been impaired. Base Gas Gas that is used to maintain wellhead pressures within the storage fields, referred to as base gas, is recorded in other property and equipment, net on the consolidated balance sheets. Base gas is held in a storage field that is not intended for sale but is required for efficient and reliable operation of the facility. Asset Retirement Obligations Our 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 (see Notes 6 and 13). Commodity Derivative Instruments We enter into commodity derivative contracts to manage our exposure to oil and natural gas price volatility with an objective to reduce exposure to downward price fluctuations. Commodity derivative contracts may take the form of futures contracts, swaps, collars or options. We have elected not to designate our derivatives as cash flow hedges. All derivatives are initially and subsequently measured at estimated fair value and recorded as assets or liabilities on the consolidated balance sheets. Changes in the fair value of commodity derivative contracts are recognized in revenues in the consolidated statements of operations and gains and losses are included within the cash flows from operating activities in the consolidated statements of cash flows. We do not believe we are exposed to credit risk in our derivative activities as the counterparties are established, well-capitalized financial institutions. Stock - Based Compensation For restricted stock, compensation cost is measured at the grant date, based on the fair value of the awards and is recognized on a straight-line basis over the requisite service period (usually the vesting period). For restricted performance units, once it becomes probable that the performance measure will be achieved, expense is recognized over the remainder of the performance period. Income Taxes We account for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis, as well as the future tax consequences attributable to the future utilization of existing tax net operating losses and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. We account for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more likely than not recognition threshold are recognized. Earnings Per Common Share Basic earnings (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders for the period by the basic weighted average number of common shares outstanding during the period. Diluted earnings (loss) per common share includes potentially issuable shares consisting primarily of non-vested restricted stock and contingent restricted performance units, using the treasury stock method. In periods when we report a net loss, all common stock equivalents are excluded from the calculation of diluted weighted average shares outstanding because they would have an anti-dilutive effect, meaning the loss per share would be reduced. Recently Adopted Accounting Pronouncement On January 1, 2019, we adopted Accounting Standards Update No. 2016-02, Leases Topic 842

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
ACQUISITIONS	Note 3 - Acquisitions Majority Control of Carbon Appalachia On December 31, 2018, we acquired all of Old Ironsides' Class A Units of Carbon Appalachia for approximately $58.2 million, representing approximately 72.76% share ownership. We paid $33.0 million in cash and delivered promissory notes of approximately $25.2 million to Old Ironsides (the "Old Ironsides Notes" The OIE Membership Acquisition was accounted for as a business combination in accordance with ASC 805, Business Combinations ASC 805 Amount Cash consideration $ 33,000 Old Ironsides Notes 25,194 Fair value of previously held equity interest 14,029 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 2,022 Prepaid expenses, deposits, and other current assets 456 Oil and gas properties: Proved 107,694 Unproved 1,869 Other property and equipment, net 15,441 Other non-current assets 514 Accounts payable and accrued liabilities (20,468 ) Due to related parties (236 ) Firm transportation contract obligations (18,724 ) Asset retirement obligations (5,626 ) Notes payable (37,975 ) Total net assets acquired $ 72,223 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, which is recorded in investments in affiliates in our consolidated statement of operations for the year ended December 31, 2018. Consolidation of Carbon Appalachia and OIE Membership Acquisition Pro Forma Results of Operations (Unaudited) Below are unaudited pro forma consolidated results of operations for the year ended December 31, 2018, as though the OIE Membership Acquisition had been completed as of January 1, 2018: Year Ended December 31, (in thousands, except per share amounts) 2018 Revenue $ 136,592 Net income before non-controlling interests $ 11,320 Net income attributable to non-controlling interests $ 4,375 Net income attributable to controlling interests before preferred shares $ 5,596 Net income per share, basic $ 0.74 Net income per share, diluted $ 0.69 Liberty Acquisition On July 11, 2018, we completed an acquisition of 54 operated oil and gas wells covering approximately 55,000 gross acres (22,000 net) and associated mineral interests in the Appalachian Basin for a purchase price of $3.0 million (the " Liberty Acquisition Majority Control of Carbon California The acquisition of additional ownership interest in Carbon California on February 1, 2018, was accounted for as a step acquisition in which we obtained control in accordance with ASC 805 (referred to herein as the " Carbon California Acquisition Amount Fair value of Carbon common shares transferred as consideration $ 8,327 Fair value of non-controlling interest 16,466 Fair value of previously held interest 7,243 Fair value of contribution associated with acquisition of Yorktown's interest in Carbon California 8,637 Fair value of business acquired $ 40,673 Assets acquired and liabilities assumed are as follows: Amount Cash $ 275 Accounts receivable: Joint interest billings and other 690 Receivable - related party 1,610 Prepaid expenses, deposits, and other current assets 1,723 Oil and gas properties: Proved 65,114 Unproved 1,495 Other property and equipment, net 877 Other non-current assets 475 Accounts payable and accrued liabilities (6,054 ) Commodity derivative liability - current (916 ) Commodity derivative liability - non-current (1,729 ) Asset retirement obligations - current (384 ) Asset retirement obligations - non-current (2,537 ) Subordinated Notes, related party, net (8,874 ) Senior Revolving Notes, related party (11,000 ) Notes payable (92 ) Total net assets acquired $ 40,673 On the date of the acquisition, we derecognized our equity investment in Carbon California and recognized a gain of approximately $5.4 million based on the fair value of our previously held interest compared to its carrying value. During the fourth quarter of 2018, the Company finalized the determination of fair value and purchase price allocation related to the Carbon California Acquisition. Based on the final valuation received, the allocation of fair value exceeded the consideration by $8.6 million, which has been reflected in equity as a capital contribution from Yorktown who held a significant membership interest in Carbon California and is the Company's largest stockholder. Seneca Acquisition On May 1, 2018, Carbon California acquired approximately 309 oil wells and approximately 6,800 gross acres (6,600 net) of oil and gas leases, and fee interests in and to certain lands, situated in the Ventura Basin, together with associated pipelines, facilities, equipment and other property rights from Seneca Resources Corporation (" Seneca Acquisition The Seneca Acquisition was accounted for as an asset acquisition as substantially all of the value related to proved oil and gas properties. Consolidation of Carbon California and Seneca Acquisition Pro Forma Results of Operations (Unaudited) Below are unaudited pro forma consolidated results of operations for the year ended December 31, 2018, as though the Carbon California Acquisition and the Seneca Acquisition had been completed as of January 1, 2018: (in thousands, except per share amounts) Year Ended December 31, 2018 Revenue $ 33,256 Net income before non-controlling interests $ 5,232 Net loss attributable to non-controlling interests (2,334 ) Net income attributable to controlling interests $ 7,566 Net income per share (basic) $ 1.00 Net income per share (diluted) $ 0.96

Property and Equipment, Net

Property and Equipment, Net	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
PROPERTY AND EQUIPMENT, NET	Note 4 - Property and Equipment, Net Property and equipment, net consists of the following: As of December 31, (in thousands) 2019 2018 Oil and gas properties: Proved oil and gas properties $ 351,488 $ 347,059 Unproved properties 4,872 5,416 Accumulated depreciation, depletion, amortization and impairment (109,344 ) (98,604 ) Oil and gas properties, net 247,016 253,871 Pipeline facilities and equipment 12,814 12,714 Base gas 1,937 2,122 Furniture and fixtures, computer hardware and software, and other equipment 6,762 6,649 Accumulated depreciation and amortization (5,529 ) (3,922 ) Other property and equipment, net 15,984 17,563 Total property and equipment, net $ 263,000 $ 271,434 Unproved properties not subject to depletion consist principally of leasehold acquisition costs in the following areas: As of December 31, (in thousands) 2019 2018 Ventura Basin: California $ 1,602 $ 1,595 Illinois Basin: Indiana 432 432 Illinois 136 136 Appalachian Basin: Kentucky 461 920 Ohio 66 66 Tennessee 1,869 1,869 West Virginia 306 398 Total unproved properties $ 4,872 $ 5,416 Unproved properties are assessed for impairment at least annually. During the year ended December 31, 2019, approximately $1.0 million of expired leasehold costs were reclassified into proved property. During the year ended December 31, 2018, there were no leasehold costs reclassified into proved property. We capitalized overhead applicable to acquisition, development and exploration activities, primarily in California, of approximately $790,000 and $337,000 for the years ended December 31, 2019 and 2018, respectively. Depletion expense related to oil and gas properties for the years ended December 31, 2019 and 2018 was approximately $14.1 million and $7.3 million, respectively.

Accounts Payable and Accrued Li

Accounts Payable and Accrued Liabilities	12 Months Ended
	Dec. 31, 2019
Payables and Accruals [Abstract]
ACCOUNTS PAYABLE AND ACCRUED LIABILITIES	Note 5 - Accounts Payable and Accrued Liabilities Accounts payable and accrued liabilities consist of the following: As of December 31, (in thousands) 2019 2018 Accounts payable $ 9,875 $ 7,670 Oil and gas revenue suspense 3,620 2,675 Gathering and transportation payables 1,877 1,774 Production taxes payable 3,212 1,860 Accrued lease operating costs 664 3,155 Accrued ad valorem taxes-current 4,407 3,474 Accrued general and administrative expenses 3,260 3,111 Asset retirement obligations-current 5,021 3,099 Accrued interest 1,335 955 Accrued gas purchases 1,392 5,441 Other liabilities 494 1,602 Total accounts payable and accrued liabilities $ 35,157 $ 34,816

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation [Abstract]
ASSET RETIREMENT OBLIGATIONS	Note 6 - Asset Retirement Obligations The following table is a reconciliation of the ARO: December 31, (in thousands) 2019 2018 Balance at beginning of year $ 22,310 $ 7,357 Accretion expense 1,625 868 Additions and revisions 294 - Obligations discharged with divestitures (1,694 ) - Change in estimate of cash outflow - 361 Additions from Carbon California (Note 3) - 2,921 Additions from Seneca Acquisition (Note 3) - 5,132 Additions from Liberty Acquisition (Note 3) - 45 Additions from OIE Membership Acquisition - 5,626 Balance at end of year $ 22,535 $ 22,310 Less: Current portion (5,021 ) (3,099 ) Non-current portion $ 17,514 $ 19,211 See Note 2 for additional details on the ARO.

Credit Facilities and Notes Pay

Credit Facilities and Notes Payable	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
CREDIT FACILITIES AND NOTES PAYABLE	Note 7 - Credit Facilities and Notes Payable The table below summarizes the outstanding credit facilities and notes payable: (in thousands) December 31, December 31, 2018 Credit Facility – revolver $ 69,150 $ 69,150 2018 Credit Facility – term note 5,833 15,000 Old Ironsides Notes 25,675 25,065 Other debt 45 57 Total debt 100,703 109,272 Less: unamortized debt discount (45 ) (134 ) Total credit facilities and notes payable 100,658 109,138 Current portion of credit facilities and notes payable (5,788 ) (11,910 ) Non-current debt, net of current portion and unamortized debt discount $ 94,870 $ 97,228 Carbon Appalachia 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 and entered into a $500.0 million senior secured asset-based revolving credit facility maturing December 31, 2022 and a $15.0 million term loan maturing 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 a margin equal to 0.25% - 0.75% depending on the utilization percentage or (ii) the Adjusted London Interbank Offered Rate (" LIBOR 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 July 1, 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. In August 2019, we amended the 2018 Credit Facility, effective October 1, 2019, to restrict the aging of our accounts payable to 90 days or less, maintain minimum liquidity of $3.0 million and require the sale of certain non-core assets by December 31, 2019. In February 2020, we amended the 2018 Credit Facility to eliminate the minimum liquidity requirement and reduce the borrowing base to $73.0 million, with subsequent borrowing base reductions totaling $6.0 million scheduled through May 1, 2020. Also, in connection with this amendment, the lenders agreed to waive our noncompliance with the hedging requirement for the fiscal quarter ended September 30, 2019 and waive the asset sale covenant included in the amendment from August 2019. As of December 31, 2019, there was approximately $69.2 million in outstanding borrowings and $5.0 million of additional borrowing capacity under the 2018 Credit Facility. After considering the waivers granted in the February 2020 amendment, we were in compliance with our December 31, 2019 financial covenants. As a result of borrowing base reductions in 2020 discussed above and currently depressed oil and natural gas prices, certain of our covenants under the 2018 Credit Facility may be stressed and may require negotiations and adjustments with our lenders. While we have historically been successful in renegotiating covenant requirements with our lenders, there can be no assurance that we will be able to do so successfully in the future. The Company believes given these circumstances it is appropriate to keep the borrowings associated with the 2018 Credit Facility as non-current. 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 International Swaps and Derivatives Association Master Agreements (" ISDA Master Agreements Fees paid in connection with the 2018 Credit Facility totaled approximately $824,000, of which $134,000 was associated with the term loan. The current portion of unamortized fees associated with the credit facility is included in prepaid expenses, 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 $45,000 as of December 31, 2019 and is directly offset against the loan in current liabilities. As of December 31, 2019, we had unamortized deferred issuance costs of approximately $519,000 associated with the 2018 Credit Facility. During the years ended December 31, 2019 and 2018, we amortized approximately $260,000 and $786,000, respectively, 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 $25.2 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 12.0% per annum. For the year ended December 31, 2019, the Company elected payment-in-kind interest of approximately $2.5 million. Carbon California The table below summarizes the outstanding notes payable – related party: (in thousands) December 31, December 31, Senior Revolving Notes, related party, due February 15, 2022 $ 33,000 $ 38,500 Subordinated Notes, related party, due February 15, 2024 13,000 13,000 Total principal 46,000 51,500 Less: Deferred notes costs (175 ) (235 ) Less: unamortized debt discount (1,084 ) (1,346 ) Total notes payable – related party $ 44,741 $ 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 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 December 31, 2019, the effective borrowing rate for the Senior Revolving Notes was 7.10%. 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. 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 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 expenses, deposits and other current assets and the non-current portion is included in other non-current assets for a combined value of approximately $599,000 as of December 31, 2019. For the years ended December 31, 2019 and 2018, Carbon California amortized fees of $273,000 and $217,000, respectively. 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 5.0% of the 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 December 31, 2019, Carbon California has an outstanding discount of $735,000, which is presented net of the Subordinated Notes within Notes payable-related party on the consolidated balance sheets. During the years ended December 31, 2019 and 2018, Carbon California amortized fees of $178,000 and $58,000, respectively, 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 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 12.0% per annum (the " 2018 Subordinated Notes Prudential received 585 Class A Units, representing an approximate 2.0% additional sharing percentage, for the issuance of the 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 December 31, 2019, Carbon California had an outstanding discount of $349,000 associated with these notes, which is presented net of the 2018 Subordinated Notes within Notes payable - related party on the consolidated balance sheet. During the year ended December 31, 2019 and 2018, Carbon California amortized fees of $84,000 and $57,000, respectively, 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 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. In December 2019, Carbon California amended the Senior Revolving Notes, the Subordinated Notes and the 2018 Subordinated Notes to amend the total leverage ratio and senior leverage ratio, effective September 30, 2019. The Senior Revolving Notes were also amended to provide a mechanism to determine a successor reference rate to LIBOR. 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 at December 31, 2019 Carbon California's compliance with (A) a maximum Debt/EBITDA ratio of 4.5 to 1.0 (B) a maximum Senior Revolving Notes/EBITDA ratio of 3.5 to 1.0 and (C) a minimum interest coverage ratio of 2.0 to 1 and (ii) the Subordinated Notes require at December 31, 2019 Carbon California's compliance with (A) a maximum Debt/EBITDA ratio of 5.18 to 1.0, (B) a maximum Senior Revolving Notes/EBITDA ratio of 4.03 to 1.0, (C) a minimum interest coverage ratio of 1.6 to 1.0, (D) an asset coverage test whereby indebtedness may not exceed the product of 0.65 times Adjusted PV-10 of proved developed reserves set forth in the most recent reserve report, (E) maintenance of a minimum borrowing base of $30.0 million under the Senior Revolving Notes and (F) a minimum current ratio of 0.85 to 1.00. As of December 31, 2019, Carbon California was in compliance with its financial covenants.

