10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒   Quarterly report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended March 31, 2019

or

☐   Transition report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from ___________ to ____________

Commission File Number: 000-02040

CARBON ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	26-0818050
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
1700 Broadway, Suite 1170, Denver, CO	80290
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (720) 407-7030

(Former name, address and fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Company was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

YES ☒               NO ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to rule 405 of Regulations S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

YES ☒               NO ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☐	Smaller reporting company	☒
Accelerated filer	☐	Emerging growth company	☐
Non-accelerated filer	☒

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

YES ☐               NO ☒

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading symbol(s)	Name of each exchange on which registered
None

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

At May 13, 2019, there were 7,816,030 issued and outstanding shares of the Company’s common stock, $0.01 par value.

Carbon Energy Corporation

TABLE OF CONTENTS

Part I – FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements	1
Consolidated Balance Sheets (unaudited)	1
Consolidated Statements of Operations (unaudited)	2
Consolidated Statements of Stockholders’ Equity (unaudited)	3
Consolidated Statements of Cash Flows (unaudited)	4
Notes to the Consolidated Financial Statements (unaudited)	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3. Quantitative and Qualitative Disclosures About Market Risk	45
Item 4. Controls and Procedures	45
Part II – OTHER INFORMATION
Item 1. Legal Proceedings	46
Item 1A. Risk Factors	46
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 6. Exhibits	46

i

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

CARBON ENERGY CORPORATION

Consolidated Balance Sheets

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

See accompanying notes to Consolidated Financial Statements.

2 

CARBON ENERGY CORPORATION

Consolidated Statements of Operations

(Unaudited)

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

See accompanying notes to Consolidated Financial Statements.

3 

CARBON ENERGY CORPORATION

Consolidated Statements of Stockholders’ Equity

(Unaudited)

(in thousands)

					Additional		Non-						Total
	Common Stock				Paid-in		Controlling			Accumulated			Stockholders’
	Shares		Amount		Capital		Interests			Deficit			Equity
Balances, December 31, 2017		6,006	$	60	$	58,813	$	1,841		$	(44,218	)	$	16,496
Stock based compensation		-		-		292		-			-			292
Restricted stock vested		38		1		-		-			-			1
CCC warrant exercise – share issuance		1,528		15		8,311		16,466			-			24,792
CCC warrant exercise – liability extinguishment		-		-		1,792		-			-			1,792
Non-controlling interest distributions, net		-		-		-		(24	)		-			(24	)
Net income		-		-		-		1,115			3,569			4,684
Balances, March 31, 2018		7,572	$	76	$	69,208	$	19,398		$	(40,649	)	$	48,033

									Additional			Non-						Total
	Common Stock				Preferred Stock				Paid-in			Controlling			Accumulated			Stockholders’
	Shares		Amount		Shares		Amount		Capital			Interests			Deficit			Equity
Balances, December 31, 2018		7,656	$	77		50	$	1	$	84,612		$	28,284		$	(36,939	)	$	76,035
Stock-based compensation		-		-		-		-		222			-			-			222
Restricted stock vested		40		1		-		-		-			-			-			1
Performance units vested		95		1		-		-		(1	)		-			-			-
Non-controlling interests’ contributions, net		-		-		-		-		-			22			-			22
Net loss		-		-		-		-		-			(2,590	)		(4,100	)		(6,690	)
Balances, March 31, 2019		7,791	$	79		50	$	1	$	84,833		$	25,716		$	(41,039	)	$	69,590

See accompanying notes to Consolidated Financial Statements.

4 

CARBON ENERGY CORPORATION

Consolidated Statements of Cash Flows

(Unaudited)

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

See accompanying notes to Consolidated Financial Statements.

5 

CARBON ENERGY CORPORATION

Notes to Consolidated Financial Statements

(Unaudited)

Note 1 – Organization

Carbon Energy Corporation (formerly known as Carbon Natural Gas Company) and its subsidiaries (referred to herein as “we”, “us”, the “Company” or “Carbon”) business is comprised of the assets and properties of us and our subsidiaries.

An illustrative organizational chart as of March 31, 2019, is below:

 

Appalachian and Illinois Basin Operations

In the Appalachian and Illinois Basins, operations are conducted by Nytis Exploration Company, LLC (“Nytis LLC”). The following organizational chart illustrates this relationship as of March 31, 2019.

 

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”), owned by Old Ironside Fund II-A Portfolio Holding Company, LLC, a Delaware limited liability company (“OIE II-A”), and Old Ironside Fund II-B Portfolio Holding Company, LLC, a Delaware limited liability company (“OIE II-B”), collectively (“Old Ironsides”) for a purchase price of $58.1 million subject to customary and standard purchase price adjustments (“OIE Membership Acquisition”). As a result of the OIE Membership Acquisition, we now hold all of the issued and outstanding ownership interests of Carbon Appalachia, along with its direct and indirect subsidiaries (Carbon Appalachia Group, LLC, Carbon Tennessee Mining Company, LLC, Carbon Appalachia Enterprises, LLC, Carbon West Virginia Company, LLC, Cranberry Pipeline Corporation, Knox Energy, LLC, Coalfield Pipeline Company and Appalachia Gas Services Company, LLC).

6 

Ventura Basin Operations

In California, Carbon California Operating Company, LLC (“CCOC”) conducts operations on behalf of Carbon California Company, LLC’s (“Carbon California”) operations. On February 1, 2018, Yorktown Energy Partners XI, L.P. (“Yorktown”) exercised the California Warrant, resulting in our aggregate sharing percentage in Carbon California increasing from 17.81% to 56.40%. On May 1, 2018, Carbon California closed the Seneca Acquisition. Following the exercise of the California Warrant by Yorktown and the Seneca Acquisition, we own 53.92% of the voting and profits interests and Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America or its affiliates (collectively, “Prudential”) owns 46.08% of the voting and profits interest in Carbon California. As of February 1, 2018, we consolidate Carbon California for financial reporting purposes. The following organizational chart illustrates this relationship as of March 31, 2019.

Collectively, references to “us” include Carbon California, CCOC, Nytis Exploration (USA) Inc. (“Nytis USA”), Nytis LLC, and Carbon Appalachia.

Note 2 – Summary of Significant Accounting Policies

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information. Accordingly, they do not include all the information and footnotes required by GAAP for complete financial statements. In the opinion of management, the accompanying unaudited condensed consolidated financial statements include all adjustments considered necessary to present fairly our financial position as of March 31, 2019, and our results of operations and cash flows for the three months ended March 31, 2019 and 2018. Operating results for the three months ended March 31, 2019 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results, seasonality, and other factors. The unaudited condensed consolidated financial statements and related notes included in this Quarterly Report on Form 10-Q should be read in conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2018. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in our 2018 Annual Report on Form 10-K.

Principles of Consolidation

The unaudited condensed consolidated financial statements include the accounts of our consolidated subsidiaries. Upon the closing of the OIE Membership Acquisition on December 31, 2018, we own 100% of Carbon Appalachia. In addition, we own 100% of Nytis USA, which owns approximately 98.1% of Nytis LLC. Nytis LLC holds interests in various oil and gas partnerships.

7 

Partnerships and subsidiaries in which we have a controlling interest are consolidated. We are currently consolidating 46 partnerships, Carbon Appalachia, and Carbon California, and we reflect the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on our unaudited consolidated statements of operations and also reflect the non-controlling ownership interest in the net assets of the partnerships as non-controlling interests within stockholders’ equity on our unaudited consolidated balance sheets. All significant intercompany accounts and transactions have been eliminated.

In accordance with established practice in the oil and gas industry, our unaudited condensed consolidated financial statements also include our pro-rata share of assets, liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which we have a non-controlling interest.

Non-majority owned investments that do not meet the criteria for pro-rata consolidation are accounted for using the equity method when we have the ability to significantly influence the operating decisions of the investee. When we do not have the ability to significantly influence the operating decisions of an investee, the cost method is used. All transactions, if any, with investees have been eliminated in the accompanying unaudited condensed consolidated financial statements.

Reclassifications

Certain prior period balances in the consolidated balance sheets and statements of operations have been reclassified to conform to the current year presentation.  Specifically, a portion of credit facilities and notes payable balances as of December 31, 2018 were reclassified from non-current liabilities to current liabilities.  This reclassification had no impact on net income, cash flows or shareholders’ equity previously reported.

Insurance Receivable

Insurance receivable is comprised of insurance claims for the loss of property as a result of wildfires that impacted Carbon California in December 2017. The Company filed claims with its insurance provider. In January 2019, we reached a settlement agreement and received an $800,000 payment from our insurance provider related to the damage caused by the California wildfires. As of March 31, 2019, we are in receipt of all funds associated with the claims.  

Accounting for Oil and Gas Operations

We use the full cost method of accounting for oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Overhead costs incurred that are directly identified with acquisition, exploration and development activities undertaken by the Company for its own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized.

Unproved properties are excluded from amortized capitalized costs until it is determined if proved reserves can be assigned to such properties. We assess our unproved properties for impairment at least annually. Significant unproved properties are assessed individually.

Capitalized costs are depleted by an equivalent unit-of-production method, converting oil to gas at the ratio of one barrel of oil to six thousand cubic feet of natural gas. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.

No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves. All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.

We perform a ceiling test quarterly. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value based measurement, rather it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using the un-weighted arithmetic average of the first-day-of-the month price for the previous twelve month period, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs. Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds the capitalized costs in future periods.

8 

For the three months ended March 31, 2019 and 2018, we did not recognize a ceiling test impairment as our full cost pool did not exceed the ceiling limitations. Future declines in oil and natural gas prices could result in impairments of our oil and gas properties in future periods. The effect of price declines will impact the ceiling test value until such time commodity prices stabilize or improve. Impairments are a non-cash charge and accordingly would not affect cash flows but would adversely affect our results of operations and members’ equity.

We capitalize the portion of general and administrative costs that is attributable to our acquisition, exploration and development activities.

Revenue

We recognize revenues for sales and services when persuasive evidence of an arrangement exists, when custody is transferred, or services are rendered, fees are fixed or determinable and collectability is reasonably assured.

Oil, Natural Gas and Natural Gas Liquid Sales

Oil, natural gas and natural gas liquid sales are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred, and collectability is reasonably assured. Revenues are recognized based on our net revenue interest.

Marketing Gas Sales

We sell production purchased from third parties as well as production from our own oil and gas producing properties. Marketing gas sales are recognized on a gross basis as we purchase and take control of the gas prior to sale and are the principal in the transaction.

Storage

Under fee-based arrangements, we receive a fee for storing natural gas. The revenues earned are directly related to the volume of natural gas that flows through our systems and are not directly dependent on commodity prices.

Transportation, gathering, and compression

We generally purchase natural gas from producers at the wellhead or other receipt points, gather the wellhead natural gas through our gathering systems, and then sell the natural gas based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of natural gas or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, regardless of the actual amount of the sales proceeds we receive. Our revenues under percent-of-proceeds/index arrangements generally correlate to the price of natural gas.

Investments in Affiliates

Investments in non-consolidated affiliates are accounted for under either the cost or equity method of accounting, as appropriate. The cost method of accounting is generally used for investments in affiliates in which we have less than 20% of the voting interests of a corporate affiliate (or less than a 3% to 5% interest of a partnership or limited liability company) and do not have significant influence. Investments in non-consolidated affiliates, accounted for using the cost method of accounting, are recorded at cost and impairment assessments for each investment are made annually to determine if a decline in the fair value of the investment, other than temporary, has occurred. A permanent impairment is recognized if a decline in the fair value occurs.

If we hold between 20% and 50% of the voting interest in non-consolidated corporate affiliates or generally greater than a 3% to 5% interest of a partnership or limited liability company and can exert significant influence or control (e.g., through our influence with a seat on the board of directors or management of operations), the equity method of accounting is generally used to account for the investment. Equity method investments will increase or decrease by our share of the affiliate’s profits or losses and such profits or losses are recognized in our unaudited consolidated statements of operations. We review equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred. Upon the exercise of the California Warrant on February 1, 2018 and the closing of the OIE Membership Acquisition on December 31, 2018, we consolidate Carbon California and Carbon Appalachia for financial reporting purposes and no longer account for these investments under the equity method.

9 

Related Party Transactions

Management Reimbursements

In our role as manager of Carbon California and Carbon Appalachia we receive reimbursements for management services. Prior to consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, these management service reimbursements were included in general and administrative – related party reimbursement on our unaudited consolidated statements of operations. As we now consolidate both Carbon California and Carbon Appalachia, these reimbursements are eliminated upon consolidation.

We received approximately $753,000 and $50,000 for the three months ended March 31, 2018, and for the one month ended January 31, 2018, from Carbon Appalachia and Carbon California, respectively. These reimbursements are included in general and administrative – related party reimbursement on our unaudited consolidated statements of operations. Effective February 1, 2018, the management reimbursements received from Carbon California were eliminated at consolidation. This elimination included $100,000 for the period February 1, 2018, through March 31, 2018.

In addition to the management reimbursements, approximately $299,000 and $14,000 in general and administrative expenses were reimbursed for the three months ended March 31, 2018, and for the one month ended January 31, 2018, by Carbon Appalachia and Carbon California, respectively. The elimination of Carbon California in consolidation includes approximately $28,000 for the period February 1, 2018, through March 31, 2018.

Operating Reimbursements

In our role as operator of Carbon California and Carbon Appalachia, we receive reimbursements of operating expenses. Prior to consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, these operating reimbursements were included in operating expenses on our unaudited consolidated statements of operations. As we now consolidate both Carbon California and Carbon Appalachia, any intercompany receivable and payable balances associated with these reimbursements are eliminated upon consolidation.

Carbon California Credit Facilities

The credit facilities of Carbon California, including the Senior Revolving Notes, Carbon California Notes and Carbon California 2018 Subordinated Notes (all defined below), are held by Prudential (see Note 7).

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and expenses and disclosure of contingent assets and liabilities. Significant items subject to such estimates and assumptions include the carrying value of oil and gas properties, estimates of proved oil and gas reserve volumes and the related depletion and present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, determining the amounts recorded for fair value of commodity derivative instruments, fair value of assets acquired and liabilities assumed qualifying as business combinations or asset acquisitions, estimated lives of other property and equipment, asset retirement obligations, fair value of Class B issuances and accrued liabilities and revenues. There have been no changes in our critical accounting estimates from those that were disclosed in the 2018 Annual Report on Form 10-K. Actual results could differ from these estimates.