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
LEASES	Note 8 - Leases On January 1, 2019, we adopted Topic 842. Results for reporting periods beginning January 1, 2019 are presented in accordance with Topic 842, while prior period amounts are reported in accordance with 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 or will be included in lease operating expenses, pipeline operating expenses or general and administrative expenses, as applicable. Our right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet. All leases recognized on our consolidated balance sheet as of December 31, 2019 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 $ 3,282 $ 3,282 Corporate leases 2,065 2,083 Vehicles 757 643 Total $ 6,104 $ 6,008 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 twelve months 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 year ended December 31, 2019: (in thousands) Amount Operating lease cost $ 2,116 Short-term lease cost 629 Total lease cost $ 2,745 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. Our weighted-average lease term and discount rate used are as follows: December 31, Weighted-average lease term (years) 3.59 Weighted-average discount rate 6.4 % The following table summarizes supplemental cash flow information related to operating leases: (in thousands) Year Ended Cash paid for operating leases $ 2,212 Right-of-use assets obtained in exchange for operating lease obligations $ 465 Minimum future commitments by year for our long-term operating leases as of December 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 2020 $ 1,960 2021 1,902 2022 1,704 2023 1,157 2024 11 Thereafter - Total future minimum lease payments $ 6,734 Less: imputed interest (726 ) Total lease liabilities $ 6,008

Revenue

Revenue	12 Months Ended
	Dec. 31, 2019
Revenue Recognition and Deferred Revenue [Abstract]
REVENUE	Note 9 - Revenue Oil, Natural Gas and Natural Gas Liquid Sales We sell oil and natural gas products in the United States primarily within two regions of the United States: Appalachia and Illinois Basins and the 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. Transportation and Handling 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. Under fee-based arrangements, we receive a fee for storing natural gas. The storage revenues earned are directly related to the volume of natural gas that flows through our systems and are not directly dependent on commodity prices. 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. The following tables present our disaggregated revenue by primary region within the United States and major product line (in thousands): Appalachian and Illinois Basins Ventura Basin Total Year Ended Year Ended Year Ended 2019 2018 2019 2018 2019 2018 Natural gas sales $ 55,279 $ 14,768 $ 1,189 $ 1,250 $ 56,468 $ 16,018 Natural gas liquids sales - - 578 1,143 578 1,143 Oil sales 5,805 4,963 30,990 25,928 36,795 30,891 Transportation and handling 1,928 - - - 1,928 - Marketing gas sales 16,920 - - - 16,920 - Total $ 79,932 $ 19,731 $ 32,757 $ 28,321 $ 112,689 $ 48,052

Stock-Based Compensation Plans

Stock-Based Compensation Plans and Employee Benefit Plans	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
STOCK-BASED COMPENSATION PLANS AND EMPLOYEE BENEFIT PLANS	Note 10 - Stock-Based Compensation Plans and Employee Benefit Plans Carbon Stock Incentive Plans We have three stock plans, the Carbon 2011 Stock Incentive Plan, the Carbon 2015 Stock Incentive Plan and the Carbon 2019 Long Term 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 Restricted stock awards for employees vest ratably over a three-year service period or cliff vest at the end of a three-year service period. For non-employee directors, the awards vest upon the earlier of a change in control of us or the date their membership on the Board of Directors is terminated other than for cause. We recognize compensation expense for these restricted stock grants based on the grant date fair value. The following table shows a summary of our unvested restricted stock under the Carbon Plans as of December 31, 2019 and 2018 as well as activity during the years then ended: Weighted Average Number of Shares Grant Date Restricted stock awards, unvested, January 1, 2018 269,997 $ 7.54 Granted 106,000 9.80 Vested (59,550 ) 6.82 Forfeited (2,240 ) 7.41 Restricted stock awards, unvested, December 31, 2018 314,207 $ 8.40 Granted 99,000 10.00 Vested (105,628 ) 6.75 Forfeited (6,682 ) 9.74 Restricted stock awards, unvested, December 31, 2019 300,897 $ 9.41 Compensation costs recognized for these restricted stock grants were approximately $811,000 and $725,000 for the years ended December 31, 2019 and 2018, respectively. As of December 31, 2019, there was approximately $1.5 million of unrecognized compensation costs related to these restricted stock grants which we expect to recognize over the next 6.3 years. Restricted Performance Units Performance units represent a contractual right to receive one share of our common stock subject to the terms and conditions of the agreements, including the achievement of certain performance measures over a defined period of time as well as, in some cases, continued service requirements. The following table shows a summary of our unvested performance units as of December 31, 2019 and 2018 as well as activity during the years then ended: Number of Shares Restricted performance units, unvested, January 1, 2018 258,811 Granted 136,159 Vested (108,484 ) Forfeited (6,610 ) Restricted performance units, unvested, December 31, 2018 279,876 Granted 101,864 Vested (95,451 ) Forfeited (11,084 ) Restricted performance units, unvested, December 31, 2019 275,205 We account for the performance units granted during 2017 through 2019 at their fair value determined at the date of grant, which were $7.20, $9.80 and $10.00 per share, respectively. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At December 31, 2019, we estimated that none of the performance units granted in 2019 and 2018 would vest, and, accordingly, no compensation cost has been recorded for these performance units. At December 31, 2019, we estimated that it was probable that the performance units granted in 2015, 2016 and 2017 would vest and therefore compensation costs of approximately $637,000 and $408,000 related to these performance units were recognized for the years ended December 31, 2019 and 2018, respectively. As of December 31, 2019, compensation costs related to the performance units granted in 2015, 2016 and 2017 have been fully recognized. As of December 31, 2019, if a change in control and other performance provisions pursuant to the terms and conditions of these award agreements were met in full, the estimated unrecognized compensation cost related to unvested performance units would be approximately $3.2 million. 401(k) Plan We have a 401(k) plan available to eligible employees. The plan provides for 6.0% matching which vests immediately. For the years ended December 31, 2019 and 2018, we contributed approximately $527,000 and $441,000, respectively, for 401(k) contributions and related administrative expenses.

Earnings (Loss) Per Common Shar

Earnings (Loss) Per Common Share	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
EARNINGS (LOSS) PER COMMON SHARE	Note 11 - Earnings (Loss) Per Common Share The following table sets forth the calculation of basic and diluted income (loss) per share: Year Ended (in thousands, except per share amounts) 2019 2018 Net income attributable to controlling interests before preferred shares $ 1,097 $ 8,404 Less: beneficial conversion feature - 1,125 Less: net income attributable to preferred shares – preferred return 300 224 Net income attributable to common stockholders, basic 797 7,055 Less: warrant derivative gain - 225 Net income attributable to common stockholders, diluted $ 797 $ 6,830 Weighted-average number of common shares outstanding, basic 7,794 7,525 Add dilutive effects of non-vested shares of restricted stock and restricted performance units 301 314 Weighted-average number of common shares outstanding, diluted 8,095 7,839 Net income per common share, basic $ 0.10 $ 0.94 Net income per common share, diluted $ 0.10 $ 0.87 For the years ended December 31, 2019 and 2018, approximately 275,000 and 280,000 restricted performance units subject to future contingencies were excluded from the computation of basic and diluted earnings per share. 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 Series B Convertible Preferred Stock, par value $0.01 per share (" Preferred Stock The Preferred Stock accrues cash dividends at a rate of 6.0% 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 stockholders and the holders of any junior ranking stock. The preferred return was approximately $524,000 and $224,000 as of December 31, 2019 and 2018, respectively.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
INCOME TAXES	Note 12 - Income Taxes The provision for income taxes consists of the following: Year Ended December 31, (in thousands) 2019 2018 Current income tax benefit $ - $ - Deferred income tax expense (benefit) 895 (590 ) Change in valuation allowance (895 ) 590 Total income tax benefit $ - $ - The effective income tax rate for the years ended December 31, 2019 and 2018 differed from the statutory U.S. federal income tax rate as follows: Year Ended December 31, 2019 2018 Federal income tax rate 21.0 % 21.0 % State income taxes, net of federal benefit 4.9 4.9 Permanent differences (3.3 ) (1.2 ) Non-controlling interest in consolidated partnerships (46.2 ) (11.4 ) True-up of prior year depletion in excess of basis (6.5 ) 1.3 Stock-based compensation deficiency (16.0 ) 1.1 Purchase accounting adjustments (45.0 ) (22.9 ) Rate changes of prior year deferred 1.8 (0.5 ) True-up of prior year deferred - 3.0 Decrease in valuation allowance and other 89.3 4.7 Total effective income tax rate - % - % The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities are presented below: (in thousands) As of December 31, 2019 2018 Deferred tax assets: Net operating loss carryforwards $ 6,232 $ 7,573 Depletion carryforwards 2,569 2,166 Accrual and other 3,997 1,372 Stock-based compensation 469 445 Asset retirement obligations 4,659 4,567 Property and equipment (2,253 ) (42 ) Total deferred tax assets 15,673 16,081 Deferred tax liabilities: Interest in partnerships (338 ) (512 ) ASC 842 Operating Leases (12 ) - Derivative and other (1,689 ) (1,008 ) Less valuation allowance (13,634 ) (14,561 ) Net deferred tax asset $ - $ - The Company has net operating losses (" NOL The Company believes that the tax positions taken in the Company's tax returns satisfy the more likely than not threshold for benefit recognition. Accordingly, no liabilities have been recorded by the Company. Any potential adjustments for uncertain tax positions would be a reclassification between the deferred tax asset related to the Company's NOL and another deferred tax asset. The Company's policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2019 and 2018, the Company did not have any uncertain tax positions.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	Note 13 - 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: Fair Value Measurements Using (in thousands) Level 1 Level 2 Level 3 Total December 31, 2019 Assets: Commodity derivatives $ - $ 7,079 $ - $ 7,079 Liabilities: Commodity derivatives $ - $ 556 $ - $ 556 December 31, 2018 Assets: Commodity derivatives $ - $ 7,022 $ - $ 7,022 Commodity Derivatives As of December 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 significant inputs are observable, either directly or indirectly; therefore, our derivative instruments are included within the Level 2 fair value hierarchy. Assets and Liabilities Measured and Recorded at Fair Value on a Non-Recurring Basis Certain assets and liabilities are measured at fair value on a non-recurring basis. These assets and liabilities are not measured at fair value on an ongoing basis; however they are subject to fair value adjustments in certain circumstances. The fair value of the following assets and liabilities are based on unobservable pricing inputs and therefore, are included within the Level 3 fair value hierarchy. Firm transportation contracts Debt Discount. Asset Retirement Obligation

Commodity Derivatives

Commodity Derivatives	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
COMMODITY DERIVATIVES	Note 14 - 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 consolidated financial statements. We have entered into swap and costless collar derivative agreements to hedge a portion of our oil and natural gas production through 2022. As of December 31, 2019, these derivative agreements consisted of the following: Natural Gas Swaps Natural Gas Collars Weighted Weighted Year MMBtu Price (a) MMBtu Range (a) 2020 12,433,000 $ 2.73 3,430,000 $2.10 – $2.75 2021 6,448,000 $ 2.58 1,745,000 $2.25 – $2.75 Oil Swaps* Oil Collars* Year WTI Bbl Weighted Average Brent Bbl Weighted Average WTI Bbl Weighted Average Brent Bbl Weighted Average 2019 17,523 $53.30 13,805 $64.87 1,700 $47.50 - $57.35 4,500 $47.00 - $75.00 2020 121,147 $ 55.37 207,182 $ 64.62 28,200 $47.00 - $60.15 57,900 $47.00 - $75.00 2021 - $ - 86,341 $ 67.12 66,200 $47.00 - $60.15 190,000 $47.00 - $75.00 2022 - $ - - $ - - $ - 199,900 $50.00 - $61.00 * Includes 100% of Carbon California’s outstanding derivative hedges at December 31, 2019, and not our proportionate share. (a) NYMEX Henry Hub Natural Gas futures contracts for the respective period. (b) NYMEX Light Sweet Crude West Texas Intermediate futures contracts 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 consolidated balance sheets. These derivative instruments are not designated as cash flow hedging instruments for accounting purposes. As of December 31, (in thousands) 2019 2018 Commodity derivative contracts: Commodity derivative asset $ 5,915 $ 3,517 Commodity derivative asset – non-current $ 1,164 $ 3,505 Commodity derivative liability $ 469 $ - Commodity derivative liability – non-current $ 87 $ - The following table summarizes the commodity derivative gain presented in the accompanying consolidated statements of operations: Year Ended (in thousands) 2019 2018 Commodity derivative contracts: Settlement gain (loss) $ 3,543 $ (3,848 ) Unrealized (loss) gain (499 ) 8,742 Total commodity derivative gain $ 3,044 $ 4,894 We net our derivative instrument fair value amounts pursuant to ISDA Master Agreements, which provide 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 effect of netting arrangements for recognized derivative assets and liabilities that are subject to master netting arrangements or similar arrangements in the consolidated balance sheet as of December 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 $ 6,917 $ (1,002 ) $ 5,915 Commodity derivative asset – non-current 3,478 (2,314 ) 1,164 Total derivative assets $ 10,395 $ (3,316 ) $ 7,079 Commodity derivative liabilities: Commodity derivative liability $ (1,471 ) $ 1,002 $ (469 ) Commodity derivative liability – non-current (2,401 ) 2,314 (87 ) Total derivative liabilities $ (3,872 ) $ 3,316 $ (556 ) Due to the volatility of oil and natural gas prices, the estimated fair values of our derivatives are subject to fluctuations from period to period.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	Note 15 - Commitments and Contingencies We have entered into 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 as of December 31, 2019 are summarized in the table below. Period Dekatherms Demand Charges Jan 2020 – 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 December 31, 2019, the remaining commitment related to the firm transportation contracts assumed in the EXCO Acquisition in October 2016 and the OIE Membership Acquisition is $14.6 million and reflected in the Company’s consolidated balance sheet. These contractual obligations are reduced monthly as the Company pays these firm transportation obligations. Natural gas processing agreement We have entered into an initial five-year gas processing agreement expiring in 2022. 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 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 December 31, 2019, we had no capital commitments.

Supplemental Cash Flow Disclosu

Supplemental Cash Flow Disclosure	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Elements [Abstract]
SUPPLEMENTAL CASH FLOW DISCLOSURE	Note 16 - Supplemental Cash Flow Disclosure Supplemental cash flow disclosures are presented below: Year Ended (in thousands) 2019 2018 Cash paid during the period for: Interest $ 9,191 $ 4,217 Non-cash transactions: Capital expenditures included in accounts payable and accrued liabilities $ (2,563 ) $ (206 ) Adjustments to OIE Membership Acquisition purchase price $ 1,505 -

Supplemental Financial Data - O

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited)	12 Months Ended
	Dec. 31, 2019
Extractive Industries [Abstract]
SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	Note 17 - Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) Estimated Proved Oil, Natural Gas, and Natural Gas Liquid Reserves The reserve estimates as of December 31, 2019 and 2018 presented herein were made in accordance with oil and gas reserve estimation and disclosure authoritative accounting guidance. Proved oil, natural gas, and natural gas liquid reserves as of December 31, 2019 and 2018 were calculated based on the prices for oil, natural gas, and natural gas liquids during the twelve-month period before the reporting date, determined as an un-weighted arithmetic average of the first-day-of-the month price for each month within such period. This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. SEC rules dictate the types of technologies that a company may use to establish reserve estimates, including the extraction of non-traditional resources, such as bitumen extracted from oil sands as well as oil and gas extracted from shales. Our estimates of our net proved, net proved developed, and net proved undeveloped oil, gas and natural gas liquids reserves and changes in our net proved oil, natural gas, and natural gas liquid reserves for 2019 and 2018 are presented in the table below. Proved oil, natural gas, and natural gas liquid reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Existing economic conditions include the average prices for oil and gas during the twelve-month period prior to the reporting date of December 31, 2019 and 2018 unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Prices do not include the effects of commodity derivatives. The independent engineering firm, Cawley, Gillespie & Associates, Inc. (" CGA Proved developed oil and gas reserves are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. A summary of the changes in quantities of proved oil, natural gas, and natural gas liquid reserves for the years ended December 31, 2019 and 2018 are as follows (in thousands): 2019 2018 Oil Natural Gas NGL Total Oil Natural Gas NGL Total MBbls MMcf MBbls MMcfe MBbls MMcf MBbls MMcfe Proved reserves, beginning of year 18,898 455,400 1,923 580,326 919 81,702 - 87,216 Revisions of previous estimates (1,362 ) 24,194 (618 ) 12,310 (2,803 ) 1,832 (1,147 ) (21,868 ) Extensions and discoveries 826 1,187 77 6,605 - - - - Production (589 ) (21,436 ) (36 ) (25,182 ) (451 ) (4,798 ) (33 ) (7,702 ) Purchases of reserves in-place - - - - 21,233 376,664 3,103 522,680 Sales of reserves in-place (31 ) (8,980 ) - (9,166 ) - - - - Proved reserves, end of year 17,742 450,365 1,346 564,893 18,898 455,400 1,923 580,326 Proved developed reserves at: End of year 12,972 444,104 936 527,555 14,336 450,424 1,472 545,272 Proved undeveloped reserves at: End of year 4,770 6,261 410 37,338 4,562 4,976 451 35,054 The estimated proved reserves for December 31, 2019 and 2018 includes approximately 3.4 Bcfe and 3.3 Bcfe, respectively, attributed to non-controlling interests of consolidated partnerships. Aggregate Capitalized Costs The aggregate capitalized costs relating to oil and gas producing activities at the end of each of the years indicated were as follows: (in thousands) 2019 2018 Oil and gas properties: Proved oil and gas properties $ 351,488 $ 347,059 Unproved properties 4,872 5,416 Accumulated depreciation, depletion, amortization and impairment (109,344 ) (98,604 ) Total $ 247,016 $ 253,871 Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities The following costs were incurred in oil and gas property acquisition, exploration, and development activities during the years ended December 31, 2019 and 2018: (in thousands) 2019 2018 Property acquisition costs: Unevaluated properties $ - $ 3,464 Proved properties and gathering facilities - 63,517 Development costs 7,676 2,074 Gathering facilities - 460 Asset retirement obligations - 14,085 Total $ 7,676 $ 83,600 Our investment in unproved properties as of December 31, 2019, by the year in which such costs were incurred is set forth in the table below: (in thousands) 2019 2018 2017 and Prior Acquisition costs $ 496 $ 3,464 $ 912 Results of Operations from Oil and Gas Producing Activities Results of operations from oil and gas producing activities for the years ended December 31, 2019 and 2018 are presented below: (in thousands) 2019 2018 Revenues: Oil, gas and NGL sales, including commodity derivative gains and losses $ 96,885 $ 52,946 Expenses: Production expenses 41,307 22,226 Depletion expense 14,062 7,305 Accretion of asset retirement obligations 1,625 868 Total expenses 56,994 30,399 Results of operations from oil and gas producing activities $ 39,891 $ 22,547 Depletion rate per Mcfe $ 0.56 $ 0.89 Standardized Measure of Discounted Future Net Cash Flows Future oil and gas sales are calculated applying the prices used in estimating our proved oil and gas reserves to the year-end quantities of those reserves. Future price changes were considered only to the extent provided by contractual arrangements in existence at each year-end. Future production and development costs, which include costs related to plugging of wells, removal of facilities and equipment, and site restoration, are calculated by estimating the expenditures to be incurred in producing and developing the proved oil and gas reserves at the end of each year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses give effect to tax deductions, credits, and allowances relating to the proved oil and gas reserves. All cash flow amounts, including income taxes, are discounted at 10%. Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. Management does not rely upon the information that follows in making investment decisions. December 31, (in thousands) 2019 2018 Future cash inflows $ 2,212,049 $ 2,878,392 Future production costs (1,306,608 ) (1,538,870 ) Future development costs (77,952 ) (76,852 ) Future income taxes (146,951 ) (258,277 ) Future net cash flows 680,538 1,004,393 10% annual discount (408,690 ) (612,325 ) Standardized measure of discounted future net cash flows $ 271,848 $ 392,068 Changes in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves An analysis of the changes in the standardized measure of discounted future net cash flows during each of the last two years is as follows: December 31, (in thousands) 2019 2018 Standardized measure of discounted future net cash flows, beginning of period $ 392,068 $ 57,082 Sales of oil and gas, net of production costs and taxes (49,746 ) (25,681 ) Price revisions (158,799 ) 133,789 Extensions, discoveries and improved recovery, less related costs 10,822 - Changes in estimated future development costs (3,041 ) (32,711 ) Development costs incurred during the period 6,685 926 Quantity revisions 5,565 (23,484 ) Accretion of discount 39,207 5,708 Net changes in future income taxes 39,929 (89,117 ) Purchases of reserves-in-place - 391,877 Sales of reserves-in-place (4,004 ) - Changes in production rate timing and other (6,838 ) (26,321 ) Standardized measure of discounted future net cash flows, end of period $ 271,848 $ 392,068 The twelve-month weighted averaged adjusted prices in effect at December 31, 2019 and 2018 were as follows: 2019 2018 Oil (per Bbl) $ 55.69 $ 65.56 Natural Gas (per Mcf) $ 2.58 $ 3.10