10 

Earnings (Loss) Per Common Share

Basic earnings per common share is computed by dividing the net income or loss attributable to common stockholders for the period by the weighted average number of common shares outstanding during the period. The shares of restricted common stock granted to our officers, directors and employees are included in the computation of basic net income per share only after the shares become fully vested. Diluted earnings per common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise of options and warrants to acquire common stock computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by us with the proceeds from the exercise of options and warrants (which were assumed to have been made at the average market price of the common shares during the reporting period).

In periods when we report a net loss, all shares of restricted stock are excluded from the calculation of diluted weighted average shares outstanding because of its anti-dilutive effect on loss per share. As a result, approximately 269,000 potentially dilutive restricted stock awards are excluded from the calculation of diluted earnings per common share for the three months ended March 31, 2019. In addition, approximately 200,000 restricted performance units subject to future contingencies were excluded in the basic and diluted income per share calculations.

For the three months ended March 31, 2018, we had net income and the diluted income per common share calculation includes the dilutive effects of approximately 230,000 non-vested shares of restricted stock. In addition, approximately 254 ,000 restricted performance units subject to future contingencies were excluded in the basic and diluted income per share calculations.

The following table sets forth the calculation of basic and diluted (loss) income per share:

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

Recently Adopted Accounting Pronouncement

In February 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The FASB subsequently issued various ASUs which provided additional implementation guidance, and these ASUs collectively make up FASB Accounting Standards Codification (“ASC”) Topic 842 – Leases (“ASC 842”). ASC 842 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The standard permits retrospective application through recognition of a cumulative-effect adjustment at the beginning of either the earliest reporting period presented or the period of adoption. The Company adopted ASC 842 effective January 1, 2019 using the modified retrospective method as of the adoption date. Adoption of the standard resulted in the recognition of additional lease assets and liabilities on our unaudited consolidated balance sheet as well as additional disclosures. The adoption did not have a material impact to our unaudited consolidated statement of operations. Refer to Note 14 for further information on our implementation of this standard.

11 

Recently Issued Accounting Pronouncements

There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows.

Note 3 – Acquisitions and Divestitures

Majority Control of Carbon Appalachia

On December 16, 2016, Carbon Appalachia was formed by us, entities managed by Yorktown and entities managed by Old Ironsides to acquire producing assets in the Appalachian Basin in Kentucky, Tennessee, Virginia and West Virginia. Carbon Appalachia began substantial operations on April 3, 2017 and is engaged primarily in acquiring, developing, exploiting, producing, processing, marketing, and transporting oil and natural gas in the Appalachian Basin.

On April 3, 2017, Carbon, Yorktown and Old Ironsides entered in to a limited liability company agreement (the “Carbon Appalachia LLC Agreement”), with an initial equity commitment of $100.0 million, of which $37.0 million had been contributed as of December 31, 2018. Carbon Appalachia (i) issued Class A Units to us, Yorktown and Old Ironsides for an aggregate cash consideration of $12.0 million, (ii) issued Class B Units to us, and (iii) issued Class C Units to us. Additionally, Carbon Appalachia Enterprises, LLC, formerly known as Carbon Tennessee Company, LLC (“Carbon Appalachia Enterprises”), a subsidiary of Carbon Appalachian Company, LLC, entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank (the “Revolver”) with an initial borrowing base of $10.0 million.

In connection with Carbon entering into the Carbon Appalachia LLC Agreement, and Carbon Appalachia engaging in the transactions described above, Carbon received 1,000 Class B Units and issued to Yorktown a warrant to purchase approximately 408,000 shares of our common stock at an exercise price dictated by the warrant agreement (the “Appalachia Warrant”). The Appalachia Warrant was payable exclusively with Class A Units of Carbon Appalachia held by Yorktown. On November 1, 2017, Yorktown exercised the Appalachia Warrant, resulting in us acquiring 2,940 Class A Units from Yorktown. 

On August 15, 2017, the Carbon Appalachia LLC Agreement was amended and, as a result, we agreed to contribute an initial commitment of future capital contributions as well as Yorktown’s, and Yorktown will not participate in future capital contributions. Carbon Appalachia issued Class A Units to us and Old Ironsides for an aggregate cash consideration of $14.0 million. The borrowing base of the Revolver increased to $22.0 million and Carbon Appalachia Enterprises borrowed $8.0 million under the Revolver.

12 

On September 29, 2017, Carbon Appalachia issued Class A Units to us and Old Ironsides for an aggregate cash consideration of $11.0 million.

Prior to the closing of the OIE Membership Acquisition, Old Ironsides held 27,195 Class A Units, which equated to a 72.76% aggregate share ownership of Carbon Appalachia and we held (i) 9,805 Class A Units, (ii) 1,000 Class B Units and (iii) 121 Class C Units, which equated to a 27.24% aggregate share ownership of Carbon Appalachia.

On December 31, 2018, we acquired all of Old Ironsides’ Class A Units of Carbon Appalachia for approximately $58.1 million, subject to customary and standard closing adjustments. We paid $33.0 million in cash and delivered promissory notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides (the “Old Ironsides Notes”). The Old Ironsides Notes bear interest at 10% per annum and have a term of five years, the first three of which require interest-only payments at the end of each calendar quarter beginning with the quarter ending March 31, 2019. At the end of the three-year interest-only period, the then current outstanding principal balance and interest is to be paid in 24 equal monthly payments. The Old Ironsides Notes also provide for mandatory prepayments upon the occurrence of certain subsequent liquidity events. A mandatory, one-time principal reduction payment in the aggregate amount of $2.0 million was made to Old Ironsides on February 1, 2019.

The OIE Membership Acquisition is accounted for as a business combination in accordance with ASC 805, Business Combinations (“ASC 805”). We recognized 100% of the identifiable assets acquired and liabilities assumed at their respective fair value as of the date of the acquisition. The $58.1 million purchase price, consisting of $33.0 million in cash and $25.1 million of Old Ironsides Notes, was paid for Old Ironsides’ outstanding interest, representing approximately 72.76% interest in Carbon Appalachia.

The Company, utilizing the assistance of third-party valuation specialists, considered various factors in its estimate of fair value of the acquired assets and liabilities including (i) reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, including price differentials, (v) future cash flows, (vi) a market participant-based weighted average cost of capital, and (vii) real estate market conditions.

We followed the fair value method to allocate the consideration transferred to the identifiable net assets acquired on a preliminary basis as follows:

	Amount  (in thousands)
Cash consideration	$	33,000
Old Ironsides Notes		25,065
Fair value of previously held equity interest		14,158
Fair value of business acquired	$	72,223

Assets acquired and liabilities assumed are as follows:

	Amount (in thousands)
Cash	$	12,283
Accounts receivable:
Revenue		12,834
Trade receivable		1,941
Commodity derivative asset		198
Inventory		900
Prepaid expenses, deposits, and other current assets		456
Oil and gas properties:
Proved		107,499
Unproved		1,869
Other property, plant and equipment, net		15,626
Other non-current assets		514
Accounts payable and accrued liabilities		(19,114	)
Due to related parties		(458	)
Firm transportation contract obligations		(18,724	)
Asset retirement obligations		(5,626	)
Notes payable		(37,975	)
Total net assets acquired	$	72,223

The preliminary fair value of the assets acquired and liabilities assumed were determined using various valuation techniques, including an income approach.

13 

On the date of the acquisition, we derecognized our equity investment in Carbon Appalachia and recognized a gain of approximately $1.3 million based on the fair value of our previously held interest compared to its carrying value.

For assets and liabilities accounted for as business combinations, including the OIE Membership Acquisition, to determine the fair value of the assets acquired, the Company primarily used the income approach and made market assumptions as to projections of estimated quantities of oil and natural gas reserves, future production rates, future commodity prices including price differentials as of the date of closing, future operating and development costs, a market participant weighted average cost of capital, and the condition of vehicles and equipment. The Company used the income approach and made market assumptions as to projections of utilization, future operating costs and a market participant weighted average costs of capital to determine the fair value of the firm transportation obligations as well as the plant facilities. The determination of the fair value of accounts payable and accrued liabilities assumed required significant judgement, including estimates relating to production assets.

Consolidation of Carbon Appalachia and OIE Membership Acquisition Unaudited Pro Forma Results of Operations

Below are unaudited pro forma consolidated results of operations for the three months ended March 31, 2019 and 2018 as though the OIE Membership Acquisition had been completed as of January 1, 2018.

	Three Months Ended March 31,			Three Months Ended March 31,
(in thousands, except per share amounts)	2019			2018
Revenue	$	24,950		$	32,316
Net (loss) income before non-controlling interests	$	(6,690	)	$	6,912
Net (loss) income attributable to non-controlling interests	$	(2,590	)	$	1,115
Net (loss) income attributable to common shareholders	$	(4,175	)	$	5,797
Net (loss) income per share (basic)	$	(0.54	)	$	0.83
Net (loss) income per share (diluted)	$	(0.54	)	$	0.77

Consolidation of Carbon California Unaudited Pro Forma Results of Operations

On February 1, 2018, Yorktown exercised the California Warrant resulting in the issuance of 1,527,778 shares of our common stock in exchange for Yorktown’s Class A Units of Carbon California representing approximately 46.96% of the outstanding Class A Units of Carbon California (a profits interest of approximately 38.59%). After giving effect to the exercise on February 1, 2018, we owned 56.4% of the voting and profits interests of Carbon California.

Below are unaudited pro forma consolidated results of operations for the three months ended March 31, 2019 and 2018 as though the Carbon California Acquisition had been completed as of January 1, 2018. The Carbon California Acquisition closed February 1, 2018, and accordingly, the Company’s unaudited consolidated statements of operations for the quarter ended March 31, 2018, includes the results of operations for the period February 1, 2018, through March 31, 2018.

	Three Months Ended March 31,			Three Months Ended March 31,
(in thousands, except per share amounts)	2019			2018
Revenue	$	24,950		$	6,672
Net (loss) income before non-controlling interests	$	(6,690	)	$	3,543
Net (loss) income attributable to non-controlling interests	$	(2,590	)	$	1,115
Net (loss) income attributable to common shareholders	$	(4,175	)	$	2,428
Net (loss) income per share (basic)	$	(0.54	)	$	0.35
Net (loss) income per share (diluted)	$	(0.54	)	$	0.30

14 

Note 4 – Property and Equipment

Net property and equipment as of March 31, 2019 and December 31, 2018 consists of the following:

(in thousands)	March 31, 2019			December 31, 2018
Oil and gas properties:
Proved oil and gas properties	$	344,147		$	343,736
Unproved properties not subject to depletion		5,385			5,416
Accumulated depreciation, depletion, amortization and impairment		(98,826	)		(95,281	)
Net oil and gas properties		250,706			253,871
Pipeline facilities and equipment		12,714			12,714
Base gas		2,122			2,122
Furniture and fixtures, computer hardware and software, and other equipment		6,688			6,649
Accumulated depreciation and amortization		(4,356	)		(3,922	)
Net other property and equipment		17,168			17,563
Total net property and equipment	$	267,874		$	271,434

As of March 31, 2019, and December 31, 2018, the Company had approximately $5.4 million of unproved oil and gas properties not subject to depletion. The costs not subject to depletion relate to unproved properties that are excluded from amortized capital costs until it is determined if proved reserves can be assigned to such properties. The excluded properties are assessed for impairment at least annually. Subject to industry conditions, evaluation of most of these properties and the inclusion of their costs in amortized capital costs is expected to be completed within five years.

During the three months ended March 31, 2019 and 2018, there were no expiring leasehold costs that were reclassified into proved property. The excluded properties are assessed for impairment at least annually. Subject to industry conditions, evaluations of most of these properties and the inclusion of their costs in amortized capital costs is expected to be completed within five years.

We capitalized overhead applicable to acquisition, development and exploration activities of approximately $68,000 and $71,000 for the three months ended March 31, 2019 and 2018, respectively.

Depletion expense related to oil and gas properties for the three months ended March 31, 2019 and 2018 was approximately $3.5 million, or $0.54 per Mcfe, and $1.3 million, or $0.82 per Mcfe, respectively.

Note 5 – Asset Retirement Obligation

Asset Retirement Obligations

The Company’s asset retirement obligations (“ARO”) relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred and the cost of such liability is recorded as an increase in the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability.

The estimated ARO liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or increased as a result of a reassessment of expected cash flows and assumptions inherent in the estimation of the liability. Upward revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. AROs are valued utilizing Level 3 fair value measurement inputs.

15 

The following table is a reconciliation of the ARO for the three months ended March 31, 2019 and 2018:

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

Note 6 – Investments in Affiliates

Carbon Appalachia

For the period April 3, 2017 (inception) through December 31, 2018, based on our 27.24% combined Class A, Class B and Class C interest (and our ability as of December 31, 2018 to earn up to an additional 14.7%) in Carbon Appalachia, our ability to appoint a member to the board of directors and our role of manager of Carbon Appalachia, we accounted for our investment in Carbon Appalachia under the equity method of accounting as we believed we exerted significant influence. We used the HLBV to determine our share of profits or losses in Carbon Appalachia and adjusted the carrying value of our investment accordingly. Our investment in Carbon Appalachia is represented by our Class A and C interests, which we acquired by contributing approximately $6.9 million in cash and unevaluated property. In the event of liquidation of Carbon Appalachia, available proceeds are first distributed to members holding Class C Units then to holders of Class A Units until their contributed capital is recovered with an internal rate of return of 10%. Any additional distributions would then be shared between holders of Class A, Class B and Class C Units.

On December 31, 2018, we acquired all of Old Ironsides’ Class A Units of Carbon Appalachia for approximately $58.1 million, subject to customary and standard closing adjustments. We paid $ 33.0 million in cash and issued the Old Ironsides Notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides.

Effective December 31, 2018, upon the closing of the OlE Membership Acquisition, we consolidate Carbon Appalachia in our consolidated financial statements.