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The consolidated financial statements include the accounts of Carbon Energy Corporation and its consolidated subsidiaries. In addition to Carbon Appalachia and Carbon California, we consolidate 46 partnerships in which we have a controlling interest. We reflect the non-controlling ownership interest of the portion we do not own on our consolidated balance sheets within stockholders' equity and our consolidated statements of operations. In accordance with established practice in the oil and gas industry, our consolidated financial statements also include our pro-rata share of assets, liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which we have a non-controlling interest. We utilize the equity method to account for investments that do not meet the criteria for pro rata consolidation when we have the ability to significantly influence the operating decisions of the investee. All significant intercompany accounts and transactions have been eliminated.
Use of Estimates in the Preparation of Financial Statements	Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“ GAAP
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. The remaining reclassifications include certain immaterial balance sheet and expense accounts. These reclassifications had no impact on net income or stockholders' equity previously reported.
Fair Value of Financial Instruments	Fair Value of Financial Instruments The carrying value of our cash and cash equivalents, accounts receivables, prepaid expenses, deposits and other current assets and accounts payable and accrued liabilities approximate fair value due to the short maturity of these instruments. The carrying value of our notes payable and credit facilities approximate fair value based on the variable nature of interest rates and current market rates available to us. Commodity derivatives are recorded at fair value.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents have been generally invested in money market accounts, certificates of deposits and other cash equivalents with maturities of three months or less . Such investments are deemed to be cash equivalents for purposes of the financial statements. At times, the Company may have cash and cash equivalent balances more than federal insured amounts within their accounts.
Accounts Receivable	Accounts Receivable We grant credit to all qualified customers, which potentially subjects us to credit risk resulting from, among other factors, adverse changes in the industries in which we operate and the financial condition of our customers. We continuously monitor collections and payments from our customers and, if necessary, maintain an allowance for doubtful accounts based upon our historical experience and any specific customer collection issues that we have identified. At December 31, 2019 and 2018, we had not identified any collection issues related to our oil and gas operations and consequently no allowance for doubtful accounts was provided for on those dates. Revenue Accounts receivable - Revenue is comprised of oil, natural gas and NGL revenues from producing activities. We recognize an asset or a liability, whichever is appropriate, for revenues associated with over-deliveries or under-deliveries of natural gas to purchasers. A purchaser imbalance asset occurs when we deliver more natural gas than we nominated to deliver to the purchaser and the purchaser pays only for the nominated amount. Conversely, a purchaser imbalance liability occurs when we deliver less natural gas than we nominated to deliver to the purchaser and the purchaser pays for the amount nominated. As of December 31, 2019, and 2018, we had a purchaser imbalance receivable of $956,000 and $551,000, respectively, within accounts receivable-revenue. Joint Interest Billings and Other Our accounts receivable - joint interest billings and other is comprised of receivables due from other exploration and production companies and individuals who own working interests in the properties that we operate. For receivables from joint interest owners, we typically have the ability to withhold future revenues disbursements to recover any non-payment of joint-interest billings. 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 final settlement payment from our insurance provider related to the damage caused by the California wildfires. As of December 31, 2019, we were in receipt of all funds associated with the claims.
Revenue Recognition	Revenue Recognition Oil, natural gas and natural gas liquids revenues are recognized when the performance obligation to deliver the production volumes is met and control is transferred to the customer. All product revenues are recognized on the basis of our net revenue interest. Oil and natural gas are 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 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 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 consolidated statements of operations, while transportation and gathering costs incurred subsequent to control transfer are recognized as a reduction to the related revenue. 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. The estimated revenue is recorded within Accounts receivable – Revenue on the consolidated balance sheets. 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. Purchaser Concentration We sell our oil, natural gas and natural gas liquids production to various purchasers in the industry. The table below presents purchasers that account for 10% or more of total oil, natural gas, and natural gas liquids sales for the years ended December 31, 2019 and 2018. There are several purchasers in the areas where we sell our production. We do not believe that changing our primary purchasers or a loss of any other single purchaser would materially impact our business. Year Ended Purchaser 2019 2018 Purchaser A 18 % * Purchaser B 11 % * Purchaser C * 17 % Purchaser D * 16 % Purchaser E * 12 % * less than 10% As of December 31, 2019, none of the above purchasers comprised more than 10% of total accounts receivable. One purchaser's receivable acquired with the closing of the OIE Membership Acquisition accounted for approximately 10% of accounts receivable as of December 31, 2018.
Inventory	Inventory Inventory includes natural gas, which is recorded at the lower of weighted average cost or market value. Inventory also consists of material and supplies used in connection with the Company's maintenance, storage and handling and gas that is available for immediate use, referred to as working gas, which are stated at the lower of cost or net realizable value.
Accounting for Oil and Gas Operations	Accounting for Oil and Gas Operations We use the full cost method of accounting for oil and gas properties. Accordingly, all costs related to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Overhead costs incurred that are directly identified with acquisition, exploration and development activities undertaken by us for our own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized. Unproved properties are excluded from amortized capitalized costs until it is determined whether or not proved reserves can be assigned to such properties. We assess our unproved properties for impairment at least annually. Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves. All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred. We perform a ceiling test quarterly. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value-based measurement, rather it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using the un-weighted arithmetic average of the first-day-of-the month price for the previous twelve month period, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down or impairment would be recognized to the extent of the excess capitalized costs. Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds capitalized costs in future periods. For the years ended December 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, increases in future operating expenses and future development costs could result in impairments of our oil and gas properties in future periods. Impairment changes are a non-cash charge and accordingly would not affect cash flows but would adversely affect our net income and stockholders' equity. We capitalize interest in accordance with Financial Accounting Standards Board (" FASB Extractive Activities-Oil and Gas, Interest
Other Property and Equipment	Other Property and Equipment Other property and equipment are recorded at cost or, in the case of assets acquired in a business combination, at fair value. Costs of renewals and improvements that substantially extend the useful lives of assets are capitalized. Maintenance and repair costs which do not extend the useful lives of property and equipment are charged to expense as incurred. Depreciation and amortization are computed using the straight-line method over the estimated useful lives of assets. Office furniture, automobiles, and computer hardware and software are depreciated over three to five years. Buildings are depreciated over 27.5 years, and pipeline facilities and equipment are depreciated over twenty years. Leasehold improvements are capitalized and amortized over the shorter of the lease term or the estimated useful life of the asset. We review our property and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered. We look primarily to the estimated undiscounted future cash flows in our assessment of whether or not property and equipment have been impaired. Base Gas Gas that is used to maintain wellhead pressures within the storage fields, referred to as base gas, is recorded in other property and equipment, net on the consolidated balance sheets. Base gas is held in a storage field that is not intended for sale but is required for efficient and reliable operation of the facility.
Asset Retirement Obligations	Asset Retirement Obligations Our 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 (see Notes 6 and 13).
Commodity Derivative Instruments	Commodity Derivative Instruments We enter into commodity derivative contracts to manage our exposure to oil and natural gas price volatility with an objective to reduce exposure to downward price fluctuations. Commodity derivative contracts may take the form of futures contracts, swaps, collars or options. We have elected not to designate our derivatives as cash flow hedges. All derivatives are initially and subsequently measured at estimated fair value and recorded as assets or liabilities on the consolidated balance sheets. Changes in the fair value of commodity derivative contracts are recognized in revenues in the consolidated statements of operations and gains and losses are included within the cash flows from operating activities in the consolidated statements of cash flows. We do not believe we are exposed to credit risk in our derivative activities as the counterparties are established, well-capitalized financial institutions.
Stock - Based Compensation	Stock - Based Compensation For restricted stock, compensation cost is measured at the grant date, based on the fair value of the awards and is recognized on a straight-line basis over the requisite service period (usually the vesting period). For restricted performance units, once it becomes probable that the performance measure will be achieved, expense is recognized over the remainder of the performance period.
Income Taxes	Income Taxes We account for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis, as well as the future tax consequences attributable to the future utilization of existing tax net operating losses and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. We account for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more likely than not recognition threshold are recognized.
Earnings Per Common Share	Earnings Per Common Share Basic earnings (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders for the period by the basic weighted average number of common shares outstanding during the period. Diluted earnings (loss) per common share includes potentially issuable shares consisting primarily of non-vested restricted stock and contingent restricted performance units, using the treasury stock method. In periods when we report a net loss, all common stock equivalents are excluded from the calculation of diluted weighted average shares outstanding because they would have an anti-dilutive effect, meaning the loss per share would be reduced.
Recently Adopted Accounting Pronouncements	Recently Adopted Accounting Pronouncement On January 1, 2019, we adopted Accounting Standards Update No. 2016-02, Leases Topic 842

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Schedule of purchaser concentration	Year Ended Purchaser 2019 2018 Purchaser A 18 % * Purchaser B 11 % * Purchaser C * 17 % Purchaser D * 16 % Purchaser E * 12 % * less than 10%

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2019
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Schedule of fair value of business acquired	Amount Cash consideration $ 33,000 Old Ironsides Notes 25,194 Fair value of previously held equity interest 14,029 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 2,022 Prepaid expenses, deposits, and other current assets 456 Oil and gas properties: Proved 107,694 Unproved 1,869 Other property and equipment, net 15,441 Other non-current assets 514 Accounts payable and accrued liabilities (20,468 ) Due to related parties (236 ) 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	(in thousands, except per share amounts) Year Ended December 31, 2018 Revenue $ 33,256 Net income before non-controlling interests $ 5,232 Net loss attributable to non-controlling interests (2,334 ) Net income attributable to controlling interests $ 7,566 Net income per share (basic) $ 1.00 Net income per share (diluted) $ 0.96
OIE Membership Acquisition [Member]
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Schedule of fair value of business acquired	Amount Fair value of Carbon common shares transferred as consideration $ 8,327 Fair value of non-controlling interest 16,466 Fair value of previously held interest 7,243 Fair value of contribution associated with acquisition of Yorktown’s interest in Carbon California 8,637 Fair value of business acquired $ 40,673
Schedule of assets acquired and liabilities assumed	Amount Cash $ 275 Accounts receivable: Joint interest billings and other 690 Receivable - related party 1,610 Prepaid expenses, deposits, and other current assets 1,723 Oil and gas properties: Proved 65,114 Unproved 1,495 Other property and equipment, net 877 Other non-current assets 475 Accounts payable and accrued liabilities (6,054 ) Commodity derivative liability - current (916 ) Commodity derivative liability - non-current (1,729 ) Asset retirement obligations - current (384 ) Asset retirement obligations - non-current (2,537 ) Subordinated Notes, related party, net (8,874 ) Senior Revolving Notes, related party (11,000 ) Notes payable (92 ) Total net assets acquired $ 40,673
Schedule of unaudited pro-forma consolidated results	Year Ended December 31, (in thousands, except per share amounts) 2018 Revenue $ 136,592 Net income before non-controlling interests $ 11,320 Net income attributable to non-controlling interests $ 4,375 Net income attributable to controlling interests before preferred shares $ 5,596 Net income per share, basic $ 0.74 Net income per share, diluted $ 0.69

Property and Equipment, Net (Ta

Property and Equipment, Net (Tables)	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Schedule of net property and equipment	As of December 31, (in thousands) 2019 2018 Oil and gas properties: Proved oil and gas properties $ 351,488 $ 347,059 Unproved properties 4,872 5,416 Accumulated depreciation, depletion, amortization and impairment (109,344 ) (98,604 ) Oil and gas properties, net 247,016 253,871 Pipeline facilities and equipment 12,814 12,714 Base gas 1,937 2,122 Furniture and fixtures, computer hardware and software, and other equipment 6,762 6,649 Accumulated depreciation and amortization (5,529 ) (3,922 ) Other property and equipment, net 15,984 17,563 Total property and equipment, net $ 263,000 $ 271,434
Schedule of unproved oil and gas properties	As of December 31, (in thousands) 2019 2018 Ventura Basin: California $ 1,602 $ 1,595 Illinois Basin: Indiana 432 432 Illinois 136 136 Appalachian Basin: Kentucky 461 920 Ohio 66 66 Tennessee 1,869 1,869 West Virginia 306 398 Total unproved properties $ 4,872 $ 5,416

Accounts Payable and Accrued _2

Accounts Payable and Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
Payables and Accruals [Abstract]
Schedule of accounts payable and accrued liabilities	As of December 31, (in thousands) 2019 2018 Accounts payable $ 9,875 $ 7,670 Oil and gas revenue suspense 3,620 2,675 Gathering and transportation payables 1,877 1,774 Production taxes payable 3,212 1,860 Accrued lease operating costs 664 3,155 Accrued ad valorem taxes-current 4,407 3,474 Accrued general and administrative expenses 3,260 3,111 Asset retirement obligations-current 5,021 3,099 Accrued interest 1,335 955 Accrued gas purchases 1,392 5,441 Other liabilities 494 1,602 Total accounts payable and accrued liabilities $ 35,157 $ 34,816

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation [Abstract]
Schedule of reconciliation of the ARO	December 31, (in thousands) 2019 2018 Balance at beginning of year $ 22,310 $ 7,357 Accretion expense 1,625 868 Additions and revisions 294 - Obligations discharged with divestitures (1,694 ) - Change in estimate of cash outflow - 361 Additions from Carbon California (Note 3) - 2,921 Additions from Seneca Acquisition (Note 3) - 5,132 Additions from Liberty Acquisition (Note 3) - 45 Additions from OIE Membership Acquisition - 5,626 Balance at end of year $ 22,535 $ 22,310 Less: Current portion (5,021 ) (3,099 ) Non-current portion $ 17,514 $ 19,211

Credit Facilities and Notes P_2

Credit Facilities and Notes Payable (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of outstanding credit facilities and notes payable	(in thousands) December 31, December 31, 2018 Credit Facility – revolver $ 69,150 $ 69,150 2018 Credit Facility – term note 5,833 15,000 Old Ironsides Notes 25,675 25,065 Other debt 45 57 Total debt 100,703 109,272 Less: unamortized debt discount (45 ) (134 ) Total credit facilities and notes payable 100,658 109,138 Current portion of credit facilities and notes payable (5,788 ) (11,910 ) Non-current debt, net of current portion and unamortized debt discount $ 94,870 $ 97,228
Schedule of outstanding notes payable - related party	(in thousands) December 31, December 31, Senior Revolving Notes, related party, due February 15, 2022 $ 33,000 $ 38,500 Subordinated Notes, related party, due February 15, 2024 13,000 13,000 Total principal 46,000 51,500 Less: Deferred notes costs (175 ) (235 ) Less: unamortized debt discount (1,084 ) (1,346 ) Total notes payable – related party $ 44,741 $ 49,919

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Schedule of operating leases related to the asset classes	(in thousands) Right-of-Use Assets Lease Compressors $ 3,282 $ 3,282 Corporate leases 2,065 2,083 Vehicles 757 643 Total $ 6,104 $ 6,008
Schedule of gross operating lease costs	(in thousands) Amount Operating lease cost $ 2,116 Short-term lease cost 629 Total lease cost $ 2,745
Schedule of weighted-average lease term and discount rate	December 31, Weighted-average lease term (years) 3.59 Weighted-average discount rate 6.4 %
Schedule of supplemental cash flow information related to leases	(in thousands) Year Ended Cash paid for operating leases $ 2,212 Right-of-use assets obtained in exchange for operating lease obligations $ 465
Schedule of lease liability maturities	(in thousands) Amount 2020 $ 1,960 2021 1,902 2022 1,704 2023 1,157 2024 11 Thereafter - Total future minimum lease payments $ 6,734 Less: imputed interest (726 ) Total lease liabilities $ 6,008

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue Recognition and Deferred Revenue [Abstract]
Schedule of disaggregation of revenue	Appalachian and Illinois Basins Ventura Basin Total Year Ended Year Ended Year Ended 2019 2018 2019 2018 2019 2018 Natural gas sales $ 55,279 $ 14,768 $ 1,189 $ 1,250 $ 56,468 $ 16,018 Natural gas liquids sales - - 578 1,143 578 1,143 Oil sales 5,805 4,963 30,990 25,928 36,795 30,891 Transportation and handling 1,928 - - - 1,928 - Marketing gas sales 16,920 - - - 16,920 - Total $ 79,932 $ 19,731 $ 32,757 $ 28,321 $ 112,689 $ 48,052

Stock-Based Compensation Plan_2

Stock-Based Compensation Plans and Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Summary of unvested restricted stock under the Carbon Plans	Weighted Average Number of Shares Grant Date Restricted stock awards, unvested, January 1, 2018 269,997 $ 7.54 Granted 106,000 9.80 Vested (59,550 ) 6.82 Forfeited (2,240 ) 7.41 Restricted stock awards, unvested, December 31, 2018 314,207 $ 8.40 Granted 99,000 10.00 Vested (105,628 ) 6.75 Forfeited (6,682 ) 9.74 Restricted stock awards, unvested, December 31, 2019 300,897 $ 9.41
Summary of unvested performance units	Number of Shares Restricted performance units, unvested, January 1, 2018 258,811 Granted 136,159 Vested (108,484 ) Forfeited (6,610 ) Restricted performance units, unvested, December 31, 2018 279,876 Granted 101,864 Vested (95,451 ) Forfeited (11,084 ) Restricted performance units, unvested, December 31, 2019 275,205

Earnings (Loss) Per Common Sh_2

Earnings (Loss) Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Schedule of basic and diluted (loss) income per share	Year Ended (in thousands, except per share amounts) 2019 2018 Net income attributable to controlling interests before preferred shares $ 1,097 $ 8,404 Less: beneficial conversion feature - 1,125 Less: net income attributable to preferred shares – preferred return 300 224 Net income attributable to common stockholders, basic 797 7,055 Less: warrant derivative gain - 225 Net income attributable to common stockholders, diluted $ 797 $ 6,830 Weighted-average number of common shares outstanding, basic 7,794 7,525 Add dilutive effects of non-vested shares of restricted stock and restricted performance units 301 314 Weighted-average number of common shares outstanding, diluted 8,095 7,839 Net income per common share, basic $ 0.10 $ 0.94 Net income per common share, diluted $ 0.10 $ 0.87