Carbon California

For the period February 15, 2017 (inception) through January 31, 2018, based on our 17.81% interest in Carbon California, our ability to appoint a member to the board of directors and our role of manager of Carbon California, we accounted for our investment in Carbon California under the equity method of accounting as we believed we exerted significant influence. We used the Hypothetical Liquidation at Book Value Method (“HLBV”) to determine our share of profits or losses in Carbon California and adjusted the carrying value of our investment accordingly. The HLBV is a balance-sheet approach that calculates the amount each member of Carbon California would have received if Carbon California were liquidated at book value at the end of each measurement period. The change in the allocated amount to each member during the period represents the income or loss allocated to that member. In the event of liquidation of Carbon California, to the extent that Carbon California has net income, available proceeds are first distributed to members holding Class B Units and any remaining proceeds are then distributed to members holding Class A Units.

Effective February 1, 2018, upon the exercise of the California Warrant, we consolidate Carbon California in our consolidated financial statements.

Other Affiliates

At March 31, 2019 and December 31, 2018, we retained interests in two equity method investments associated with the development and transportation of oil and gas.

16 

Note 7 – Credit Facilities and Notes Payable

Carbon Appalachia

The table below summarizes the outstanding credit facilities and notes payable:

(in thousands)	March 31, 2019			December 31, 2018
2018 Credit Facility – revolver	$	70,150		$	69,150
2018 Credit Facility – term note		13,333			15,000
Old Ironsides Notes		23,659			25,065
Other debt		48			57
Total principal		107,190			109,272
Less:  unamortized debt discount		(112	)		(134	)
Total credit facilities and notes payable	$	107,078		$	109,138

The current portion of the outstanding credit facilities and notes payable was approximately $9.9 million as of March 31, 2019 and $11.9 million as of December 31, 2018.

2018 Credit Facility

In connection with and concurrently with the closing of the OIE Membership Acquisition, the Company and its subsidiaries amended and restated our prior credit facilities for a new $500.0 million senior secured asset-based revolving credit facility maturing December 31, 2022 and a $15.0 million term loan which matures in 2020 (the “2018 Credit Facility”). The 2018 Credit Facility includes a sublimit of $1.5 million for letters of credit. The borrowers under the 2018 Credit Facility are Carbon Appalachia Enterprises, LLC (“CAE”) and various other subsidiaries of the Company (including Nytis USA, together with CAE, the “Borrowers”). Under the 2018 Credit Facility, Carbon Energy Corporation is neither a borrower nor a guarantor. The initial borrowing base under the 2018 Credit Facility was $75.0 million, and remained so as of March 31, 2019.

The 2018 Credit Facility is guaranteed by each existing and future direct or indirect subsidiary of the Borrowers and certain other subsidiaries of the Company (subject to various exceptions) and the obligations under the 2018 Credit Facility are secured by essentially all tangible, intangible and real property (subject to certain exclusions).

Interest accrues on borrowings under the 2018 Credit Facility at a rate per annum equal to either (i) the base rate plus an applicable margin equal to 0.25% - 0.75% depending on the utilization percentage or (ii) the Adjusted LIBOR rate plus an applicable margin equal to 2.75% - 3.75% depending on the utilization percentage, at the Borrowers’ option. The Borrowers are obligated to pay certain fees and expenses in connection the 2018 Credit Facility, including a commitment fee for any unused amounts of 0.50% and an origination fee of 0.50%. Loans under the 2018 Credit Facility may be prepaid without premium or penalty.

The 2018 Credit Facility also provides for a $15.0 million term loan which bears interest at a rate of 6.25% and is payable in 18 equal monthly installments beginning February 1, 2019 with the last payment due on June 30, 2020.

The 2018 Credit Facility contains certain affirmative and negative covenants that, among other things, limit the Company’s ability to (i) incur additional debt; (ii) incur additional liens; (iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distribution on, or repurchase of, equity; (vi) make certain investments; (vii) enter into certain transactions with their affiliates; (viii) enter in sale-leaseback transactions; (ix) make optional or voluntary payment of debt other than obligations under the 2018 Credit Facility; (x) change the nature of their business; (xi) change their fiscal year or make changes to the accounting treatment or reporting practices; (xii) amend their constituent documents; and (xiii) enter into certain hedging transactions.

17 

The affirmative and negative covenants are subject to various exceptions, including certain basket amounts and acceptable transaction levels. In addition, the 2018 Credit Facility requires the Borrowers’ compliance, on a consolidated basis, with a maximum Net Debt (all debt of the Borrowing Parties minus all unencumbered cash and cash equivalents of the Borrowers not to exceed $3.0 million) / EBITDAX (as defined) ratio of 3.50 to 1.00 and a current ratio, as defined, minimum of 1.00 to 1.00, tested quarterly, commencing with the quarter ending March 31, 2019. We are in compliance with our financial covenants as of March 31, 2019 and expect to be in compliance with these covenants throughout the next twelve month period. We are currently engaged in discussions with LegacyTexas Bank to decrease the required hedging period of our expected future production from 30 months to 24 months.

As of March 31, 2019, there was approximately $70.2 million in outstanding borrowings and $4.8 million of additional borrowing capacity under the 2018 Credit Facility.

The terms of the 2018 Credit Facility require us to enter into derivative contracts at fixed pricing for a certain percentage of our production. We are party to an ISDA Master Agreement with BP Energy Company that establishes standard terms for the derivative contracts and an inter-creditor agreement with LegacyTexas Bank and BP Energy Company whereby any credit exposure related to the derivative contracts entered into by us and BP Energy Company is secured by the collateral and backed by the guarantees supporting the 2018 Credit Facility.

Fees paid in connection with the 2018 Credit Facility totaled $779,000, of which $134,000 was associated with the term loan. The current portion of unamortized fees is included in prepaid expense, deposits and other current assets and the non-current portion is included in other non-current assets. The unamortized portion associated with the term loan was $112,000 as of March 31, 2019, and is directly offset against the loan in non-current liabilities. As of March 31, 2019, we had unamortized deferred issuance costs of $604,000 associated with the 2018 Credit Facility. During the three months ended March 31, 2019, we amortized approximately $63,000 as interest expense associated with the 2018 Credit Facility.

Old Ironsides Notes

On December 31, 2018, as part of the OIE Membership Acquisition, we delivered unsecured, promissory notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides (the “Old Ironsides Notes”). The Old Ironsides Notes bear interest at 10% per annum and have a term of five years, the first three of which require interest-only payments at the end of each calendar quarter beginning with the quarter ending March 31, 2019. At the end of the three-year interest-only period, the then current outstanding principal balance and interest is to be paid in 24 equal monthly payments. The Old Ironsides Notes also require mandatory prepayments upon the occurrence of certain subsequent liquidity events. A mandatory, one-time principal reduction payment in the aggregate amount of $2.0 million was made to Old Ironsides on February 1, 2019. Subsequent to the closing of the OIE Membership Acquisition Old Ironsides ceased to be a related party.

The interest payable under the Old Ironsides Notes can be paid-in-kind at the election of the Company. This provision allows the Company to increase the principal balance associated with the Old Ironsides Notes. This election creates a second tranche of principal, which bears interest at 12% per annum. On March 31, 2019, the Company elected to pay-in-kind approximately $594,000.

Carbon California

The table below summarizes the outstanding notes payable – related party:

(in thousands)	March 31, 2019			December 31, 2018
Senior Revolving Notes, related party, due February 15, 2022	$	38,500		$	38,500
Subordinated Notes, related party, due February 15, 2024		13,000			13,000
Total principal		51,500			51,500
Less: Deferred notes costs		(255	)		(235	)
Less: unamortized debt discount		(1,281	)		(1,346	)
Total notes payable – related party	$	49,964		$	49,919

Senior Revolving Notes, Related Party

On February 15, 2017, Carbon California entered into a Note Purchase Agreement (the “Note Purchase Agreement”) for the issuance and sale of Senior Secured Revolving Notes to Prudential with an initial revolving borrowing capacity of $25.0 million which mature on February 15, 2022 (the “Senior Revolving Notes”). Carbon Energy Corporation is not a guarantor of the Senior Revolving Notes. The closing of the Note Purchase Agreement on February 15, 2017 resulted in the sale and issuance by Carbon California of Senior Revolving Notes in the principal amount of $10.0 million. The maximum principal amount available under the Senior Revolving Notes is based upon the borrowing base attributable to Carbon California’s proved oil and gas reserves which is to be determined at least semi-annually. As of March 31, 2019, the borrowing base was $41.0 million, of which $38.5 million was outstanding.

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Carbon California may elect to incur interest at either (i) 5.50% plus the London interbank offered rate (“LIBOR”) or (ii) 4.50% plus the Prime Rate (which is defined as the interest rate published daily by JPMorgan Chase Bank, N.A.). As of March 31, 2019, the effective borrowing rate for the Senior Revolving Notes was 7.80%. In addition, the Senior Revolving Notes include a commitment fee for any unused amounts at 0.50% as well as an annual administrative fee of $75,000, payable on February 15 each year.

The Senior Revolving Notes are secured by all the assets of Carbon California. The Senior Revolving Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated proved developed production at such time for year one, two and three at a rate of 75%, 65% and 50%, respectively. Carbon California may make principal payments in minimum installments of $500,000. Distributions to equity members are generally restricted.

Carbon California incurred fees directly associated with the issuance of the Senior Revolving Notes and amortizes these fees over the life of the Senior Revolving Notes. The current portion of these fees are included in prepaid expense and deposits and the long-term portion is included in other non-current assets for a combined value of approximately $939,000. For the three months ended March 31, 2019, Carbon California amortized fees of $74,000.

Carbon California may at any time repay the Senior Revolving Notes, in whole or in part, without penalty. Carbon California must pay down Senior Revolving Notes or provide mortgages of additional oil and natural gas properties to the extent that outstanding loans and letters of credit exceed the borrowing base.  

Subordinated Notes, Related Party

On February 15, 2017, Carbon California entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”) with Prudential Capital Energy Partners, L.P. for the issuance and sale of Subordinated Notes due February 15, 2024, bearing interest of 12% per annum (the “Subordinated Notes”). Carbon Energy Corporation is not a guarantor of the Subordinated Notes. The closing of the Securities Purchase Agreement on February 15, 2017 resulted in the sale and issuance by Carbon California of Subordinated Notes in the original principal amount of $10.0 million, all of which remains outstanding as of March 31, 2019.

Prudential received an additional 1,425 Class A Units, representing 5% of total sharing percentage, for the issuance of the Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding Subordinated Notes of $10.0 million. The Company then allocated the non-cash value of the units of approximately $1.3 million, which was recorded as a discount to the Subordinated Notes. As of March 31, 2019, Carbon California has an outstanding discount of approximately $869,000, which is presented net of the Subordinated Notes within Credit facility-related party on the unaudited consolidated balance sheets. During the three months ended March 31, 2019, Carbon California amortized $45,000 associated with the Subordinated Notes.

The Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively.

Prepayment of the Subordinated Notes is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted.

19 

2018 Subordinated Notes, Related Party

On May 1, 2018, Carbon California entered into an agreement with Prudential for the issuance and sale of $3.0 million in Subordinated Notes due February 15, 2024, bearing interest of 12% per annum (the “2018 Subordinated Notes”), of which $3.0 million remains outstanding as of March 31, 2019.

Prudential received 585 Class A Units, representing an approximate 2% additional sharing percentage, for the issuance of the Carbon California 2018 Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding 2018 Subordinated Notes of $3.0 million. The Company then allocated the non-cash value of the units of approximately $490,000, which was recorded as a discount to the 2018 Subordinated Notes. As of March 31, 2019, Carbon California had an outstanding discount of $412,000 associated with these notes, which is presented net of the 2018 Subordinated Notes within Credit facility - related party on the unaudited consolidated balance sheets. During the three months ended March 31, 2019, Carbon California amortized $21,000 associated with the 2018 Subordinated Notes.

The 2018 Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively.

Prepayment of the 2018 Subordinated Notes is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted.

Restrictions and Covenants

The Senior Revolving Notes, Subordinated Notes and 2018 Subordinated Notes contain affirmative and negative covenants that, among other things, limit Carbon California’s ability to (i) incur additional debt; (ii) incur additional liens; (iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distributions on, or repurchases of, equity; (vi) make certain investments; (vii) enter into certain transactions with our affiliates; (viii) enter into sales-leaseback transactions; (ix) make optional or voluntary payments of debt; (x) change the nature of our business; (xi) change our fiscal year to make changes to the accounting treatment or reporting practices; (xii) amend constituent documents; and (xiii) enter into certain hedging transactions.

The affirmative and negative covenants are subject to various exceptions, including basket amounts and acceptable transaction levels. In addition, (i) the Senior Revolving Notes require Carbon California’s compliance, on a consolidated basis, with (A) a maximum Debt/EBITDA ratio of 4.0 to 1.0, stepping down to 3.5 to 1.0 starting with the quarter ending June 30, 2018, (B) a maximum Senior Revolving Notes/EBITDA ratio of 2.5 to 1.0, (C) a minimum interest coverage ratio of 3.0 to 1.0 and (D) a minimum current ratio of 1.0 to 1.0 and (ii) the Subordinated Notes require Carbon California’s compliance, on a consolidated basis, with (A) a maximum Debt/EBITDA ratio of 4.5 to 1.0, stepping down to 4.0 to 1.0 starting with the quarter ending June 30, 2018, (B) a maximum Senior Revolving Notes/EBITDA ratio of 3.0 to 1.0, (C) a minimum interest coverage ratio of 2.5 to 1.0, (D) an asset coverage test whereby indebtedness may not exceed the product of 0.65 times Adjusted PV-10 set forth in the most recent reserve report, (E) maintenance of a minimum borrowing base of $10,000,000 under the Senior Revolving Notes and (F) a minimum current ratio of 0.85 to 1.00.

Note 8 – Income Taxes

We recognize deferred income tax assets and liabilities for the estimated future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. We have net operating loss carryforwards available in certain jurisdictions to reduce future taxable income. Future tax benefits for net operating loss carryforwards are recognized to the extent that realization of these benefits is considered more likely than not. To the extent that available evidence raises doubt about the realization of a deferred income tax asset, a valuation allowance is established.

At March 31, 2019 the Company has established a full valuation allowance against the balance of net deferred tax assets.