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of provision for income taxes	Year Ended December 31, (in thousands) 2019 2018 Current income tax benefit $ - $ - Deferred income tax expense (benefit) 895 (590 ) Change in valuation allowance (895 ) 590 Total income tax benefit $ - $ -
Schedule of effective income tax rate differed from the statutory U.S. federal income tax rate	Year Ended December 31, 2019 2018 Federal income tax rate 21.0 % 21.0 % State income taxes, net of federal benefit 4.9 4.9 Permanent differences (3.3 ) (1.2 ) Non-controlling interest in consolidated partnerships (46.2 ) (11.4 ) True-up of prior year depletion in excess of basis (6.5 ) 1.3 Stock-based compensation deficiency (16.0 ) 1.1 Purchase accounting adjustments (45.0 ) (22.9 ) Rate changes of prior year deferred 1.8 (0.5 ) True-up of prior year deferred - 3.0 Decrease in valuation allowance and other 89.3 4.7 Total effective income tax rate - % - %
Schedule of deferred tax assets and liabilities	(in thousands) As of December 31, 2019 2018 Deferred tax assets: Net operating loss carryforwards $ 6,232 $ 7,573 Depletion carryforwards 2,569 2,166 Accrual and other 3,997 1,372 Stock-based compensation 469 445 Asset retirement obligations 4,659 4,567 Property and equipment (2,253 ) (42 ) Total deferred tax assets 15,673 16,081 Deferred tax liabilities: Interest in partnerships (338 ) (512 ) ASC 842 Operating Leases (12 ) - Derivative and other (1,689 ) (1,008 ) Less valuation allowance (13,634 ) (14,561 ) Net deferred tax asset $ - $ -

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Schedule of financial assets and liabilities at fair value	Fair Value Measurements Using (in thousands) Level 1 Level 2 Level 3 Total December 31, 2019 Assets: Commodity derivatives $ - $ 7,079 $ - $ 7,079 Liabilities: Commodity derivatives $ - $ 556 $ - $ 556 December 31, 2018 Assets: Commodity derivatives $ - $ 7,022 $ - $ 7,022

Commodity Derivatives (Tables)

Commodity Derivatives (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of swap derivative agreements	Natural Gas Swaps Natural Gas Collars Weighted Weighted Year MMBtu Price (a) MMBtu Range (a) 2020 12,433,000 $ 2.73 3,430,000 $2.10 – $2.75 2021 6,448,000 $ 2.58 1,745,000 $2.25 – $2.75 Oil Swaps* Oil Collars* Year WTI Bbl Weighted Average Brent Bbl Weighted Average WTI Bbl Weighted Average Brent Bbl Weighted Average 2019 17,523 $53.30 13,805 $64.87 1,700 $47.50 - $57.35 4,500 $47.00 - $75.00 2020 121,147 $ 55.37 207,182 $ 64.62 28,200 $47.00 - $60.15 57,900 $47.00 - $75.00 2021 - $ - 86,341 $ 67.12 66,200 $47.00 - $60.15 190,000 $47.00 - $75.00 2022 - $ - - $ - - $ - 199,900 $50.00 - $61.00 * Includes 100% of Carbon California’s outstanding derivative hedges at December 31, 2019, and not our proportionate share. (a) NYMEX Henry Hub Natural Gas futures contracts for the respective period. (b) NYMEX Light Sweet Crude West Texas Intermediate futures contracts for the respective period. (c) Brent future contracts for the respective period.
Schedule of fair value of the derivatives recorded	As of December 31, (in thousands) 2019 2018 Commodity derivative contracts: Commodity derivative asset $ 5,915 $ 3,517 Commodity derivative asset – non-current $ 1,164 $ 3,505 Commodity derivative liability $ 469 $ - Commodity derivative liability – non-current $ 87 $ -
Schedule of realized and unrealized gains and losses	Year Ended (in thousands) 2019 2018 Commodity derivative contracts: Settlement gain (loss) $ 3,543 $ (3,848 ) Unrealized (loss) gain (499 ) 8,742 Total commodity derivative gain $ 3,044 $ 4,894
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 $ 6,917 $ (1,002 ) $ 5,915 Commodity derivative asset – non-current 3,478 (2,314 ) 1,164 Total derivative assets $ 10,395 $ (3,316 ) $ 7,079 Commodity derivative liabilities: Commodity derivative liability $ (1,471 ) $ 1,002 $ (469 ) Commodity derivative liability – non-current (2,401 ) 2,314 (87 ) Total derivative liabilities $ (3,872 ) $ 3,316 $ (556 )

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Schedule of firm transportation volumes and related demand charges	Period Dekatherms Demand Charges Jan 2020 – 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)	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Schedule of supplemental cash flow disclosures	Year Ended (in thousands) 2019 2018 Cash paid during the period for: Interest $ 9,191 $ 4,217 Non-cash transactions: Capital expenditures included in accounts payable and accrued liabilities $ (2,563 ) $ (206 ) Adjustments to OIE Membership Acquisition purchase price $ 1,505 -

Supplemental Financial Data -_2

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
Extractive Industries [Abstract]
Schedule of proved undeveloped and developed oil and gas reserves expected to be recovered from new wells	2019 2018 Oil Natural Gas NGL Total Oil Natural Gas NGL Total MBbls MMcf MBbls MMcfe MBbls MMcf MBbls MMcfe Proved reserves, beginning of year 18,898 455,400 1,923 580,326 919 81,702 - 87,216 Revisions of previous estimates (1,362 ) 24,194 (618 ) 12,310 (2,803 ) 1,832 (1,147 ) (21,868 ) Extensions and discoveries 826 1,187 77 6,605 - - - - Production (589 ) (21,436 ) (36 ) (25,182 ) (451 ) (4,798 ) (33 ) (7,702 ) Purchases of reserves in-place - - - - 21,233 376,664 3,103 522,680 Sales of reserves in-place (31 ) (8,980 ) - (9,166 ) - - - - Proved reserves, end of year 17,742 450,365 1,346 564,893 18,898 455,400 1,923 580,326 Proved developed reserves at: End of year 12,972 444,104 936 527,555 14,336 450,424 1,472 545,272 Proved undeveloped reserves at: End of year 4,770 6,261 410 37,338 4,562 4,976 451 35,054
Schedule of aggregate capitalized costs relating to oil and gas producing activities	(in thousands) 2019 2018 Oil and gas properties: Proved oil and gas properties $ 351,488 $ 347,059 Unproved properties 4,872 5,416 Accumulated depreciation, depletion, amortization and impairment (109,344 ) (98,604 ) Total $ 247,016 $ 253,871
Schedule of costs incurred in oil and gas property acquisition, exploration, and development activities	(in thousands) 2019 2018 Property acquisition costs: Unevaluated properties $ - $ 3,464 Proved properties and gathering facilities - 63,517 Development costs 7,676 2,074 Gathering facilities - 460 Asset retirement obligations - 14,085 Total $ 7,676 $ 83,600
Schedule of company's investment in unproved properties	(in thousands) 2019 2018 2017 and Prior Acquisition costs $ 496 $ 3,464 $ 912
Schedule of results of operations from oil and gas producing activities	(in thousands) 2019 2018 Revenues: Oil, gas and NGL sales, including commodity derivative gains and losses $ 96,885 $ 52,946 Expenses: Production expenses 41,307 22,226 Depletion expense 14,062 7,305 Accretion of asset retirement obligations 1,625 868 Total expenses 56,994 30,399 Results of operations from oil and gas producing activities $ 39,891 $ 22,547 Depletion rate per Mcfe $ 0.56 $ 0.89
Schedule of estimate of the current market value of the Company's proved reserves	December 31, (in thousands) 2019 2018 Future cash inflows $ 2,212,049 $ 2,878,392 Future production costs (1,306,608 ) (1,538,870 ) Future development costs (77,952 ) (76,852 ) Future income taxes (146,951 ) (258,277 ) Future net cash flows 680,538 1,004,393 10% annual discount (408,690 ) (612,325 ) Standardized measure of discounted future net cash flows $ 271,848 $ 392,068
Schedule of discounted future cash flows relating to proved oil and gas reserves	December 31, (in thousands) 2019 2018 Standardized measure of discounted future net cash flows, beginning of period $ 392,068 $ 57,082 Sales of oil and gas, net of production costs and taxes (49,746 ) (25,681 ) Price revisions (158,799 ) 133,789 Extensions, discoveries and improved recovery, less related costs 10,822 - Changes in estimated future development costs (3,041 ) (32,711 ) Development costs incurred during the period 6,685 926 Quantity revisions 5,565 (23,484 ) Accretion of discount 39,207 5,708 Net changes in future income taxes 39,929 (89,117 ) Purchases of reserves-in-place - 391,877 Sales of reserves-in-place (4,004 ) - Changes in production rate timing and other (6,838 ) (26,321 ) Standardized measure of discounted future net cash flows, end of period $ 271,848 $ 392,068
Schedule of weighted averaged adjusted prices	2019 2018 Oil (per Bbl) $ 55.69 $ 65.56 Natural Gas (per Mcf) $ 2.58 $ 3.10

Organization (Details)

Organization (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	May 01, 2018	Feb. 01, 2018	Jan. 31, 2018
Carbon California [Member]
Ownership percentage		53.92%	56.40%	17.81%
OIE Membership Acquisition [Member]
Business acquisition purchase price	$ 58,200
Prudential [Member] | Carbon California [Member]
Ownership percentage		46.08%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2019		Dec. 31, 2018
Purchaser A [Member]
Concentration Risk [Line Items]
Sales as percentage of revenue	18.00%			[1]
Purchaser B [Member]
Concentration Risk [Line Items]
Sales as percentage of revenue	11.00%			[1]
Purchaser C [Member]
Concentration Risk [Line Items]
Sales as percentage of revenue		[1]	17.00%
Purchaser D [Member]
Concentration Risk [Line Items]
Sales as percentage of revenue		[1]	16.00%
Purchaser E [Member]
Concentration Risk [Line Items]
Sales as percentage of revenue		[1]	12.00%
[1]	less than 10%

Summary of Significant Accoun_5

Summary of Significant Accounting Policies (Details Textual) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)Partnerships	Dec. 31, 2018USD ($)
Accounting Policies [Abstract]
Insurance settlement received	$ 800
Number of consolidated partnerships | Partnerships	46
Purchaser imbalance receivable	$ 956	$ 551
Discount factor used in ceiling test	10.00%
Accounts Receivable [Member]
Accounting Policies [Abstract]
Concentraction risk threshold percentage	10.00%
Sales Revenue Net [Member]
Accounting Policies [Abstract]
Concentraction risk threshold percentage	10.00%	10.00%
Minimum [Member]
Accounting Policies [Abstract]
Payment received for product sales, period	30 days
Maximum [Member]
Accounting Policies [Abstract]
Payment received for product sales, period	90 days
Office Furniture [Member] | Minimum [Member]
Accounting Policies [Abstract]
Estimated useful lives of the assets	3 years
Office Furniture [Member] | Maximum [Member]
Accounting Policies [Abstract]
Estimated useful lives of the assets	5 years
Automobiles [Member] | Minimum [Member]
Accounting Policies [Abstract]
Estimated useful lives of the assets	3 years
Automobiles [Member] | Maximum [Member]
Accounting Policies [Abstract]
Estimated useful lives of the assets	5 years
Computer Hardware [Member] | Minimum [Member]
Accounting Policies [Abstract]
Estimated useful lives of the assets	3 years
Computer Hardware [Member] | Maximum [Member]
Accounting Policies [Abstract]
Estimated useful lives of the assets	5 years
Computer Software [Member] | Minimum [Member]
Accounting Policies [Abstract]
Estimated useful lives of the assets	3 years
Computer Software [Member] | Maximum [Member]
Accounting Policies [Abstract]
Estimated useful lives of the assets	5 years
Buildings [Member]
Accounting Policies [Abstract]
Estimated useful lives of the assets	27 years 6 months
Pipeline Facilities and Equipment [Member]
Accounting Policies [Abstract]
Estimated useful lives of the assets	20 years

Acquisitions (Details)

Acquisitions (Details) - Old Ironsides [Member] $ in Thousands	1 Months Ended
	Dec. 31, 2018USD ($)
Business Acquisition [Line Items]
Cash consideration	$ 33,000
Old Ironsides Notes	25,194
Fair value of previously held equity interest	14,029
Fair value of business acquired	$ 72,223

Acquisitions (Details 1)

Acquisitions (Details 1) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Oil and gas properties:
Commodity derivative liability - current	$ 469
Commodity derivative liability - non-current	87
Asset retirement obligations - non-current	$ (17,514)	(19,211)
Carbon California [Member]
Business Acquisition [Line Items]
Cash		275
Accounts receivable:
Prepaid expenses, deposits, and other current assets		1,723
Joint interest billings and other		690
Receivable - related party		1,610
Oil and gas properties:
Proved		65,114
Unproved		1,495
Other property and equipment, net		877
Other non-current assets		475
Accounts payable and accrued liabilities		(6,054)
Commodity derivative liability - current		(916)
Commodity derivative liability - non-current		(1,729)
Asset retirement obligations - current		(384)
Asset retirement obligations - non-current		(2,537)
Subordinated Notes, related party, net		(8,874)
Senior Revolving Notes, related party		(11,000)
Notes payable		(92)
Total net assets acquired		40,673
OIE Membership Acquisition [Member]
Business Acquisition [Line Items]
Cash		12,283
Accounts receivable:
Revenue		12,834
Trade receivable		1,941
Commodity derivative asset		198
Inventory		2,022
Prepaid expenses, deposits, and other current assets		456
Oil and gas properties:
Proved		107,694
Unproved		1,869
Other property and equipment, net		15,441
Other non-current assets		514
Accounts payable and accrued liabilities		(20,468)
Due to related parties		(236)
Firm transportation contract obligations		(18,724)
Asset retirement obligations - current		(5,626)
Notes payable		(37,975)
Total net assets acquired		$ 72,223