Note 9 – Stockholders’ Equity

Authorized and Issued Capital Stock

Effective March 15, 2017 and pursuant to a reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. References to the number of shares and price per share give retroactive effect to the reverse stock split for all periods presented. On June 1, 2018, we amended our charter to increase the number of authorized shares of our common stock from 10.0 million to 35.0 million.

As of March 31, 2019, we had 35.0 million shares of common stock authorized with a par value of $0.01 per share, of which approximately 7.8 million were issued and outstanding, and 1.0 million shares of preferred stock authorized with a par value of $0.01 per share. During the first three months of 2019, the increase in the Company’s issued and outstanding common stock was a result of restricted stock and performance units that vested during the period.

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Carbon Stock Incentive Plans

We have two stock plans, the Carbon 2011 Stock Incentive Plan and the Carbon 2015 Stock Incentive Plan (collectively the “Carbon Plans”). The Carbon Plans were approved by our shareholders and in the aggregate provide for the issuance of approximately 1.1 million shares of common stock to our officers, directors, employees or consultants eligible to receive the awards under the Carbon Plans.

The Carbon Plans provide for the granting of incentive stock options, non-qualified stock options, restricted stock awards, performance awards and phantom stock awards, or a combination of the foregoing, to employees, officers, directors or consultants, provided that only employees may be granted incentive stock options and directors may only be granted restricted stock awards and phantom stock awards.

Restricted Stock

As of March 31, 2019, approximately 649,000 shares of restricted stock have been granted under the terms of the Carbon Plans. Restricted stock awards for employees vest ratably over a three-year service period or cliff vest at the end of a three-year service period. For non-employee directors, the awards vest upon the earlier of a change in control of us or the date their membership on the Board of Directors is terminated other than for cause. During the three months ended March 31, 2019, approximately 40,000 restricted stock units vested.

Compensation costs recognized for these restricted stock grants were approximately $179,000 for the three months ended March 31, 2019. For the three months ended March 31, 2018, we recognized compensation expense of approximately $158,000. As of March 31, 2019, there was approximately $1.2 million unrecognized compensation costs related to these restricted stock grants which we expect to be recognized over the next six years.

Restricted Performance Units

As of March 31, 2019, approximately 621,000 shares of performance units have been granted under the terms of the Carbon Plans. Performance units represent a contractual right to receive one share of our common stock subject to the terms and conditions of the agreements, including the achievement of certain performance measures relative to a defined peer group or the growth of certain performance measures over a defined period of time as well as, in some cases, continued service requirements.

We account for the performance units granted during 2015 through 2018 at their fair value determined at the date of grant, which were $8.00, $5.40, $7.20 and $9.80 per share, respectively. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At March 31, 2019, we estimated that none of the performance units granted in 2017 and 2018 would vest, and, accordingly, no compensation cost has been recorded for these performance units. We estimated that it was probable that the performance units granted in 2015 and 2016 would vest and therefore compensation costs of approximately $43,000 and $135,000 related to these performance units were recognized for the three months ended March 31, 2019 and 2018, respectively. As of March 31, 2019, compensation costs related to the performance units granted in 2015 and 2016 have been fully recognized. As of March 31, 2019, if change in control and other performance provisions pursuant to the terms and conditions of these award agreements are met in full, the estimated unrecognized compensation cost related to the performance units granted in 2012, 2017 and 2018 would be approximately $2.7 million.

Preferred Stock

Series B Convertible Preferred Stock - Related Party

In connection with the closing of the Seneca Acquisition, we raised $5.0 million through the issuance of 50,000 shares of Preferred Stock to Yorktown. The Preferred Stock converts into common stock at the election of the holder or will automatically convert into shares of our common stock upon completion of a qualifying equity financing event. The number of shares of common stock issuable upon conversion is dependent upon the price per share of common stock issued in connection with any such qualifying equity financing but has a floor conversion price equal to $8.00 per share. The conversion ratio at which the Preferred Stock will convert into common stock is equal to an amount per share of $100 plus all accrued but unpaid dividends payable in respect thereof divided by the greater of (i) $8.00 per share or (ii) the price that is 15% less than the lowest price per share of shares sold to the public in the next equity financing. Using the floor of $8.00 per share would yield 12.5 shares of common stock for every unit of Preferred Stock. The conversion price will be proportionately increased or decreased to reflect changes to the outstanding shares of common stock, such as the result of a combination, reclassification, subdivision, stock split, stock dividend or other similar transaction involving the common stock. Additionally, after the third anniversary of the issuance of the Preferred Stock, we have the option to redeem the shares for cash.

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The Preferred Stock accrues cash dividends at a rate of six percent (6%) of the initial issue price of $100 per share per annum. The holders of the Preferred Stock are entitled to the same number of votes of common stock that such share of Preferred Stock would represent on an as converted basis. The holders of the Preferred Stock receive liquidation preference based on the initial issue price of $100 per share plus a preferred return over common stock holders and the holders of any junior ranking stock. As of March 31, 2019, the preferred return was approximately $299,000.

We apply the guidance in ASC 480 “Distinguishing Liabilities from Equity” when determining the classification and measurement of the Preferred Stock. The Preferred Stock does not feature any redemption rights within the holders’ control or conditional redemption features not within our control as of March 31, 2019. Accordingly, the Preferred Stock is presented as a component of consolidated stockholders’ equity.

We have evaluated the Preferred Stock in accordance with ASC 815, “Derivatives and Hedging”, including consideration of embedded derivatives requiring bifurcation. The issuance of the Preferred Stock could generate a beneficial conversion feature (“BCF”), which arises when a debt or equity security is issued with an embedded conversion option that is beneficial to the investor or in the money at inception because the conversion option has an effective strike price that is less than the market price of the underlying stock at the commitment date. Based on the conversion terms and the price at the commitment date, we determined that a BCF was required to be recorded related to the voluntary conversion option by the holder as of March 31, 2019. We recorded the BCF as a reduction of retained earnings and an increase to Additional Paid in Capital (“APIC”) of $1.1 million, which is based on the difference between the floor price of $8.00 and our stock price as of the commitment date multiplied by the number of shares to be issued. We are also required to evaluate a contingent BCF for the automatic conversion feature, but in accordance with ASC 470, “Debt”, we will not record the effect of the BCF until the contingency is resolved.

Note 10 – Revenue Recognition

Revenue from Contracts with Customers

The Company recognizes revenue in accordance with FASB ASC Topic 606 – Revenue Recognition (“ASC 606”).  Revenue is recognized when it satisfies a performance obligation by transferring control over a product to a customer. Revenue is measured based on the consideration we expect to receive in exchange for those products. Revenues from contracts with customers are recorded on the unaudited consolidated statements of operations based on the type of product being sold.

Performance Obligations and Significant Judgments

We sell oil and natural gas products in the United States through a single reportable segment. We primarily sell products within two regions of the United States: Appalachian Basin and Ventura Basin. We enter into contracts that generally include one type of distinct product in variable quantities and priced based on a specific index related to the type of product. Most of our contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions.

The oil and natural gas is typically sold in an unprocessed state to third party purchasers. We recognize revenue based on the net proceeds received from the purchaser when control of the oil or natural gas passes to the purchaser. For oil sales, control is typically transferred to the purchaser upon receipt at the wellhead or a contractually agreed upon delivery point. Under our natural gas contracts with purchasers, control transfers upon delivery at the wellhead or the inlet of the purchaser’s system. For our other natural gas contracts, control transfers upon delivery to the inlet or to a contractually agreed upon delivery point.

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Transfer of control drives the presentation of transportation and gathering costs within the accompanying unaudited consolidated statements of operations. Transportation and gathering costs incurred prior to control transfer are recorded within the transportation and gathering expense line item on the accompanying unaudited consolidated statements of operations, while transportation and gathering costs incurred subsequent to control transfer are recognized as a reduction to the related revenue.

A portion of our product sales are short-term in nature. For those contracts, we use the practical expedient in ASC 606 exempting us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606 which states we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to an unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore, future volumes are unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. We have no unsatisfied performance obligations at the end of each reporting period.

We do not believe that significant judgments are required with respect to the determination of the transaction price, including any variable consideration identified. There is a low level of uncertainty due to the precision of measurement and use of index-based pricing with predictable differentials. Additionally, any variable consideration identified is not constrained.

Disaggregation of Revenues

In the following tables, revenue for the three months ended March 31, 2019, is disaggregated by primary region within the United States and major product line. As noted above, we operate as one reportable segment.

For the three months ended March 31, 2019:

(in thousands)
Type	Appalachian Basin		Ventura Basin		Total
Natural gas sales	$	18,792	$	524	$	19,316
Natural gas liquids sales		-		247		247
Oil sales		1,537		7,452		8,989
Transportation and handling		734		-		734
Marketing gas sales		4,944		-		4,944
Total revenue	$	26,007	$	8,223	$	34,230

Contract Balances

Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not typically give rise to contract assets or liabilities under ASC 606.

Prior Period Performance Obligations

We record revenue in the month production is delivered to the purchaser, but settlement statements may not be received until 30 to 90 days after the month of production. As such, we estimate the production delivered and the related pricing. Any differences between our initial estimates and actuals are recorded in the month payment is received from the customer. These differences have not historically been material. For the three months ended March 31, 2019, revenue recognized in the reporting period related to prior period performance obligations is immaterial.

The estimated revenue is recorded within Accounts receivable – Revenue on the unaudited consolidated balance sheets.

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Note 11 – Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities at March 31, 2019 and December 31, 2018 consist of the following:

(in thousands)	March 31, 2019		December 31, 2018
Accounts payable	$	6,064	$	7,670
Oil and gas revenue suspense		2,766		2,675
Gathering and transportation payables		1,228		1,774
Production taxes payable		2,411		1,860
Accrued operating costs		2,431		3,155
Accrued ad valorem taxes – current		3,731		3,474
Accrued general and administrative expenses		2,217		3,111
Accrued asset retirement obligation – current		3,392		3,099
Accrued interest		1,543		955
Accrued gas purchases		2,959		5,440
Other liabilities		1,278		1,603
Total accounts payable and accrued liabilities	$	30,020	$	34,816

Note 12 – Fair Value Measurements

Authoritative guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of us. Unobservable inputs are inputs that reflect our assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

Level 1: Quoted prices are available in active markets for identical assets or liabilities;

Level 2: Quoted prices in active markets for similar assets or liabilities that are observable for the asset or liability; or

Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our policy is to recognize transfers in and/or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. We have consistently applied the valuation techniques discussed below for all periods presented.

The following table presents our financial assets and liabilities that were accounted for at fair value on a recurring basis by level within the fair value hierarchy:

(in thousands)	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Total
March 31, 2019
Assets:
Commodity derivatives	$	-	$	147	$	-	$	147
Liabilities:
Commodity derivatives	$	-	$	1,975	$	-	$	1,975
December 31, 2018
Asset:
Commodity derivatives	$	-	$	7,022	$	-	$	7,022

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Commodity Derivative

As of March 31, 2019, our commodity derivative financial instruments are comprised of natural gas and oil swaps and costless collars. The fair values of these agreements are determined under an income valuation technique. The valuation model requires a variety of inputs, including contractual terms, published forward prices, volatilities for options and discount rates, as appropriate. Our estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, our credit worthiness and the time value of money. The consideration of these factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. All the significant inputs are observable, either directly or indirectly; therefore, our derivative instruments are included within the Level 2 fair value hierarchy. The counterparty for all our outstanding commodity derivative financial instruments as of March 31, 2019, is BP Energy Company.

Assets and Liabilities Measured and Recorded at Fair Value on a Non-Recurring Basis

The fair value of each of the following assets and liabilities measured and recorded at fair value on a non-recurring basis are based on unobservable pricing inputs and therefore, are included within the Level 3 fair value hierarchy.

The fair value of the non-controlling interest in the partnerships we are required to consolidate was determined based on the net discounted cash flows of the proved developed producing properties attributable to the non-controlling interests in these partnerships.

We assume, at times, certain firm transportation contracts as part of our acquisitions of oil and natural gas properties. The fair value of the firm transportation contract obligations was determined based upon the contractual obligations assumed by us and discounted based upon our effective borrowing rate. These contractual obligations are reduced on a monthly basis as we pay these firm transportation obligations in the future.

The fair value measurements associated with the assets acquired and liabilities assumed in the business combination for the OIE Membership Acquisition of Carbon Appalachia are outlined within Note 3.

Debt Discount

The fair value of the debt discount from the 1,425 and 585 additional Class A Units issued in connection with the Subordinated Notes and 2018 Subordinated Notes was $1.3 million and $490,000, respectively. The debt discount was a Level 3 fair value assessment and was based on the relative fair value of Class A Units. Class A Units were issued contemporaneously at $1,000 per Class A Unit.

Asset Retirement Obligation

The fair value of our asset retirement obligation liability is recorded in the period in which it is incurred or assumed by taking into account the cost of abandoning oil and gas wells ranging from $20,000 to $45,000, which is based on our historical experience and industry expectations for similar work; the estimated timing of reclamation ranging from one to 75 years based on estimates from reserve engineers; an inflation rate between 1.52% to 2.79%; and a credit adjusted risk-free rate between 3.28% to 8.27%, which takes into account our credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs (see Note 3). During the three month period ended March 31, 2019, we did not record any additions to asset retirement obligations. We use the income valuation technique to estimate the fair value of asset retirement obligations using the amounts and timing of expected future dismantlement costs, credit-adjusted risk-free rates and time value of money.

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Class B Units

We received Class B units from Carbon California and Carbon Appalachia as part of the entry into the Carbon California LLC Agreement and Carbon Appalachia LLC Agreement, respectively. We estimated the fair value of the Class B units, in each case, by utilizing the assistance of third-party valuation specialists. The fair values were based upon enterprise values derived from inputs including estimated future production rates, future commodity prices including price differentials as of the dates of closing, future operating and development costs and comparable market participants.

Note 13 – Commodity Derivatives

We historically use commodity-based derivative contracts to manage exposures to commodity price on a portion of our oil and natural gas production. We do not hold or issue derivative financial instruments for speculative or trading purposes. We also have entered into, on occasion, oil and natural gas physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. These contracts are not recorded at fair value in the unaudited condensed consolidated financial statements.