Acquisitions (Details 2)

Acquisitions (Details 2) - OIE Membership Acquisition [Member] $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)$ / shares
Business Acquisition [Line Items]
Revenue	$ 136,592
Net income before non-controlling interests	11,320
Net loss attributable to non-controlling interests	4,375
Net income attributable to controlling interests	$ 5,596
Net income per share (basic) | $ / shares	$ 0.74
Net income per share (diluted) | $ / shares	$ 0.69
Carbon California [Member]
Business Acquisition [Line Items]
Revenue	$ 33,256
Net income before non-controlling interests	5,232
Net loss attributable to non-controlling interests	(2,334)
Net income attributable to controlling interests	$ 7,566
Net income per share (basic) | $ / shares	$ 1
Net income per share (diluted) | $ / shares	$ 0.96

Acquisitions (Details 3)

Acquisitions (Details 3) - Carbon California [Member] $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)
Fair value of Carbon common shares transferred as consideration	$ 8,327
Fair value of non-controlling interest	16,466
Fair value of previously held interest	7,243
Fair value of contribution associated with acquisition of Yorktown's interest in Carbon California	8,637
Fair value of business acquired	$ 40,673

Acquisitions (Details Textual)

Acquisitions (Details Textual) $ / shares in Units, $ in Thousands	Jul. 11, 2018USD ($)awells	Feb. 01, 2018USD ($)$ / sharesshares	May 01, 2018USD ($)awellsshares	Dec. 31, 2018USD ($)	Dec. 31, 2018USD ($)
Class A Units [Member] | Old Ironsides [Member]
Business Acquisition [Line Items]
Aggregate share ownership prior to acquisition				72.76%	72.76%
Class A Units [Member] | Carbon Appalachia [Member]
Business Acquisition [Line Items]
Cash paid to acquired business					$ 33,000
Business acquisition, purchase price					58,200
Debt issued for acquired business					25,200
Seneca Acquisition [Member]
Business Acquisition [Line Items]
Cash paid to acquired business			$ 5,000
Business acquisition, purchase price			43,000
Debt issued for acquired business			$ 3,000
Number of oil wells acquired | wells			309
Number of acres land acquired gross | a			6,800
Number of acres land acquired net | a			6,600
Issuance shares of preferred stock | shares			50,000
Liberty Acquisition [Member]
Business Acquisition [Line Items]
Business acquisition, purchase price	$ 3,000
Number of oil wells acquired | wells	54
Number of acres land acquired gross | a	55,000
Number of acres land acquired net | a	22,000
Working interest percentage prior to acquisition	60.00%
Working interest ownership after acquisition	100.00%
Carbon California [Member]
Business Acquisition [Line Items]
Gain on derecognized equity investment					5,400
Percentage of acquisition		100.00%
Ownership prior to acquisition		38.59%
Fair value of consideration				$ 8,600
Exchanged common shares | shares		1,527,778
Exchanged common shares value		$ 8,300
Exchanged common shares per share | $ / shares		$ 5.45
Carbon California [Member] | Class A Units [Member]
Business Acquisition [Line Items]
Exchanged common shares | shares		11,000
Carbon Appalachia [Member]
Business Acquisition [Line Items]
Gain on derecognized equity investment					$ 1,300

Property and Equipment, Net (De

Property and Equipment, Net (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Oil and gas properties:
Proved oil and gas properties	$ 351,488	$ 347,059
Unproved properties	4,872	5,416
Accumulated depreciation, depletion, amortization and impairment	(109,344)	(98,604)
Oil and gas properties, net	247,016	253,871
Pipeline facilities and equipment	12,814	12,714
Base gas	1,937	2,122
Furniture and fixtures, computer hardware and software, and other equipment	6,762	6,649
Accumulated depreciation and amortization	(5,529)	(3,922)
Other property and equipment, net	15,984	17,563
Total property and equipment, net	$ 263,000	$ 271,434

Property and Equipment, Net (_2

Property and Equipment, Net (Details 1) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative [Abstract]
Total unproved properties	$ 4,872	$ 5,416
Ventura Basin [Member] | California [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative [Abstract]
Total unproved properties	1,602	1,595
Illinois Basin [Member] | Indiana [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative [Abstract]
Total unproved properties	432	432
Illinois Basin [Member] | Illinois [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative [Abstract]
Total unproved properties	136	136
Appalachian Basin [Member] | Kentucky [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative [Abstract]
Total unproved properties	461	920
Appalachian Basin [Member] | Ohio [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative [Abstract]
Total unproved properties	66	66
Appalachian Basin [Member] | Tennessee [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative [Abstract]
Total unproved properties	1,869	1,869
Appalachian Basin [Member] | West Virginia [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative [Abstract]
Total unproved properties	$ 306	$ 398

Property and Equipment, Net (_3

Property and Equipment, Net (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Capitalized overhead	$ 790	$ 337
Depletion expense related to oil and gas properties	14,100	$ 7,300
Leasehold costs reclassified into proved property	$ 1,000

Accounts Payable and Accrued _3

Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Payables and Accruals [Abstract]
Accounts payable	$ 9,875	$ 7,670
Oil and gas revenue suspense	3,620	2,675
Gathering and transportation payables	1,877	1,774
Production taxes payable	3,212	1,860
Accrued lease operating costs	664	3,155
Accrued ad valorem taxes-current	4,407	3,474
Accrued general and administrative expenses	3,260	3,111
Asset retirement obligations-current	5,021	3,099
Accrued interest	1,335	955
Accrued gas purchases	1,392	5,441
Other liabilities	494	1,602
Total accounts payable and accrued liabilities	$ 35,157	$ 34,816

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation [Abstract]
Balance at beginning of year	$ 22,310	$ 7,357
Accretion expense	1,625	868
Additions and revisions	294
Obligations discharged with divestitures	(1,694)
Change in estimate of cash outflow		361
Additions from Carbon California (Note 3)		2,921
Additions from Seneca Acquisition (Note 3)		5,132
Additions from Liberty Acquisition (Note 3)		45
Additions from OIE Membership Acquisition		5,626
Balance at end of year	22,535	22,310
Less: Current portion	(5,021)	(3,099)
Non-current portion	$ 17,514	$ 19,211

Credit Facilities and Notes P_3

Credit Facilities and Notes Payable (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
2018 Credit Facility - revolver [Member]
Debt Instrument [Line Items]
Total debt	$ 69,150	$ 69,150
2018 Credit Facility - term note [Member]
Debt Instrument [Line Items]
Total debt	5,833	15,000
Old Ironsides Notes [Member]
Debt Instrument [Line Items]
Total debt	25,675	25,065
Other Debt [Member]
Debt Instrument [Line Items]
Total debt	45	57
Credit Facilities [Member]
Debt Instrument [Line Items]
Total debt	100,703	109,272
Less: unamortized debt discount	(45)	(134)
Total credit facilities and notes payable	100,658	109,138
Current portion of credit facilities and notes payable	(5,788)	(11,910)
Non-current debt, net of current portion and unamortized debt discount	$ 94,870	$ 97,228

Credit Facilities and Notes P_4

Credit Facilities and Notes Payable (Details 1) - Prudential [Member] - Carbon California [Member] - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Total principal	$ 46,000	$ 51,500
Less: Deferred notes costs	(175)	(235)
Less: unamortized debt discount	(1,084)	(1,346)
Total notes payable - related party	44,741	49,919
Senior Revolving Notes [Member]
Debt Instrument [Line Items]
Total principal	33,000	38,500
Subordinated Notes [Member]
Debt Instrument [Line Items]
Total principal	$ 13,000	$ 13,000

Credit Facilities and Notes P_5

Credit Facilities and Notes Payable (Details Textual) - USD ($) $ in Thousands	Oct. 01, 2019	Feb. 01, 2019	Dec. 31, 2019	Dec. 31, 2018	May 01, 2020	Feb. 29, 2020
Credit Facilities and Notes Payable (Textual)
Senior secured asset-based revolving credit facility			$ 7,000	$ 118,628
Amortization of deferred issuance costs			846	966
Paid in kind interest			2,481
One-time principal reduction payment			$ 23,708	$ 64,150
Line Of Credit [Member] | Minimum [Member]
Credit Facilities and Notes Payable (Textual)
Funded debt ratio required to be maintained			1
Debt Instrument, covenant, current ratio			1
Old Ironsides Notes [Member] | Carbon Appalachia [Member]
Credit Facilities and Notes Payable (Textual)
Bank credit facility, terms				5 years
Amount of unsecured notes issuance				$ 25,200
Interest rate (as a percent)				10.00%
Number of monthly installments			24
One-time principal reduction payment		$ 2,000
Old Ironsides Notes [Member] | Carbon Appalachia [Member] | Payment in Kind (PIK) Note [Member]
Credit Facilities and Notes Payable (Textual)
Interest rate (as a percent)			12.00%
Paid in kind interest			$ 2,500
2018 Credit Facility [Member] | Carbon Appalachia [Member]
Credit Facilities and Notes Payable (Textual)
Unamortized deferred issuance costs			519
Unamortized debt discount, term note			45
Senior secured asset-based revolving credit facility			$ 500,000
Commitment fee (as a percent)			0.50%
Origination fee (as a percent)			0.50%
Credit facility			$ 75,000
Additional borrowing capacity available			$ 5,000
Debt Instrument, covenant, ratio of debt to EBITDAX			3.5
Debt Instrument, covenant, current ratio			1
Credit facility-revolver outstanding			$ 69,200
Debt instrument, covenant, minimum liquidity	$ 3,000
Debt instrument, covenant, minimum liquidity, term	90 days
Amortization of deferred issuance costs			$ 260	$ 786
Revolving credit facility maturing date			Dec. 31, 2022
Cash and cash equivalents of borrowers not to exceed			$ 3,000
Debt issuance costs paid, revolver and term loan			824
Debt issuance costs paid, term loan			134
Term loan			15,000
Sublimit for letters of credit			$ 1,500
Interest rate (as a percent)			6.25%
Number of monthly installments			18
2018 Credit Facility [Member] | Carbon Appalachia [Member] | Subsequent Event [Member]
Credit Facilities and Notes Payable (Textual)
Credit facility						$ 73,000
Total future borrowing base reductions					$ 6,000
2018 Credit Facility [Member] | Carbon Appalachia [Member] | Minimum [Member] | Base rate [Member]
Credit Facilities and Notes Payable (Textual)
Spread on variable base rate (as a percent)			0.25%
2018 Credit Facility [Member] | Carbon Appalachia [Member] | Minimum [Member] | London interbank offered rate [Member]
Credit Facilities and Notes Payable (Textual)
Spread on variable base rate (as a percent)			2.75%
2018 Credit Facility [Member] | Carbon Appalachia [Member] | Maximum [Member] | Base rate [Member]
Credit Facilities and Notes Payable (Textual)
Spread on variable base rate (as a percent)			0.75%
2018 Credit Facility [Member] | Carbon Appalachia [Member] | Maximum [Member] | London interbank offered rate [Member]
Credit Facilities and Notes Payable (Textual)
Spread on variable base rate (as a percent)			3.75%

Credit Facilities and Notes P_6

Credit Facilities and Notes Payable (Details Textual 1) - USD ($) $ in Thousands	May 01, 2018	Feb. 15, 2017	Dec. 31, 2019	Dec. 31, 2018
Credit Facilities and Notes Payable (Textual)
Amortization of deferred issuance costs			$ 846	$ 966
Carbon California [Member]
Credit Facilities and Notes Payable (Textual)
Business acquisitions, description		The sale and issuance by Carbon California of Senior Revolving Notes in the principal amount of $10.0 million.
Prudential [Member] | Carbon California [Member] | Senior Revolving Notes [Member]
Credit Facilities and Notes Payable (Textual)
Initial revolving borrowing capacity		$ 25,000
Notes maturity date		Feb. 15, 2022
Principal outstanding			10,000
Borrowing base amount			45,000
Outstanding borrowings			$ 33,000
Effective borrowing rate			7.10%
Commitment fee (as a percent)		0.50%
Annual administrative fee payable		$ 75
Percentage of production hedged by commodity derivatives, year one		75.00%
Percentage of production hedged by commodity derivatives, year two		65.00%
Percentage of production hedged by commodity derivatives, year three		50.00%
Principal payments in minimum installments		$ 500
Current portion of fees			$ 599
Amortization of deferred issuance costs			$ 273	217
Debt instrument, covenant, debt to EBITDA ratio		4.5
Debt instrument, covenant, senior revolving notes to EBITDA ratio		3.5
Debt instrument, covenant, interest coverage ratio		2
Debt instrument, covenant, current ratio		1
Ownership percentage			46.08%
Prudential [Member] | Carbon California [Member] | Senior Revolving Notes [Member] | LIBOR [Member]
Credit Facilities and Notes Payable (Textual)
Effective borrowing rate		5.50%
Prudential [Member] | Carbon California [Member] | Senior Revolving Notes [Member] | Prime Rate [Member]
Credit Facilities and Notes Payable (Textual)
Effective borrowing rate		4.50%
Prudential [Member] | Carbon California [Member] | Subordinated Notes [Member]
Credit Facilities and Notes Payable (Textual)
Notes maturity date		Feb. 15, 2024
Principal outstanding			$ 10,000
Percentage of production hedged by commodity derivatives, year one		67.50%
Percentage of production hedged by commodity derivatives, year two		58.50%
Percentage of production hedged by commodity derivatives, year three		45.00%
Amortization of debt discount			178	58
Interest rate (as a percent)		12.00%
Number of common units issued		1,425
Increase in sharing percentage by noncontroling interest		5.00%
Fair value per Class A unit		$ 1,000
Fair value of debt discount		1,300
Outstanding discount amount of notes			735
Proceeds from debt		$ 30,000
Principal prepayment allowed (as a percent)		100.00%
Prepayment fee (as a percent)		3.00%
Debt instrument, covenant, debt to EBITDA ratio		5.18
Debt instrument, covenant, senior revolving notes to EBITDA ratio		4.03
Debt instrument, covenant, interest coverage ratio		1.6
Debt instrument, covenant, current ratio		0.85
Percentage of adjusted PV-10 not to exceed indebtedness		0.65%
Prudential [Member] | Carbon California [Member] | 2018 Subordinated Notes [Member]
Credit Facilities and Notes Payable (Textual)
Notes maturity date	Feb. 15, 2024
Principal outstanding			3,000
Percentage of production hedged by commodity derivatives, year one	67.50%
Percentage of production hedged by commodity derivatives, year two	58.50%
Percentage of production hedged by commodity derivatives, year three	45.00%
Amortization of debt discount			84	$ 57
Interest rate (as a percent)	12.00%
Number of common units issued	585
Increase in sharing percentage by noncontroling interest	2.00%
Fair value per Class A unit	$ 1,000
Fair value of debt discount	490
Outstanding discount amount of notes			$ 349
Proceeds from debt	$ 3,000
Principal prepayment allowed (as a percent)	100.00%
Prepayment fee (as a percent)	3.00%

Leases (Details)

Leases (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Operating Leased Assets [Line Items]
Right-of-Use Assets	$ 6,104
Lease Liability	6,008
Compressors [Member]
Operating Leased Assets [Line Items]
Right-of-Use Assets	3,282
Lease Liability	3,282
Corporate leases [Member]
Operating Leased Assets [Line Items]
Right-of-Use Assets	2,065
Lease Liability	2,083
Vehicles [Member]
Operating Leased Assets [Line Items]
Right-of-Use Assets	757
Lease Liability	$ 643

Leases (Details 1)

Leases (Details 1) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Operating lease cost	$ 2,116
Short-term lease cost	629
Total lease cost	$ 2,745

Leases (Details 2)

Leases (Details 2)	Dec. 31, 2019
Leases [Abstract]
Weighted-average lease term (years)	3 years 7 months 2 days
Weighted-average discount rate	6.40%

Leases (Details 3)

Leases (Details 3) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Cash paid for amounts included in measurement of lease liabilities:
Cash paid for operating leases	$ 2,212
Right-of-use assets obtained in exchange for operating lease obligations	$ 465

Leases (Details 4)

Leases (Details 4) $ in Thousands	Dec. 31, 2019USD ($)
Leases [Abstract]
2020	$ 1,960
2021	1,902
2022	1,704
2023	1,157
2024	11
Thereafter
Total future minimum lease payments	6,734
Less: imputed interest	(726)
Total lease liabilities	$ 6,008

Leases (Details Textual)

Leases (Details Textual) - USD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right-of-use lease liabilities	$ 6,008
Right-of-use assets and liabilities discounted present value	$ 6,104
Accounting Standards Update 2016-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right-of-use lease liabilities		$ 7,700
Right-of-use assets and liabilities discounted present value		$ 7,700

Revenue (Details)

Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Total [Member]
Disaggregation of Revenue [Line Items]
Total	$ 112,689	$ 48,052
Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Total	56,468	16,018
Natural gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Total	578	1,143
Oil sales [Member]
Disaggregation of Revenue [Line Items]
Total	36,795	30,891
Transportation and handling [Member]
Disaggregation of Revenue [Line Items]
Total	1,928
Marketing gas sales [Member]
Disaggregation of Revenue [Line Items]
Total	16,920
Appalachian and Illinois Basins [Member]
Disaggregation of Revenue [Line Items]
Total	79,932	19,731
Appalachian and Illinois Basins [Member] | Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Total	55,279	14,768
Appalachian and Illinois Basins [Member] | Natural gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Total
Appalachian and Illinois Basins [Member] | Oil sales [Member]
Disaggregation of Revenue [Line Items]
Total	5,805	4,963
Appalachian and Illinois Basins [Member] | Transportation and handling [Member]
Disaggregation of Revenue [Line Items]
Total	1,928
Appalachian and Illinois Basins [Member] | Marketing gas sales [Member]
Disaggregation of Revenue [Line Items]
Total	16,920
Ventura Basin [Member]
Disaggregation of Revenue [Line Items]
Total	32,757	28,321
Ventura Basin [Member] | Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Total	1,189	1,250
Ventura Basin [Member] | Natural gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Total	578	1,143
Ventura Basin [Member] | Oil sales [Member]
Disaggregation of Revenue [Line Items]
Total	30,990	25,928
Ventura Basin [Member] | Transportation and handling [Member]
Disaggregation of Revenue [Line Items]
Total
Ventura Basin [Member] | Marketing gas sales [Member]
Disaggregation of Revenue [Line Items]
Total

Stock-Based Compensation Plan_3

Stock-Based Compensation Plans and Employee Benefit Plans (Details) - Restricted Stock [Member] - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Number of Shares, unvested, Beginning Balance	314,207	269,997
Number of Shares, Granted	99,000	106,000
Number of Shares, Vested	(105,628)	(59,550)
Number of Shares, Forfeited	(6,682)	(2,240)
Number of Shares, unvested, Ending Balance	300,897	314,207
Weighted Average Grant Date Fair Value, unvested, Beginning Balance	$ 8.40	$ 7.54
Weighted Average Grant Date Fair Value, Granted	10	9.80
Weighted Average Grant Date Fair Value, Vested	6.75	6.82
Weighted Average Grant Date Fair Value, Forfeited	9.74	7.41
Weighted Average Grant Date Fair Value, unvested, Ending Balance	$ 9.41	$ 8.40

Stock-Based Compensation Plan_4

Stock-Based Compensation Plans and Employee Benefit Plans (Details 1) - Restricted Performance Units [Member] - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Number of Shares, unvested, Beginning Balance	279,876	258,811
Number of Shares, Granted	101,864	136,159
Number of Shares, Vested	(95,451)	(108,484)
Number of Shares, Forfeited	(11,084)	(6,610)
Number of Shares, unvested, Ending Balance	275,205	279,876

Stock-Based Compensation Plan_5

Stock-Based Compensation Plans and Employee Benefit Plans (Details Textual) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Arrangements with Employees and Nonemployees [Abstract]
Shares authorized	1,600,000
Employer matching contribution	6.00%
Contributions and related administrative expenses	$ 527	$ 441
Restricted Stock [Member]
Share-based Arrangements with Employees and Nonemployees [Abstract]
Compensation costs	811	725
Unrecognized compensation costs	$ 1,500
Compensation recognized period	6 years 3 months 19 days
Restricted Performance Units [Member]
Share-based Arrangements with Employees and Nonemployees [Abstract]
Compensation costs	$ 637	$ 408
Fair value of performance units at date of grant	$ 10	$ 9.80	$ 7.20
Unrecognized compensation costs	$ 3,200

Earnings (Loss) Per Common Sh_3

Earnings (Loss) Per Common Share (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Earnings Per Share [Abstract]
Net income attributable to controlling interests before preferred shares	$ 1,097	$ 8,404
Less: beneficial conversion feature		1,125
Less: net income attributable to preferred shares - preferred return	300	224
Net income attributable to common stockholders, basic	797	7,055
Less: warrant derivative gain		(225)
Net income attributable to common stockholders, diluted	$ 797	$ 6,830
Weighted-average number of common shares outstanding, basic	7,794	7,525
Add dilutive effects of non-vested shares of restricted stock and restricted performance units	301	314
Weighted-average number of common shares outstanding, diluted	8,095	7,839
Net income per common share, basic	$ 0.10	$ 0.94
Net income per common share, diluted	$ 0.10	$ 0.87

Earnings (Loss) Per Common Sh_4

Earnings (Loss) Per Common Share (Details Textual) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Issuance of preferred stock, value	$ 1	$ 1
Issuance of preferred stock, shares	50,000	50,000
Preferred return	$ 524	$ 224
Additional paid-in capital
Anti-dilutive shares excluded from computation of diluted earnings per share	275,000	280,000
Series B Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Issue price, per share	$ 0.01
Series B Convertible Preferred Stock [Member] | Yorktown [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Issuance of preferred stock, value	$ 5,000
Issuance of preferred stock, shares	50,000
Conversion price, per share	$ 8
Annual per share dividend rate	6.00%
Issue price, per share	$ 100
Preferred return	$ 524	$ 224
Convertible preferred stock shares issued upon conversion	12.5
Preferred stock, conversion ratio, stock price trigger	15.00%

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Current income tax benefit
Deferred income tax expense (benefit)	895	(590)
Change in valuation allowance	(895)	590
Total income tax benefit

Income Taxes (Details 1)

Income Taxes (Details 1)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Summary of effective income tax rate differed from the statutory U.S. federal income tax rate
Federal income tax rate	21.00%	21.00%
State income taxes, net of federal benefit	4.90%	4.90%
Permanent differences	(3.30%)	(1.20%)
Non-controlling interest in consolidated partnerships	(46.20%)	(11.40%)
True-up of prior year depletion in excess of basis	(6.50%)	1.30%
Stock-based compensation deficiency	(16.00%)	1.10%
Purchase accounting adjustments	(45.00%)	(22.90%)
Rate changes of prior year deferred	1.80%	(0.50%)
True-up of prior year deferred		3.00%
Decrease in valuation allowance and other	89.30%	4.70%
Total effective income tax rate	0.00%	0.00%

Income Taxes (Details 2)

Income Taxes (Details 2) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred tax assets
Net operating loss carryforwards	$ 6,232	$ 7,573
Depletion carryforwards	2,569	2,166
Accrual and other	3,997	1,372
Stock-based compensation	469	445
Asset retirement obligations	4,659	4,567
Property and equipment	(2,253)	(42)
Total deferred tax assets	15,673	16,081
Deferred tax liabilities:
Interest in partnerships	(338)	(512)
ASC 842 Operating Leases	(12)
Derivative and other	(1,689)	(1,008)
Less valuation allowance	(13,634)	(14,561)
Net deferred tax asset

Income Taxes (Details Textual)

Income Taxes (Details Textual) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Income Taxes (Textual)
Net operating losses	$ 21,600
NOL carryforwards expire, description	The federal net operating losses expire beginning in 2031 through 2037, while the current 2018 and 2019 net operating losses will never expire. The Company has various state NOL carryforwards available to reduce future years' state taxable income, which are dependent on apportionment percentages and state laws that can change from year to year and impact the amount of such carryforwards. These state NOL will expire beginning in 2023 through 2039 depending upon each jurisdiction’s specific law surrounding NOL carryforwards. Tax returns are subject to audit by various taxation authorities.

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Fair Value Measurements [Member] - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Assets:
Commodity derivatives	$ 7,079	$ 7,022
Liabilities:
Commodity derivatives	556
Level 1 [Member]
Assets:
Commodity derivatives
Liabilities:
Commodity derivatives
Level 2 [Member]
Assets:
Commodity derivatives	7,079	7,022
Liabilities:
Commodity derivatives	556
Level 3 [Member]
Assets:
Commodity derivatives
Liabilities:
Commodity derivatives

Fair Value Measurements (Deta_2

Fair Value Measurements (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Additions to asset retirement obligations	$ 294
Revisions to asset retirement obligations		361
Fair Value, Inputs, Level 3 [Member] | Non-Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Additions to asset retirement obligations		$ 14,100
Revisions to asset retirement obligations	290,000
Fair Value, Inputs, Level 3 [Member] | Non-Recurring [Member] | Minimum [Member] | Abandonment Costs Member [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset retirement obligation liability	$ 20
Fair Value, Inputs, Level 3 [Member] | Non-Recurring [Member] | Minimum [Member] | Inflation rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset retirement obligation, measurement input rate	1.52%
Fair Value, Inputs, Level 3 [Member] | Non-Recurring [Member] | Minimum [Member] | Risk-free rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset retirement obligation, measurement input rate	3.28%
Fair Value, Inputs, Level 3 [Member] | Non-Recurring [Member] | Minimum [Member] | Reclamation Period [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Estimated timing of reclamation range (in years)	1 year
Fair Value, Inputs, Level 3 [Member] | Non-Recurring [Member] | Maximum [Member] | Abandonment Costs Member [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset retirement obligation liability	$ 45
Fair Value, Inputs, Level 3 [Member] | Non-Recurring [Member] | Maximum [Member] | Inflation rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset retirement obligation, measurement input rate	2.79%
Fair Value, Inputs, Level 3 [Member] | Non-Recurring [Member] | Maximum [Member] | Risk-free rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset retirement obligation, measurement input rate	8.27%
Fair Value, Inputs, Level 3 [Member] | Non-Recurring [Member] | Maximum [Member] | Reclamation Period [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Estimated timing of reclamation range (in years)	75 years
Class A Units [Member] | Subordinated Notes [Member] | Fair Value, Inputs, Level 3 [Member] | Non-Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Number of common units issued	1,425
Fair value of debt discount	$ 1,300
Fair value per Class A unit	$ 1,000
Class A Units [Member] | 2018 Subordinated Notes [Member] | Fair Value, Inputs, Level 3 [Member] | Non-Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Number of common units issued	585
Fair value of debt discount	$ 490

Commodity Derivatives (Details)