Pursuant to the terms of our credit facilities with LegacyTexas Bank and Prudential, we have entered into swap and costless collar derivative agreements to hedge a portion of our oil and natural gas production through 2021. As of March 31, 2019, these derivative agreements consisted of the following:

	Natural Gas Swaps				Natural Gas Collars
			Weighted Average				Weighted Average Price
Year	MMBtu		Price (a)		MMBtu		Range (a)
2019		11,762,000,	$	2.82		374,000	$	2.60 – $3.03
2020		12,433,000	$	2.73		1,018,000	$	2.50 – $2.70
2021		6,448,000	$	2.58		-	$	-

	Oil Swaps								Oil Collars
Year	WTI Bbl		Weighted Average  Price (b)		Brent Bbl		Weighted Average Price (c)		WTI Bbl		Weighted  Average Price (b)		Brent Bbl		Weighted  Average Price (c)
2019		180,775	$	53.46		121,079	$	66.93		-		-		29,800	$	47.00 - $75.00
2020		121,147	$	55.37		151,982	$	66.03		18,000	$	47.00 - $60.15		37,400	$	47.00 - $75.00
2021		-	$	-		86,341	$	67.12		30,000	$	47.00 - $60.15		98,000	$	47.00 - $75.00

*	Includes 100% of Carbon California’s outstanding derivative hedges at March 31, 2019, and not our proportionate share.
(a)	NYMEX Henry Hub Natural Gas futures contract for the respective period.
(b)	NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective period.
(c)	Brent future contracts for the respective period.

For our swap instruments, we receive a fixed price for the hedged commodity and pay a floating price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. Costless collars are designed to establish floor and ceiling prices on anticipated future oil and gas production. The ceiling establishes a maximum price that the Company will receive for the volumes under contract, while the floor establishes a minimum price.

The following table summarizes the fair value of the derivatives recorded in the unaudited consolidated balance sheets.

These derivative instruments are not designated as cash flow hedging instruments for accounting purposes:

(in thousands)	March 31, 2019		December 31, 2018
Commodity derivative contracts:
Commodity derivative asset	$	-	$	3,517
Commodity derivative asset – non-current	$	147	$	3,505
Commodity derivative liability	$	1,657	$	-
Commodity derivative liability – non-current	$	318	$	-

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The table below summarizes the commodity settlements and unrealized gains and losses related to the Company’s derivative instruments for the three months ended March 31, 2019 and 2018. These commodity derivative settlements and unrealized gains and losses are recorded and included in commodity derivative income or loss in the accompanying unaudited consolidated statements of operations. 

	Three Months Ended March 31,
(in thousands)	2019			2018
Commodity derivative contracts:
Settlement losses	$	(456	)	$	(377	)
Unrealized losses		(8,850	)		(249	)
Total settlement and unrealized losses, net	$	(9,306	)	$	(626	)

Commodity derivative settlement gains and losses are included in cash flows from operating activities in our unaudited consolidated statements of cash flows.

The counterparty in all of our derivative instruments is BP Energy Company. We have entered into ISDA Master Agreements with BP Energy Company that establishes standard terms for the derivative contracts and inter-creditor agreements with LegacyTexas Bank, Prudential and BP Energy Company whereby any credit exposure related to the derivative contracts entered into by us and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facilities.

We net our derivative instrument fair value amounts executed with BP Energy Company pursuant to ISDA master agreements, which provides for the net settlement over the term of the contracts and in the event of default or termination of the contracts. The following table summarizes the location and fair value amounts of all derivative instruments in the unaudited consolidated balance sheet, as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited consolidated balance sheet as of March 31, 2019.

						Net
	Gross					Recognized
	Recognized		Gross			Fair Value
	Assets/		Amounts			Assets/
Balance Sheet Classification (in thousands)	Liabilities		Offset			Liabilities
Commodity derivative assets:
Commodity derivative asset	$	1,063	$	(1,063	)	$	-
Commodity derivative asset – non-current		2,049		(1,902	)		147
Total derivative assets	$	3,112	$	(2,965	)	$	147
Commodity derivative liabilities:
Commodity derivative liability	$	2,720	$	(1,063	)	$	(1,657	)
Commodity derivative liability – non-current		2,220		(1,902	)		(318	)
Total derivative liabilities	$	4,940	$	(2,965	)	$	(1,975	)

Due to the volatility of oil and natural gas prices, the estimated fair value of our derivatives are subject to fluctuations from period to period. 

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Note 14 – Leases

On January 1, 2019, we adopted ASC 842. Results for reporting periods beginning January 1, 2019 are presented in accordance with ASC 842, while prior period amounts are reported in accordance with FASB ASC Topic 840 – Leases. On January 1, 2019, we recognized approximately $7.7 million in right-of-use assets and approximately $7.7 million in lease liabilities, representing the present value of minimum payment obligations associated with compressor, vehicle, and office space operating leases with non-cancellable lease terms in excess of one year. We do not have any finance leases, nor are we the lessor in any leasing arrangements. We have elected certain practical expedients available under ASC 842 including those that permit us to (i) account for lease and non-lease components in our contracts as a single lease component for all asset classes; (ii) not evaluate existing and expired land easements; (iii) not apply the recognition requirements of ASC 842 to leases with a lease term of twelve months or less; and (iv) retain our existing lease assessment and classification. As such, there was no cumulative-effect adjustment to retained earnings required at January 1, 2019. Additionally, the Company has elected the short-term lease recognition exemption for all classes of underlying assets and therefore, leases with a term of one year or less will not be recognized on the unaudited consolidated balance sheet. 

The lease amounts disclosed herein are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners, and our net share of these costs, once paid, are included in lease operating expenses, pipeline operating expenses or general and administrative expenses, as applicable.

During the three months ended March 31, 2019, we did not acquire any right-of-use assets or incur any lease liabilities. Our right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet at $7.3 million as of March 31, 2019. All leases recognized on our unaudited consolidated balance sheet are classified as operating leases, which include leases related to the asset classes reflected in the table below:

(in thousands)	Right-of-Use Assets		Lease Liability
Compressors	$	4,178	$	4,178
Corporate leases		2,433		2,438
Vehicles		645		645
Total	$	7,256	$	7,261

We recognize lease expense on a straight-line basis excluding short-term and variable lease payments which are recognized as incurred. Short-term lease cost represents payments for leases with a lease term of one year or less, excluding leases with a term of one month or less. Short-term leases include certain compressors and vehicles that have a non-cancellable lease term of less than one year.

The following table summarizes the components of our gross operating lease costs incurred during the three months ended March 31, 2019:

(in thousands)	Three Months Ended March 31, 2019
Operating lease cost	$	531
Short-term lease cost		161
Total lease cost	$	692

We do not have any leases with an implicit interest rate that can be readily determined. As a result, we calculate collateralized incremental borrowing rates to use as discount rates. We utilize the benchmark rates defined in our credit facilities, and adjust for facility utilization and term considerations, to establish collateralized incremental borrowing rates. Refer to Note 7 for additional information on our credit facilities.

Our weighted-average lease term and discount rate used are as follows:

(in thousands)	Three Months Ended March 31, 2019
Weighted-average lease term (years)		4.3
Weighted-average discount rate		6.34	%

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The following table summarizes supplemental cash flow information related to leases:

Cash paid for amounts included in measurement of lease liabilities (in thousands)	Three Months Ended March 31, 2019
Operating cash flows for operating leases	$	526

Minimum future commitments by year for our long-term operating leases as of March 31, 2019 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet as follows:

(in thousands)	Amount
Remainder of 2019	$	1,535
2020		1,946
2021		1,889
2022		1,718
2023		1,222
Thereafter		11
Total lease payments	$	8,321
Less: imputed interest		(1,060	)
Total lease liability	$	7,261

Note 15 – Commitments and Contingencies

We have entered into employment agreements with certain of our executives and officers. The term of the agreements generally ranges from one to two years and provides for renewal provisions in one-year increments thereafter. The agreements provide for, among other items, severance and continuation of benefit payments upon termination of employment or certain change of control events.

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We have entered into non-current firm transportation contracts to ensure the transport for certain of our gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts at March 31, 2019 are summarized in the table below.

Period	Dekatherms per day		Demand Charges
Apr 2019 – Mar 2020		58,871	$	0.20 - 0.62
Apr 2020 – May 2020		57,791	$	0.20 - 0.56
Jun 2020 – Oct 2020		56,641	$	0.20 - 0.56
Nov 2020 – Aug 2022		50,341	$	0.20 - 0.56
Sep 2022 – May 2027		30,990	$	0.20 - 0.21
Jun 2027 – May 2036		1,000	$	0.20

As of March 31, 2019, the remaining commitment related to the firm transportation contracts assumed in the EXCO Acquisition in 2016 and OIE Membership Acquisition is $17.8 million and reflected in the Company’s unaudited consolidated balance sheet. The fair values of these firm transportation obligations were determined based upon the contractual obligations assumed by the Company and discounted based upon the Company’s effective borrowing rate. These contractual obligations are being reduced monthly as the Company pays these firm transportation obligations in the future.

Natural gas processing agreement

We have entered into an initial five-year gas processing agreement. We have an option to extend the term of the agreement by another five years. The related demand charges for volume commitments over the remaining term of the agreement at March 31, 2019 are approximately $1.8 million per year. We will pay a processing fee of $2.50 per MCF for the term of the agreement, with a minimum annual volume commitment of 720,000 MCF.

Capital Commitments

As of March 31, 2019, we had no capital commitments associated with Carbon California. 

Note 16 – Supplemental Cash Flow Disclosure

Supplemental cash flow disclosures for the three months ended March 31, 2019 and 2018 are presented below:

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

Note 17 – Subsequent Events

We evaluated activities from March 31, 2019, to the date these financial statements were available for issuance. We believe there are no subsequent events requiring recognition or disclosure.

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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion includes forward-looking statements about our business, financial condition and results of operations, including discussions about management’s expectations for our business. These statements represent projections, beliefs and expectations based on current circumstances and conditions, and you should not construe these statements either as assurances of performance or as promises of a given course of action. Instead, various known and unknown factors may cause our actual performance and management’s actions to vary, and the results of these variances may be both material and adverse. A description of material factors known to us that may cause our results to vary, or may cause management to deviate from its current plans and expectations, is set forth under “Risk Factors.” The following discussion should be read in conjunction with “Forward-Looking Statements,” “Risk Factors” and our unaudited condensed consolidated financial statements, including the notes thereto appearing elsewhere in this Quarterly Report on Form 10-Q and the information included or incorporated by reference in the Company’s 2018 Annual Report on Form 10-K.

General Overview

Carbon 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. We currently develop and operate oil and gas properties in the Appalachian Basin in Kentucky, Ohio, Tennessee, Virginia and West Virginia, in the Illinois Basin in Illinois and Indiana, and in the Ventura Basin in California through our majority-owned subsidiaries. We own 100% of the outstanding interests of Carbon Appalachia, and Nytis Exploration (USA) Inc., a Delaware corporation (“Nytis USA”), which in turn owns 98.1% of Nytis Exploration Company LLC, a Delaware limited liability company (“Nytis LLC”). Nytis LLC holds interests in our operating subsidiaries, which include 46 consolidated partnerships and 18 non-consolidated partnerships. We own 53.92% of Carbon California which consolidates as a majority-owned subsidiary. We focus on conventional and unconventional reservoirs, including shale, tight sands and coalbed methane. Our executive offices are in Denver, Colorado and we maintain offices in Lexington, Kentucky, and Santa Paula, California from which we conduct our oil and gas operations.

At March 31, 2019, our proved developed reserves were comprised of 22% oil and natural gas liquids (“NGL”) and 78% natural gas. Our current capital expenditure program is focused on the acquisition and development of oil and natural gas properties in areas where we currently operate. We believe that our asset and lease position, combined with our low operating expense structure and technical expertise, provides us with a portfolio of opportunities for the development of our oil and natural gas properties. Our growth plan is centered on the following activities:

● Acquire and develop oil and gas producing properties that deliver attractive risk adjusted rates of return, provide for field development projects, and complement our existing asset base; and

● Develop, optimize and maintain a portfolio of low risk, long-lived oil and natural gas properties that provide stable cash flows and attractive risk adjusted rates of return.  

Factors That Significantly Affect Our Financial Condition and Results of Operations

Our revenue, profitability and future growth rate depend on many factors which are beyond our control, including but not limited to, economic, political and regulatory developments and competition from other industry participants. Our financial results are sensitive to fluctuations in oil and natural gas prices. Oil and gas prices historically have been volatile and may fluctuate widely in the future due to a variety of factors, including but not limited to, prevailing economic conditions, supply and demand of hydrocarbons in the marketplace, actions by speculators, and geopolitical events such as wars or natural disasters. The following table highlights the quarterly average of NYMEX oil and natural gas prices for the last eight calendar quarters:

	2017						2018								2019
	Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1
Oil (Bbl)	$	48.29	$	48.19	$	55.39	$	62.89	$	67.90	$	69.50	$	58.83	$	54.85
Natural Gas (MMBtu)	$	3.09	$	2.89	$	2.87	$	3.13	$	2.77	$	2.88	$	3.62	$	2.99

Low oil, NGL and natural gas prices may decrease our revenues, may reduce the amount of oil, NGL and natural gas that we can produce economically and potentially lower our oil and natural gas reserves. Our estimated proved reserves may decrease if the economic life of underlying producing wells are shortened as a result of lower oil, NGL and natural gas prices. A substantial or extended decline in oil, NGL or natural gas prices may result in future impairments of our proved reserves and may materially and adversely affect our future business, financial condition, cash flows, results of operations or liquidity. Lower oil, NGL and natural gas prices may also reduce the amount of borrowing base under our bank credit facilities, which are determined at the discretion of our lender and may make it more difficult to comply with the covenants and other restrictions under our bank credit facilities.

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We use the full cost method of accounting for our oil and gas properties and performs a ceiling test quarterly. The ceiling calculation utilizes a rolling 12 month average commodity price. We did not recognize an impairment for the three months ended March 31, 2019 and 2018.

Future write downs or impairments, if any, are difficult to predict and will depend not only on commodity prices, but also other factors that include, but are not limited to, incremental proved reserves that may be added each period, revisions to previous reserve estimates, capital expenditures and operating costs. There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in subsequent periods.

Impairment charges do not affect cash flows from operating activities but do adversely affect net income and stockholders’ equity. An extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, cash flows and liquidity.

We use commodity derivative instruments, such as swaps and costless collars, to manage and reduce price volatility and other market risks associated with our production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases.

Future property acquisitions or dispositions could have a material impact on our financial condition and results of operations by increasing or decreasing our reserves, production and revenues as well as expenses and future capital expenditures. We currently anticipate that we would finance any future acquisitions with available borrowings under our credit facilities, sales of properties or the issuance of additional equity or debt.

Operational Highlights

During 2017 and 2018, and the first quarter of 2019, we concentrated our efforts on the acquisition and development of producing properties through the acquisitions consummated by Carbon California and Carbon Appalachia. We completed the purchase of Old Ironsides’ interests in Carbon Appalachia, resulting in ownership of 100% of Carbon Appalachia. Our field development activities have consisted principally of oil-related remediation, and return to production and recompletion projects in California. Since closing these acquisitions, we have focused on operating efficiencies and reduction of operating expenses, optimization of natural gas gathering and compression facilities, greater flexibility in moving our production to markets with more favorable pricing, and the identification of development project opportunities to provide more efficient and lower cost operations.

As of March 31, 2019, we owned working interests in approximately 8,800 gross wells (7,100 net), royalty interests located primarily in California, Illinois, Indiana, Kentucky, Ohio, Tennessee, Virginia, and West Virginia and had leasehold positions in approximately 336,000 net developed acres and approximately 1,317,900 net undeveloped acres. Approximately 68% of the undeveloped acreage is held by production and of the remaining undeveloped acreage, approximately 80% have lease terms of greater than five years remaining in the primary term or contractual extension periods.

Our oil and natural gas assets contain an inventory of field development projects which may provide growth opportunities when oil and natural gas commodity prices warrant capital investment to develop the properties.

Recent Developments and Factors Affecting Comparability

We are continually evaluating producing property and land acquisition opportunities in our operating area which would expand our operations and provide attractive risk adjusted rates of return on invested capital. The drilling of additional oil and natural gas wells is contingent on our expectation of future oil and natural gas prices.

Investment in Affiliates

Carbon Appalachia

Carbon Appalachia was formed in 2016 by us, Yorktown and Old Ironsides to acquire producing assets in the Appalachian Basin in Kentucky, Tennessee, Virginia and West Virginia. Carbon Appalachia was accounted for as an equity method investment from April 2017 until December 31, 2018, upon the closing of the OIE Membership Acquisition, which required us to consolidate Carbon Appalachia for financial reporting purposes.

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In December 2018, we completed the acquisition of all of the Class A Units of Carbon Appalachia owned by Old Ironsides for a purchase price of $58.1 million subject to customary and standard purchase price adjustments (“OIE Membership Acquisition”). As a result of the OIE Membership Acquisition, we now hold all of the issued and outstanding ownership interests of Carbon Appalachia, along with its direct and indirect subsidiaries (Carbon Appalachia Group, LLC, Carbon Tennessee Mining Company, LLC, Carbon Appalachia Enterprises, LLC, Carbon West Virginia Company, LLC, Cranberry Pipeline Corporation, Knox Energy, LLC, Coalfield Pipeline Company and Appalachia Gas Services Company, LLC). As a result, we consolidate Carbon Appalachia for financial reporting purposes.

Outlined below is a summary of (i) ownership changes to Carbon Appalachia since its formation, (ii) our resulting percent ownership of Class A Units, which represents the voting interest in Carbon Appalachia, and (iii) our proportionate share in Carbon Appalachia after giving effect of all classes of ownership interests.

Timing	Ownership Changes	Resulting Class A Units (%)			Proportionate Share (%)
April 2017	Formation: $0.24 million capital contribution		2.00	%		2.98	%
August 2017	$3.71 million capital contribution		15.20	%		16.04	%
September 2017	$2.92 million capital contribution		18.55	%		19.37	%
November 2017	Warrant exercise		26.50	%		27.24	%
December 2018	OIE Membership Acquisition		100.00	%		100.00	%

Carbon California

Carbon California was formed in 2016 by us, Yorktown and Prudential to acquire producing assets in the Ventura Basin in California. Carbon California was accounted for as an equity method investment from February 2017 until January 31, 2018, upon the exercise of the California Warrant, which required us to consolidate Carbon California for financial reporting purposes as of February 1, 2018.

Outlined below is a summary of (i) ownership changes to Carbon California since its formation, (ii) our resulting percent ownership of Class A Units, and (iii) our proportionate share in Carbon California after giving effect of all classes of ownership interests.

Timing	Ownership Changes	Resulting Class A Units (%)			Proportionate Share (%)
February 2017	Formation		0.00	%		17.81	%
February 2018	Warrant exercise		46.96	%		56.41	%
May 2018	$5.0 million capital contribution		47.05	%		53.92	%

Recent Acquisitions

When Carbon California makes acquisitions, we contribute our pro rata equity portion of the purchase price to fund such acquisitions. In 2018, we contributed an aggregate of $5.0 million to Carbon California in connection with Carbon California’s acquisition activities.

When Carbon Appalachia made acquisitions (prior to the OIE Membership Acquisition described below), we contributed our pro rata equity portion of the purchase price to fund such acquisitions. During 2018, we did not contribute any funds to Carbon Appalachia.

While we made other non-material acquisitions that are not specifically listed, the acquisitions described below most meaningfully affect our financial condition.

● In December 2018, we acquired all of the Class A Units of Carbon Appalachia owned by Old Ironsides for a purchase price of $58.1 million, subject to purchase price adjustments (“OIE Membership Acquisition”). As a result of the OIE Membership Acquisition, we now hold all of the issued and outstanding ownership interests of Carbon Appalachia, along with its direct and indirect subsidiaries (Carbon Appalachia Group, LLC, Carbon Tennessee Mining Company, LLC, Carbon Appalachia Enterprises, LLC, Carbon West Virginia Company, LLC, Cranberry Pipeline Corporation, Knox Energy, LLC, Coalfield Pipeline Company and Appalachia Gas Services Company, LLC). The acquisition was funded with cash, debt and the issuance of notes to Old Ironsides.

● 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 the associated mineral interests in the Appalachian Basin for a purchase price of $3.0 million, subject to customary and standard purchase price adjustments (the “Liberty Acquisition”).  The Liberty Acquisition increased our working interest in the acquired wells from 60% to 100%.  The Liberty Acquisition was funded through borrowings under our previous credit facility. The Liberty Acquisition is accounted for as a non-significant asset acquisition.

● In May 2018, but effective as of October 1, 2017, Carbon California acquired 332 operated and one non-operated oil wells covering approximately 6,800 gross acres (6,600 net), and fee interests in and to certain lands, situated in the Ventura Basin, together with associated wells, pipelines, facilities, equipment and other property rights for a purchase price of $43.0 million, subject to customary and standard purchase price adjustments, from Seneca Resources Corporation (the “Seneca Acquisition”). We contributed approximately $5.0 million to Carbon California to fund our portion of the purchase price with the remainder funded by Prudential and debt. We raised our $5.0 million through the issuance of 50,000 shares of Series B Convertible Preferred Stock, par value $0.01 per share (the “Preferred Stock”), to Yorktown.

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Increase in Authorized Shares of Common Stock

On June 1, 2018, we increased the number of authorized shares of our common stock from 10,000,000 to 35,000,000.

Preferred Stock Issuance to Yorktown

In connection with the closing of the Seneca Acquisition, we raised $5.0 million through the issuance of 50,000 shares of Preferred Stock to Yorktown. See Note 9 to the unaudited condensed consolidated financial statements.

Principal Components of Our Cost Structure

● Lease operating expenses. Lease operating expenses are costs incurred to bring oil and natural gas out of the ground, together with the costs incurred to maintain our producing properties. Such costs include maintenance, repairs and workover expenses related to our oil and natural gas properties.

● Pipeline operating expenses. Pipeline operating expenses are costs incurred to accept, transport and deliver gas across our midstream assets.

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● Transportation and gathering costs. Transportation and gathering costs are incurred to bring oil and natural gas to market. Gathering refers to the utilization of low pressure pipelines to move the oil and natural gas from the wellhead into a transportation pipeline, or in case of oil, into a tank battery from which sales of oil are made.

● Production and property taxes.  Production taxes consist of severance and property taxes and are paid on oil and natural gas produced based on a percentage of market prices or at fixed rates established by federal, state or local taxing authorities.

● Marketing gas purchases.  Marketing gas purchases consist of third-party purchases of gas associated with our midstream operations.

● Depreciation, amortization and impairment. We use the full cost method of accounting for oil and gas properties. All costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. We perform a quarterly ceiling test based on average first-of-the-month prices during the twelve-month period prior to the reporting date. The full cost ceiling test is a limitation on capitalized costs prescribed by the SEC. The ceiling test is not a fair value-based measurement; rather, it is a standardized mathematical calculation that compares the net capitalized costs of our full cost pool to estimated discounted cash flows. Should the net capitalized cost exceed the sum of the estimated discounted cash flows, a ceiling test write-down would be recognized to the extent of the excess. For the three months ended March 31, 2019 and 2018, we did not incur a ceiling test impairment.

● Depletion. Depletion is calculated using capitalized costs in the full cost pool, including estimated asset retirement costs and estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values and depleted based on a unit-of-production method.

● General and administrative expense.  General and administrative expense includes payroll and benefits for our corporate staff, non-cash stock based compensation, costs of maintaining our offices, costs of managing our production, development and acquisition operations, franchise taxes, audit, tax, legal and other professional fees and legal compliance. Certain of these costs are recovered as management reimbursements in place with Carbon California and, prior to the completion of the OIE Membership Acquisition on December 31, 2018, Carbon Appalachia. In 2018, we expensed costs in preparation of an equity raise that we do not believe is likely to occur in the short term.

● Interest expense.  We finance a portion of our working capital requirements for drilling and completion activities and acquisitions with borrowings under our bank credit facilities. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.

● Income tax expense.  We are subject to state and federal income taxes but typically have not been in a tax paying position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs (“IDC”) and net operating loss (“NOL”) carryforwards. We pay alternative minimum tax, state income or franchise taxes where IDC or NOL deductions do not exceed taxable income or where state income or franchise taxes are determined on another basis. As of December 31, 2018, we have NOL carryforwards of approximately $29.2 million available to reduce future years’ federal taxable income. Federal NOLs incurred through 2017 expire in various years through 2037 while the NOLs incurred during 2018 and in future years will never expire. As of December 31, 2018, we have various state NOL carryforwards available to reduce future years’ state taxable income, which are dependent on apportionment percentages and state laws that can change from year to year and impact the amount of such carryforwards. These state NOL carryforwards will expire in the future based upon each jurisdiction’s specific law surrounding NOL carry forwards.

In 2017, the Tax Cuts and Jobs Act (“TCJA”) was enacted. The TCJA significantly changes the U.S. corporate tax law by, among other things, lowering the U.S. corporate income tax rate from 35% to 21% beginning in January 2018. FASB ASC Topic 740, Income Taxes, requires companies to recognize the impact of the changes in tax law in the period of enactment.

Other provisions of the TCJA effective in 2018 that may impact income taxes include (i) a limitation on the current deductibility of interest expense in excess of 30% of adjusted taxable income, (ii) a limitation on the usage of NOLs generated after 2017 to 80% of taxable income, (iii) the inclusion of performance based compensation in determining the excessive compensation limitation, and (iv) the unlimited carryforward of NOLs.

Results of Operations

Three Months Ended March 31, 2019 Compared to Three Months Ended March 31, 2018

The following discussion and analysis relates to items that have affected our results of operations for the three months ended March 31, 2019 and 2018. The following table sets forth, for the periods presented, selected historical unaudited consolidated statements of operations and production data. The information contained in the table below should be read in conjunction with the Company’s unaudited condensed consolidated financial statements and notes thereto and the information under “Forward Looking Statements” below.

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	Three Months Ended
	March 31,						Percent
(in thousands except production and per unit data)	2019			2018 (1)			Change
Revenue:
Natural gas sales	$	19,316		$	3,939			390	%
Natural gas liquids sales		247			163			51	%
Oil sales		8,989			2,983			201	%
Transportation and handling		734			-			*
Marketing gas sales		4,944			-			*
Commodity derivative loss		(9,306	)		(626	)		1387	%
Other income		26			14			86	%
Total revenues		24,950			6,473			285	%
Expenses:
Lease operating expenses		6,616			2,087			217	%
Pipeline operating expenses		3,085			-			*
Transportation costs		3,799			855			344	%
Production and property taxes		2,010			433			364	%
Marketing gas purchases		4,172			-			*
General and administrative		4,689			2,948			59	%
General and administrative – related party reimbursement		-			(1,116	)		(100	%)
Depreciation, depletion and amortization		3,980			1,492			167	%
Accretion of asset retirement obligations		394			141			179	%
Total expenses		28,745			6,840			320	%
Operating income (loss)	$	(3,795	)	$	(367	)		(846	%)
Other income and (expense):
Interest expense		(2,914	)		(1,002	)		191	%
Warrant derivative gain		-			225			*
Equity investment income		19			5,828			*
Total other income (expense)	$	(2,895	)	$	5,051			(157	%)
Production data:
Natural gas (Mcf)		5,544,052			1,323,092			319	%
Oil (Bbl)		147,492			47,103			213	%
Natural gas liquids (Bbl)		13,210			4,502			193	%
Combined (Mcfe)		6,508,264			1,632,722			299	%
Average prices before effects of hedges:
Natural gas (per Mcf)	$	3.48		$	2.98			17	%
Oil (per Bbl)	$	60.95		$	57.80			5	%
Natural gas liquids (per Bbl)	$	18.67		$	35.30			(47	%)
Combined (per Mcfe)	$	4.39		$	4.34			1	%
Average prices after effects of hedges**:
Natural gas (per Mcf)	$	3.34		$	2.98			12	%
Oil (per Bbl)	$	63.29		$	50.39			26	%
Natural gas liquids (per Bbl)	$	18.67		$	35.30			(47	%)
Combined (per Mcfe)	$	4.32		$	4.11			1	%
Average costs (per Mcfe):
Lease operating expenses	$	1.02		$	1.28			(20	%)
Transportation costs	$	0.26		$	0.52			12	%
Production and property taxes	$	0.31		$	0.27			15	%
Cash-based general and administrative expense, net of related party reimbursement	$	0.69		$	0.95			(27	%)
Depreciation, depletion and amortization	$	0.61		$	0.91			(33	%)

* Not meaningful or applicable

**	Includes effect of settled commodity derivative gains and losses
(1)	Includes Carbon California activity for the period of consolidation from February 1, 2018 through March 31, 2018, and does not include Carbon Appalachia activity during 2018 as Carbon Appalachia did not consolidate until December 31, 2018 upon the closing of the OIE Membership Acquisition. See Recent Developments and Factors Affecting Comparability.