Commodity Derivatives (Details) - Carbon California [Member]	12 Months Ended
	Dec. 31, 2019bblMMBTU$ / MMBTU$ / Bbl
2019 [Member] | Oil Swaps [Member] | WTI Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	17,523	[1]
Weighted Average Price | $ / bbl	53.30	[1],[2]
2019 [Member] | Oil Swaps [Member] | Brent Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	13,805	[1]
Weighted Average Price | $ / bbl	64.87	[1]
2019 [Member] | Oil Collars [Member] | WTI Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	1,700	[1]
2019 [Member] | Oil Collars [Member] | WTI Bbl [Member] | Minimum [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	47.50	[1],[2]
2019 [Member] | Oil Collars [Member] | WTI Bbl [Member] | Maximum [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	57.35	[1],[2]
2019 [Member] | Oil Collars [Member] | Brent Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	4,500	[1]
2019 [Member] | Oil Collars [Member] | Brent Bbl [Member] | Minimum [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	47	[1],[3]
2019 [Member] | Oil Collars [Member] | Brent Bbl [Member] | Maximum [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	75	[1],[3]
2020 [Member] | Natural Gas Swaps [Member] | MMBtu [Member]
Derivative agreements details:
Crude oil, notional amount (in MMBtu) | MMBTU	12,433,000
Weighted Average Price | $ / MMBTU	2.73	[4]
2020 [Member] | Natural Gas Collars [Member] | MMBtu [Member]
Derivative agreements details:
Crude oil, notional amount (in MMBtu) | MMBTU	3,430,000
2020 [Member] | Natural Gas Collars [Member] | MMBtu [Member] | Minimum [Member]
Derivative agreements details:
Weighted Average Price | $ / MMBTU	2.10	[4]
2020 [Member] | Natural Gas Collars [Member] | MMBtu [Member] | Maximum [Member]
Derivative agreements details:
Weighted Average Price | $ / MMBTU	2.75	[4]
2020 [Member] | Oil Swaps [Member] | WTI Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	121,147	[1]
Weighted Average Price | $ / bbl	55.37	[1],[2]
2020 [Member] | Oil Swaps [Member] | Brent Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	207,182	[1]
Weighted Average Price | $ / bbl	64.62	[1],[3]
2020 [Member] | Oil Collars [Member] | WTI Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	28,200	[1]
2020 [Member] | Oil Collars [Member] | WTI Bbl [Member] | Minimum [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	47	[1],[2]
2020 [Member] | Oil Collars [Member] | WTI Bbl [Member] | Maximum [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	60.15	[1],[2]
2020 [Member] | Oil Collars [Member] | Brent Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	57,900	[1]
2020 [Member] | Oil Collars [Member] | Brent Bbl [Member] | Minimum [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	47	[1],[3]
2020 [Member] | Oil Collars [Member] | Brent Bbl [Member] | Maximum [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	75	[1],[3]
2021 [Member] | Natural Gas Swaps [Member] | MMBtu [Member]
Derivative agreements details:
Crude oil, notional amount (in MMBtu) | MMBTU	6,448,000
Weighted Average Price | $ / MMBTU	2.58	[4]
2021 [Member] | Natural Gas Collars [Member] | MMBtu [Member]
Derivative agreements details:
Crude oil, notional amount (in MMBtu) | MMBTU	1,745,000
2021 [Member] | Natural Gas Collars [Member] | MMBtu [Member] | Minimum [Member]
Derivative agreements details:
Weighted Average Price | $ / MMBTU	2.25	[4]
2021 [Member] | Natural Gas Collars [Member] | MMBtu [Member] | Maximum [Member]
Derivative agreements details:
Weighted Average Price | $ / MMBTU	2.75	[4]
2021 [Member] | Oil Swaps [Member] | WTI Bbl [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl		[1],[2]
2021 [Member] | Oil Swaps [Member] | Brent Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	86,341	[1]
Weighted Average Price | $ / bbl	67.12	[1],[3]
2021 [Member] | Oil Collars [Member] | WTI Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	66,200	[1]
2021 [Member] | Oil Collars [Member] | WTI Bbl [Member] | Minimum [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	47	[1],[2]
2021 [Member] | Oil Collars [Member] | WTI Bbl [Member] | Maximum [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	60.15	[1],[2]
2021 [Member] | Oil Collars [Member] | Brent Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	190,000	[1]
2021 [Member] | Oil Collars [Member] | Brent Bbl [Member] | Minimum [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	47	[1],[3]
2021 [Member] | Oil Collars [Member] | Brent Bbl [Member] | Maximum [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	75	[1],[3]
2022 [Member] | Oil Swaps [Member] | WTI Bbl [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl		[1],[2]
2022 [Member] | Oil Swaps [Member] | Brent Bbl [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl		[1],[3]
2022 [Member] | Oil Collars [Member] | WTI Bbl [Member] | Minimum [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl		[1],[2]
2022 [Member] | Oil Collars [Member] | WTI Bbl [Member] | Maximum [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl		[1],[2]
2022 [Member] | Oil Collars [Member] | Brent Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	199,900	[1]
2022 [Member] | Oil Collars [Member] | Brent Bbl [Member] | Minimum [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	50	[1],[3]
2022 [Member] | Oil Collars [Member] | Brent Bbl [Member] | Maximum [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	61	[1],[3]
[1]	Includes 100% of Carbon California's outstanding derivative hedges at December 31, 2019, and not our proportionate share.
[2]	NYMEX Light Sweet Crude West Texas Intermediate futures contracts for the respective period.
[3]	Brent future contracts for the respective period.
[4]	NYMEX Henry Hub Natural Gas futures contracts for the respective period.

Commodity Derivatives (Details

Commodity Derivatives (Details 1) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Commodity derivative contracts:
Commodity derivative asset	$ 5,915	$ 3,517
Commodity derivative asset - non-current	1,164	3,505
Commodity derivative liability	469
Commodity derivative liability – non-current	$ 87

Commodity Derivatives (Detail_2

Commodity Derivatives (Details 2) - Commodity derivative contracts [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Settlement gain (loss)	$ 3,543	$ (3,848)
Unrealized (loss) gain	(499)	8,742
Total commodity derivative gain	$ 3,044	$ 4,894

Commodity Derivatives (Detail_3

Commodity Derivatives (Details 3) $ in Thousands	Dec. 31, 2019USD ($)
Commodity derivative asset - current [Member]
Derivatives, Fair Value [Line Items]
Gross Recognized Assets	$ 6,917
Gross Amounts Offset	(1,002)
Net Recognized Fair Value Assets	5,915
Commodity derivative asset - non-current [Member]
Derivatives, Fair Value [Line Items]
Gross Recognized Assets	3,478
Gross Amounts Offset	(2,314)
Net Recognized Fair Value Assets	1,164
Total derivative assets [Member]
Derivatives, Fair Value [Line Items]
Gross Recognized Assets	10,395
Gross Amounts Offset	(3,316)
Net Recognized Fair Value Assets	7,079
Commodity derivative liability - current [Member]
Derivatives, Fair Value [Line Items]
Gross Recognized Liabilities	(1,471)
Gross Amounts Offset	1,002
Net Recognized Fair Value Liabilities	(469)
Commodity derivative liability - non-current [Member]
Derivatives, Fair Value [Line Items]
Gross Recognized Liabilities	(2,401)
Gross Amounts Offset	2,314
Net Recognized Fair Value Liabilities	(87)
Total derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Gross Recognized Liabilities	(3,872)
Gross Amounts Offset	3,316
Net Recognized Fair Value Liabilities	$ (556)

Commitments and Contingencies_2

Commitments and Contingencies (Details) - Transportation Commitments [Member]	12 Months Ended
	Dec. 31, 2019$ / DekathermDekatherms
Jan 2020 – Mar 2020 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Dekatherms	58,871
Jan 2020 – Mar 2020 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.20
Jan 2020 – 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) | Dekatherms	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) | Dekatherms	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) | Dekatherms	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) | Dekatherms	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) | Dekatherms	1,000
Demand Charges (in dollars per dekatherm)	0.20

Commitments and Contingencies_3

Commitments and Contingencies (Details Textual) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)$ / McfMcf
Commitments and Contingencies Disclosure [Abstract]
Firm transportation contract obligations, current and non-current	$ 14,600
Natural gas processing agreement initial term	5 years
Natural gas processing agreement extension period	5 years
Annual demand charges for volume commitments	$ 1,800
Minimum annual volume commitment | Mcf	720
Natural gas processing fee | $ / Mcf	2.50

Supplemental Cash Flow Disclo_3

Supplemental Cash Flow Disclosure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Cash paid during the period for:
Interest	$ 9,191	$ 4,217
Non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	(2,563)	(206)
Adjustments to OIE Membership Acquisition purchase price	$ 1,505

Supplemental Financial Data -_3

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details)	12 Months Ended
	Dec. 31, 2019MBblsMMcf	Dec. 31, 2018MBblsMMcf
Summary of proved developed and undeveloped oil and gas reserves
Proved reserves, beginning of year | MMcf	580,326	87,216
Revisions of previous estimates | MMcf	12,310	(21,868)
Extensions and discoveries | MMcf	6,605
Production | MMcf	(25,182)	(7,702)
Purchases of reserves in-place | MMcf		522,680
Sales of reserves in-place | MMcf	(9,166)
Proved reserves, end of year | MMcf	564,893	580,326
Proved developed reserves at:
End of Year | MMcf	527,555	545,272
Proved undeveloped reserves at:
End of Year | MMcf	37,338	35,054
Oil [Member]
Summary of proved developed and undeveloped oil and gas reserves
Proved reserves, beginning of year | MBbls	18,898	919
Revisions of previous estimates | MBbls	(1,362)	(2,803)
Extensions and discoveries | MBbls	826
Production | MBbls	(589)	(451)
Purchases of reserves in-place | MBbls		21,233
Sales of reserves in-place | MBbls	(31)
Proved reserves, end of year | MBbls	17,742	18,898
Proved developed reserves at:
End of Year | MBbls	12,972	14,336
Proved undeveloped reserves at:
End of Year | MBbls	4,770	4,562
Natural Gas [Member]
Summary of proved developed and undeveloped oil and gas reserves
Proved reserves, beginning of year | MMcf	455,400	81,702
Revisions of previous estimates | MMcf	24,194	1,832
Extensions and discoveries | MMcf	1,187
Production | MMcf	(21,436)	(4,798)
Purchases of reserves in-place | MMcf		376,664
Sales of reserves in-place | MMcf	(8,980)
Proved reserves, end of year | MMcf	450,365	455,400
Proved developed reserves at:
End of Year | MMcf	444,104	450,424
Proved undeveloped reserves at:
End of Year | MMcf	6,261	4,976
Natural gas liquids [Member]
Summary of proved developed and undeveloped oil and gas reserves
Proved reserves, beginning of year | MBbls	1,923
Revisions of previous estimates | MBbls	(618)	(1,147)
Extensions and discoveries | MBbls	77
Production | MBbls	(36)	(33)
Purchases of reserves in-place | MBbls		3,103
Sales of reserves in-place | MBbls
Proved reserves, end of year | MBbls	1,346	1,923
Proved developed reserves at:
End of Year | MBbls	936	1,472
Proved undeveloped reserves at:
End of Year | MBbls	410	451

Supplemental Financial Data -_4

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 1) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Oil and gas properties
Proved oil and gas properties	$ 351,488	$ 347,059
Unproved properties	4,872	5,416
Accumulated depreciation, depletion, amortization and impairment	(109,344)	(98,604)
Net oil and gas properties	$ 247,016	$ 253,871

Supplemental Financial Data -_5

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property acquisition costs:
Unevaluated properties	$ 496	$ 3,464	$ 912
Proved properties and gathering facilities		63,517
Development costs	7,676	2,074
Gathering facilities		460
Asset retirement obligation		$ 14,085

Supplemental Financial Data -_6

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract]
Total acquisition costs	$ 496	$ 3,464	$ 912

Supplemental Financial Data -_7

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 4) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenue:
Oil, gas and NGL sales, including commodity derivative gains and losses	$ 96,885	$ 52,946
Expenses:
Production expenses	41,307	22,226
Depletion expense	14,062	7,305
Accretion of asset retirement obligations	1,625	868
Total expenses	56,994	30,399
Results of operations from oil and gas producing activities	$ 39,891	$ 22,547
Depletion rate per Mcfe	$ 0.56	$ 0.89

Supplemental Financial Data -_8

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 5) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Summary of estimate of the current market value of the Company's proved reserves
Future cash inflows	$ 2,212,049	$ 2,878,392
Future production costs	(1,306,608)	(1,538,870)
Future development costs	(77,952)	(76,852)
Future income taxes	(146,951)	(258,277)
Future net cash flows	680,538	1,004,393
10% annual discount	(408,690)	(612,325)
Standardized measure of discounted future net cash flows	$ 271,848	$ 392,068	$ 57,082

Supplemental Financial Data -_9

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 6) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
Standardized measure of discounted future net cash flows, beginning of year	$ 392,068	$ 57,082
Sales of oil and gas, net of production costs and taxes	(49,746)	(25,681)
Price revisions	(158,799)	133,789
Extensions, discoveries and improved recovery, less related costs	10,822
Changes in estimated future development costs	(3,041)	(32,711)
Development costs incurred during the period	6,685	926
Quantity revisions	5,565	(23,484)
Accretion of discount	39,207	5,708
Net changes in future income taxes	39,929	(89,117)
Purchases of reserves-in-place		391,877
Sales of reserves-in-place	(4,004)
Changes in production rate timing and other	(6,838)	(26,321)
Standardized measure of discounted future net cash flows, end of year	$ 271,848	$ 392,068

Supplemental Financial Data _10

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 7)	12 Months Ended
	Dec. 31, 2019$ / Bbl$ / Mcf	Dec. 31, 2018$ / Bbl$ / Mcf
Oil [Member]
Average Sales Price And Production Cost Per Unit [Abstract]
Price per unit used to prepare reserve estimates, based upon average prices | $ / Bbl	55.69	65.56
Natural Gas [Member]
Average Sales Price And Production Cost Per Unit [Abstract]
Price per unit used to prepare reserve estimates, based upon average prices | $ / Mcf	2.58	3.10

Supplemental Financial Data _11

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details Textual) - Bcfe	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Textual)
Proved reserves attributable to non-controlling interests	3.4	3.3
Discount rate, description	All cash flow amounts, including income taxes, are discounted at 10%.