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Oil, natural gas liquids, and natural gas sales – Sales of oil, natural gas liquids and natural gas increased 303% to approximately $28.6 million for the three months ended March 31, 2019 from approximately $7.1 million for the three months ended March 31, 2018. This increase is primarily attributed to a 319%, 213% and 193% increase in natural gas, oil and natural gas liquids sales volumes, respectively, and an increase in natural gas and oil prices of 17% and 5%, respectively. The increases in production were a direct result of the acquisitions of Carbon Appalachia and Carbon California during 2018 and the resultant consolidation of the related activity for the three months ended March 31, 2019. Carbon Appalachia operating results are included in each of the three months ended March 31, 2019 whereas no Carbon Appalachia results were included in the three months ended March 31, 2018. Carbon California operating results are included in each of the three months ended March 31, 2019 whereas only the months of February and March reflect Carbon California activities during the three months ended March 31, 2018. Furthermore, the December 2017 California wildfires significantly impacted Carbon California results of operations in the first quarter of 2018.

Commodity derivative gains and losses – To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we enter into derivative contracts including fixed price swap contracts and costless collars. Because we do not designate these derivatives as cash flow hedges, they do not receive hedge accounting treatment and all mark-to-market gains or losses, as well as settlement gains or losses on the derivative instruments, are currently recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these contracts as oil and natural gas futures prices fluctuate relative to the fixed price we will receive from these contracts. For the three months ended March 31, 2019 and 2018, we had hedging losses of approximately $9.3 million and $626,000, respectively.

Lease operating expenses – Lease operating expenses for the three months ended March 31, 2019 increased 217% compared to the three months ended March 31, 2018. The increase was primarily attributable to the Carbon Appalachia and Carbon California acquisitions and the resultant increased production volumes. Expenses during the three months ended March 31, 2018 were also lower as a result of the December 2017 California wildfires. On a per Mcfe basis, lease operating expenses decreased to $1.02 per Mcfe for the three months ended March 31, 2019 from $1.28 per Mcfe for the three months ended March 31, 2018.

Transportation costs – Transportation costs for the three months ended March 31, 2019 increased 95% compared to the three months ended March 31, 2018. This increase is attributable to an increase in production as a result of the Carbon Appalachia Acquisition and a full three months of Carbon California operations. On a per Mcfe basis, these expenses decreased from $0.52 per Mcfe for the three months ended March 31, 2018 to $0.26 per Mcfe for the three months ended March 31, 2019.

Production and property taxes – Production and property taxes increased from approximately $433,000 for the three months ended March 31, 2018 to approximately $2.0 million for the three months ended March 31, 2019. This increase is primarily attributable to increased oil and natural gas sales as a result of consolidation of Carbon Appalachia and a full three months of Carbon California production. Production taxes averaged approximately 7.0% and 6.1% of product sales for the three months ended March 31, 2019 and 2018, respectively. Ad valorem tax rates, which can fluctuate by year, are determined by individual counties where we have production and are assessed on our sales one or two years in arrears depending on the location of the production.

Depreciation, depletion and amortization (DD&A) – DD&A increased from approximately $1.5 million for the three months ended March 31, 2018 to approximately $4.0 million for the three months ended March 31, 2019 primarily due to the consolidation of Carbon Appalachia and a full three months of Carbon California operations. On a per Mcfe basis, DD&A decreased from $0.91 per Mcfe for the three months ended March 31, 2018 to $0.61 per Mcfe for the three months ended March 31, 2019. The decrease in the depletion rate is primarily attributable to the consolidation of Carbon Appalachia.

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General and administrative expenses – Cash-based general and administrative expenses increased from approximately $1.5 million for the three months ended March 31, 2018 to approximately $4.5 million for the three months ended March 31, 2019. This increase is primarily attributable to the consolidation of Carbon Appalachia and a full three months of Carbon California operations. As a result of the consolidation of Carbon Appalachia and Carbon California during the three months ended March 31, 2019, management reimbursements which offset general and administrative expenses decreased by approximately $1.1 million compared to the three months ended December 31, 2018. On a per Mcfe basis, cash-based general and administrative expenses, net of related party reimbursements, decreased from $0.95 per Mcfe for the three months ended March 31, 2018 to $0.69 per Mcfe for the three months ended March 31, 2019. Non-cash stock based compensation and other general and administrative expenses for the three months ended March 31, 2019 and 2018 are summarized in the following table:

General and administrative expenses	Three Months Ended March 31,					Increase/
(in thousands)	2019		2018			(Decrease)
Stock-based compensation	$	222	$	292		$	(70	)
Other general and administrative expenses		4,467		2,656			1,811
General and administrative – related party reimbursement		-		(1,116	)		1,116
General and administrative expense	$	4,689	$	1,832		$	2,858

Interest expense – Interest expense increased from approximately $1.0 million for the three months ended March 31, 2018 to approximately $2.9 million for the three months ended March 31, 2019 primarily due to higher outstanding debt balances related to borrowings to complete the Carbon Appalachia and Seneca acquisitions in 2018. On a per Mcfe basis, interest expense decreased from $0.61 per Mcfe for the three months ended March 31, 2018 to $0.45 per Mcfe for the three months ended March 31, 2019.

Transportation and handling, marketing gas sales, pipeline operating expenses and marketing gas purchases – Subsequent to the OIE Membership Acquisition on December 31, 2018, we consolidate Carbon Appalachia operations. The associated revenues and expenses are presented within our unaudited consolidated statements of operations during the three months ended March 31, 2019. These operations were not presented in our unaudited consolidated statements of operations during the three months ended March 31, 2018.

Liquidity and Capital Resources

Our exploration, development and acquisition activities may require us to make significant operating and capital expenditures. Historically, we have used cash flow from operations and our bank credit facilities as our primary sources of liquidity and on occasion, we have engaged in the sale of assets. Changes in the market prices for oil and natural gas directly impact our level of cash flow generated from operations. The prices we receive for our production are determined by prevailing market conditions and greatly influence our revenue, cash flow, profitability, access to capital and future rate of growth. We employ a commodity hedging strategy in an attempt to moderate the effects of commodity price fluctuations on our cash flow.

The following table reflects our outstanding derivative agreements as of March 31, 2019:

	Natural Gas Swaps				Natural Gas Collars
			Weighted Average				Weighted Average Price
Year	MMBtu		Price (a)		MMBtu		Range (a)
2019		11,762,000	$	2.82		374,000	$	2.60 – $3.03
2020		12,433,000	$	2.73		1,018,000	$	2.50 – $2.70
2021		6,448,000	$	2.58		-	$	-

	Oil Swaps								Oil Collars
Year	WTI Bbl		Weighted Average  Price (b)		Brent Bbl		Weighted Average Price (c)		WTI Bbl		Weighted  Average Price		Brent Bbl		Weighted  Average Price
2019		180,775	$	53.46		121,079	$	66.93		-		-		29,800	$	47.00 - $75.00
2020		121,147	$	55.37		151,982	$	66.03		18,000	$	47.00 - $60.15		37,400	$	47.00 - $75.00
2021		-	$	-		86,341	$	67.12		30,000	$	47.00 - $60.15		98,000	$	47.00 - $75.00

*	Includes 100% of Carbon California’s outstanding derivative hedges at March 31, 2019, and not our proportionate share.
(a)	NYMEX Henry Hub Natural Gas futures contract for the respective period.
(b)	NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective period.
(c)	Brent future contracts for the respective period.

This hedge program mitigates uncertainty regarding cash flow that we will receive with respect to a portion of our expected production through 2021. Future hedging activities may result in reduced income or even financial losses to us. See “Risk Factors-The use of derivative instruments used in hedging arrangements could result in financial losses or reduce income,” in our Annual Report on Form 10-K for further details of the risks associated with our hedging activities. In the future, we may determine to increase or decrease our hedging positions.

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We have derivative contracts with BP Energy Company pursuant to ISDA Master Agreements. BP Energy Company is currently our only derivative contract counterparty.

Management Reimbursements

In our role as manager of Carbon California and Carbon Appalachia we receive reimbursements for management services. Prior to consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, these management service reimbursements were included in general and administrative – related party reimbursement on our unaudited consolidated statements of operations. As we now consolidate both Carbon California and Carbon Appalachia, these reimbursements are eliminated upon consolidation.

Operating Reimbursements

In our role as operator of Carbon California and Carbon Appalachia, we receive reimbursements of operating expenses. Prior to consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, these operating reimbursements were included in operating expenses on our unaudited consolidated statements of operations. As we now consolidate both Carbon California and Carbon Appalachia, these reimbursements are eliminated upon consolidation.

Historically, the primary sources of liquidity have been our credit facilities (described below) and cash flow from operations. We may use other sources of capital, including the issuance of debt or equity securities, to fund acquisitions or maintain our financial flexibility.

Credit Facilities and Notes Payable

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 for a new $500.0 million senior secured asset-based revolving credit facility maturing December 31, 2022 and a $15.0 million term loan which matures in 2020 (the “2018 Credit Facility”). The 2018 Credit Facility includes a sublimit of $1.5 million for letters of credit. The borrowers under the 2018 Credit Facility are Carbon Appalachia Enterprises, LLC (“CAE”) and various other subsidiaries of the Company (including Nytis USA, together with CAE, the “Borrowers”). Under the 2018 Credit Facility, Carbon is neither a borrower nor a guarantor. The initial borrowing base under the 2018 Credit Facility was $75.0 million, and remained so as of March 31, 2019.

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 and intangible and real property (subject to certain exclusions).

Interest accrues on borrowings under the 2018 Credit Facility at a rate per annum equal to either (i) the base rate plus an applicable margin equal to 0.25% - 0.75% depending on the utilization percentage or (ii) the Adjusted LIBOR rate plus an applicable margin equal to 2.75% - 3.75% depending on the utilization percentage, at the Borrowers’ option. The Borrowers are obligated to pay certain fees and expenses in connection the 2018 Credit Facility, including a commitment fee for any unused amounts of 0.50% and an origination fee of 0.50%. Loans under the 2018 Credit Facility may be prepaid without premium or penalty.

The 2018 Credit Facility also provides for a $15.0 million term loan which bears interest at a rate of 6.25% and is payable in 18 equal monthly installments beginning February 1, 2019 with the last payment due on June 30, 2020.

The 2018 Credit Facility contains certain affirmative and negative covenants that, among other things, limit the Company’s ability to (i) incur additional debt; (ii) incur additional liens; (iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distribution on, or repurchase of, equity; (vi) make certain investments; (vii) enter into certain transactions with their affiliates; (viii) enter in sale-leaseback transactions; (ix) make optional or voluntary payment of debt other than obligations under the 2018 Credit Facility; (x) change the nature of their business; (xi) change their fiscal year or make changes to the accounting treatment or reporting practices; (xii) amend their constituent documents; and (xiii) enter into certain hedging transactions.

The affirmative and negative covenants are subject to various exceptions, including certain basket amounts and acceptable transaction levels. In addition, the 2018 Credit Facility requires the Borrowers’ compliance, on a consolidated basis, with a maximum Net Debt (all debt of the Borrowing Parties minus all unencumbered cash and cash equivalents of the Borrowers not to exceed $3.0 million) / EBITDAX (as defined) ratio of 3.50 to 1.00 and a current ratio covenant minimum of 1.00 to 1.00, tested quarterly, commencing with the quarter ending March 31, 2019.

As of March 31, 2019, there was approximately $70.2 million in outstanding borrowings, an additional $4.8 million borrowing capacity under the 2018 Credit Facility, and Carbon Appalachia was in compliance with its financial covenants.

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Old Ironsides Notes

On December 31, 2018, as part of the OIE Membership Acquisition, we delivered unsecured promissory notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides (the “Old Ironsides Notes”). The Old Ironsides Notes bear interest at 10% per annum and have a term of five years, the first three of which require interest-only payments at the end of each calendar quarter beginning with the quarter ending March 31, 2019. At the end of the three-year interest-only period, the then current outstanding principal balance and interest is to be paid in 24 equal monthly payments. The Old Ironsides Notes also require mandatory prepayments upon the occurrence of certain subsequent liquidity events. A mandatory, one-time principal reduction payment in the aggregate amount of $2.0 million was made to Old Ironsides on February 1, 2019. Subsequent to the closing of the OIE Membership Acquisition Old Ironsides ceased to be a related party.

The interest payable under the Old Ironsides Notes can be paid-in-kind at the election of the Company. This provision allows the Company to increase the principal balance associated with the Old Ironsides Notes. This election creates a second tranche of principal, which bears interest at 12% per annum. On March 31, 2019, the Company elected to pay-in-kind approximately $594,000.

Carbon California

Senior Revolving Notes, Related Party

On February 15, 2017, Carbon California entered into a Note Purchase Agreement (the “Note Purchase Agreement”) for the issuance and sale of Senior Secured Revolving Notes to Prudential with an initial revolving borrowing capacity of $25.0 million which mature on February 15, 2022 (the “Senior Revolving Notes”). Carbon Energy Corporation is not a guarantor of the Senior Revolving Notes. The closing of the Note Purchase Agreement on February 15, 2017 resulted in the sale and issuance by Carbon California of Senior Revolving Notes in the principal amount of $10.0 million. The maximum principal amount available under the Senior Revolving Notes is based upon the borrowing base attributable to Carbon California’s proved oil and gas reserves which is to be determined at least semi-annually. As of March 31, 2019, the borrowing base was $41.0 million, of which $38.5 million was outstanding.

Carbon California may elect to incur interest at either (i) 5.50% plus the London interbank offered rate (“LIBOR”) or (ii) 4.50% plus the Prime Rate (which is defined as the interest rate published daily by JPMorgan Chase Bank, N.A.). As of March 31, 2019, the effective borrowing rate for the Senior Revolving Notes was 7.80%. In addition, the Senior Revolving Notes include a commitment fee for any unused amounts at 0.50% as well as an annual administrative fee of $75,000, payable on February 15 each year.

The Senior Revolving Notes are secured by all the assets of Carbon California. The Senior Revolving Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated proved developed production at such time for year one, two and three at a rate of 75%, 65% and 50%, respectively. Carbon California may make principal payments in minimum installments of $500,000. Distributions to equity members are generally restricted.

Carbon California may at any time repay the Senior Revolving Notes, in whole or in part, without penalty. Carbon California must pay down Senior Revolving Notes or provide mortgages of additional oil and natural gas properties to the extent that outstanding loans and letters of credit exceed the borrowing base.  

Subordinated Notes, Related Party

On February 15, 2017, Carbon California entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”) with Prudential Capital Energy Partners, L.P. for the issuance and sale of Subordinated Notes due February 15, 2024, bearing interest of 12% per annum (the “Subordinated Notes”). Carbon Energy Corporation is not a guarantor of the Subordinated Notes. The closing of the Securities Purchase Agreement on February 15, 2017 resulted in the sale and issuance by Carbon California of Subordinated Notes in the original principal amount of $10.0 million, all of which remains outstanding as of March 31, 2019.

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The Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively.

Prepayment of the Subordinated Notes is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted.

2018 Subordinated Notes, Related Party

On May 1, 2018, Carbon California entered into an agreement with Prudential for the issuance and sale of $3.0 million in Subordinated Notes due February 15, 2024, bearing interest of 12% per annum (the “2018 Subordinated Notes”), of which $3.0 million remains outstanding as of March 31, 2019.

The 2018 Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively.

Prepayment of the 2018 Subordinated Notes is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted.

Restrictions and Covenants

The Senior Revolving Notes, Subordinated Notes and 2018 Subordinated Notes contain affirmative and negative covenants that, among other things, limit Carbon California’s ability to (i) incur additional debt; (ii) incur additional liens; (iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distributions on, or repurchases of, equity; (vi) make certain investments; (vii) enter into certain transactions with our affiliates; (viii) enter into sales-leaseback transactions; (ix) make optional or voluntary payments of debt; (x) change the nature of our business; (xi) change our fiscal year to make changes to the accounting treatment or reporting practices; (xii) amend constituent documents; and (xiii) enter into certain hedging transactions.

41 

The affirmative and negative covenants are subject to various exceptions, including basket amounts and acceptable transaction levels. In addition, (i) the Senior Revolving Notes require Carbon California’s compliance, on a consolidated basis, with (A) a maximum Debt/EBITDA ratio of 4.0 to 1.0, stepping down to 3.5 to 1.0 starting with the quarter ending June 30, 2018, (B) a maximum Senior Revolving Notes/EBITDA ratio of 2.5 to 1.0, (C) a minimum interest coverage ratio of 3.0 to 1.0 and (D) a minimum current ratio of 1.0 to 1.0 and (ii) the Subordinated Notes require Carbon California’s compliance, on a consolidated basis, with (A) a maximum Debt/EBITDA ratio of 4.5 to 1.0, stepping down to 4.0 to 1.0 starting with the quarter ending June 30, 2018, (B) a maximum Senior Revolving Notes/EBITDA ratio of 3.0 to 1.0, (C) a minimum interest coverage ratio of 2.5 to 1.0, (D) an asset coverage test whereby indebtedness may not exceed the product of 0.65 times Adjusted PV-10 set forth in the most recent reserve report, (E) maintenance of a minimum borrowing base of $10,000,000 under the Senior Revolving Notes and (F) a minimum current ratio of 0.85 to 1.00.

As of March 31, 2019, Carbon California was in compliance with its covenants.

Borrowings under the Senior Revolving Notes and net proceeds from the Subordinated Notes issuances were used to fund certain acquisitions by Carbon California. Additional borrowings under the Senior Revolving Notes may be used to fund field development projects and to fund future complementary acquisitions and for general working capital purposes of Carbon California.

Sources and Uses of Cash

Our primary sources of liquidity and capital resources are operating cash flow and borrowings under our credit facilities. On December 31, 2018, we closed the OIE Membership Acquisition. As a result, we now own 100% of all interests in Carbon Appalachia. Upon closing, we received approximately $12.1 million in cash and will now receive 100% of cash flows associated with Carbon Appalachia.

Our primary uses of funds are expenditures for acquisitions, exploration and development activities, leasehold acquisitions, other capital expenditures and debt service.

Low prices for our oil and natural gas production may adversely impact our operating cash flow and amount of cash available for development activities.

The following table presents net cash provided by or used in operating, investing and financing activities for the three months ended March 31, 2019 and 2018.

	Three Months Ended
	March 31,
(in thousands)	2019			2018
Net cash provided by operating activities	$	8,311		$	95
Net cash (used in) investing activities	$	(336	)	$	(599	)
Net cash (used in) provided by financing activities	$	(2,695	)	$	2,968

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Net cash provided by operating activities is primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and changes in working capital. Operating cash flows increased approximately $8.1 million for the three months ended March 31, 2019 as compared to the same period in 2018. This increase was primarily due to increased revenues from the acquisition of producing oil and natural gas properties in the Appalachian Basin in the fourth quarter of 2018 and increased revenues from the consolidation of Carbon California effective February 1, 2018.

Net cash used in investing activities is primarily comprised of the acquisition, exploration and development of oil and natural gas properties, net of dispositions of oil and natural gas properties. Net cash used in investing activities decreased approximately $263,000 for the three months ended March 31, 2019 as compared to the same period in 2018.

Net cash provided by or used in financing activities is primarily comprised of activities associated with our credit facilities and equity contributions and distributions. During the three months ended March 31, 2019, the Company (i) paid $2.0 million in principal associated with the Old Ironsides Notes; (ii) paid approximately $1.7 million in principal associated with the 2018 Credit Facility term note; and (iii) increased net borrowings under the 2018 Credit Facility revolver by approximately $1.0 million. During the three months ended March 31, 2018, the Company increased borrowings by approximately $1.0 million and $2.0 million under its previously held credit facility revolver and the Carbon California Senior Revolving Notes, respectively.

Capital Expenditures

Capital expenditures incurred for the three months ended March 31, 2019 and 2018 are summarized in the following table:

	Three Months Ended March 31,
(in thousands)	2019		2018
Drilling and development	$	461	$	707
Other		39		167
Total capital expenditures	$	500	$	874

Capital expenditures presented in the table above represent cash used for capital expenditures.

Due to low commodity prices, the Company reduced its drilling program in 2018 and for three months ended March 31, 2019 and has focused on the optimization of our gathering facilities and marketing arrangements to provide greater flexibility in moving natural gas production to markets with more favorable pricing. Other factors impacting the level of our capital expenditures include the cost and availability of oil field services, general economic and market conditions and weather disruptions. 

Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of March 31, 2019, the off-balance sheet arrangements and transactions that we have entered into include (i) operating lease agreements, (ii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as natural gas transportation contracts, and (iii) oil and natural gas physical delivery contracts that are not expected to be net cash settled and are considered to be normal sales contracts and not derivatives. We do not believe that any of these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.

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Critical Accounting Policies, Estimates, Judgments, and Assumptions

Our critical accounting policies and estimates are set forth in “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations- Critical Accounting Policies, Estimates, Judgments, and Assumptions” in our 2018 Annual Report on Form 10-K. As of March 31, 2019, there have been no significant changes to our critical accounting policies and estimates since our 2018 Annual Report was filed.  

Forward Looking Statements

The information in this Quarterly Report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are statements other than statements of historical or present facts, that address activities, events, outcomes, and other matters that the Company plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates, or anticipates (and other similar expressions) will, should, or may occur in the future. Generally, the words “expects,” “anticipates,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “may,” “will,” “could,” “should,” “future,” “potential,” “continue,” variations of such words, and similar expressions identify forward-looking statements. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

These forward-looking statements appear in a number of places in this report and include statements with respect to, among other things:

● estimates of our oil, natural gas liquids, and natural gas reserves;

● estimates of our future oil, natural gas liquids, and natural gas production, including estimates of any increases or decreases in our production;

● our future financial condition and results of operations;

● our future revenues, cash flows, and expenses;

● our access to capital and our anticipated liquidity;

● our future business strategy and other plans and objectives for future operations and acquisitions;

● our outlook on oil, natural gas liquids, and natural gas prices;

● the amount, nature, and timing of future capital expenditures, including future development costs;

● our ability to access the capital markets to fund capital and other expenditures;

● our assessment of our counterparty risk and the ability of our counterparties to perform their future obligations; and

● the impact of federal, state and local political, regulatory, and environmental developments in the United States of America

We believe the expectations and forecasts reflected in our forward-looking statements are reasonable, but we can give no assurance that they will prove to be correct. We caution you that these forward-looking statements can be affected by inaccurate assumptions and are subject to all the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, and sale of oil, natural gas liquids and natural gas. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in our 2018 Annual Report on Form 10-K.

44 

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this report, and we undertake no obligation to update this information to reflect events or circumstances after the filing of this report with the SEC, except as required by law. All forward-looking statements, expressed or implied, included in this Quarterly Report on Form 10-Q and attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we may make or persons acting on our behalf may issue.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

As a smaller reporting company, we are not required to provide the information otherwise required by this item.

ITEM 4. Controls and Procedures

Evaluation of disclosure controls and procedures.  

We have established disclosure controls and procedures to ensure that material information relating to us and our consolidated subsidiaries is made known to the officers who certify our financial reports and the Board of Directors.

Our Chief Executive Officer, Patrick R. McDonald, and our Chief Financial Officer, Kevin D. Struzeski, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of the end of the period covered by this Quarterly Report on Form 10-Q (the “Evaluation Date”). Based on this evaluation, they believe that as of the Evaluation Date our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (i) is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms; and (ii) is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Changes in internal control over financial reporting.  There were no changes in our internal control over financial reporting during the quarter ended March 31, 2019, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

45 

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

We are subject to legal claims and proceedings in the ordinary course of our business. Management believes that should the controversies be resolved against us, none of the current pending proceedings would have a material adverse effect on us.

ITEM 1A. Risk Factors

Risk factors relating to us are discussed in “Part I, Item 1A. Risk Factors” in our 2018 Annual Report. There have been no material changes from the risk factors previously disclosed in our 2018 Annual Report. 

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

None. 

ITEM 6. Exhibits

Exhibit No.	Description
10.1	Amended and Restated Credit Agreement, among Carbon Appalachia Enterprises, LLC and Nytis Exploration (USA) Inc. and LegacyTexas Bank, dated December 31, 2018, incorporated by reference to Exhibit 10.2 to Form 8-K filed on January 7, 2019.
10.2	Letter Amendment, dated December 31, 2018, to Membership Interest Purchase Agreement, dated as of May 4, 2018, by and among Old Ironsides Fund II-A Portfolio Holding Company, LLC, Old Ironsides Fund II-B Portfolio Holding Company, LLC, and Carbon Energy Corporation, incorporated by reference to Exhibit 10.1 to Form 8-K filed on January 7, 2019.
10.3	Amendment to the Employment Agreement of Patrick R. McDonald, dated March 4, 2019, incorporated by reference to Exhibit 10.1 to Form 8-K filed on March 6, 2019.
10.4	Amendment to the Employment Agreement of Mark D. Pierce, dated March 4, 2019, incorporated by reference to Exhibit 10.2 to Form 8-K filed on March 6, 2019.
10.5	Amendment to the Employment Agreement of Kevin D. Struzeski, dated March 4, 2019, incorporated by reference to Exhibit 10.3 to Form 8-K filed on March 6, 2019.
31.1*	Certification of Chief Executive Officer Pursuant to Rule 13a-15(e) / Rule 15d-15(e).
31.2*	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) / Rule 15(e)/15d-15(e).
32.1†	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2†	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
101*	Interactive data files pursuant to Rule 405 of Regulation S-T.

*	Filed herewith
†	Not considered to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section

46 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	CARBON ENERGY CORPORATION
	(Registrant)
Date: May 13, 2019	By:	/s/ Patrick R. McDonald
		PATRICK R. MCDONALD,
		Chief Executive Officer
Date: May 13, 2019	By:	/s/ Kevin D. Struzeski
		KEVIN D. STRUZESKI
		Chief Financial Officer

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EX-31.1

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

I, Patrick R. McDonald, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Carbon Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

May 13, 2019	/s/ Patrick R. McDonald
	Patrick R. McDonald
	Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

I, Kevin D. Struzeski, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Carbon Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

May 13, 2019	/s/ Kevin D. Struzeski
	Kevin D. Struzeski
	Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF
CHIEF EXECUTIVE OFFICER
OF CARBON ENERGY CORPORATION
PURSUANT TO 18 U.S.C. SECTION 1350

Pursuant to 18 U.S.C. Section 1350 and in connection with the accompanying report on Form 10-Q for the quarter ended March 31, 2019 that is being filed concurrently with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned officer of Carbon Energy Corporation (the "Company") hereby certifies that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  May 13, 2019	/s/ Patrick R. McDonald
	Patrick R. McDonald
	Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION OF
CHIEF FINANCIAL OFFICER
OF CARBON ENERGY CORPORATION
PURSUANT TO 18 U.S.C. SECTION 1350

Pursuant to 18 U.S.C. Section 1350 and in connection with the accompanying report on Form 10-Q for the quarter ended March 31, 2019 that is being filed concurrently with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned officer of Carbon Energy Corporation (the "Company") hereby certifies that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  May 13, 2019	/s/ Kevin D. Struzeski
	Kevin D. Struzeski
	Chief Financial Officer

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

XML

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

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

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

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

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

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Organization

3 Months Ended

Mar. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization

Note 1 – Organization

Carbon Energy Corporation (formerly known as Carbon Natural Gas Company) and its subsidiaries (referred to herein as “we”, “us”, the “Company” or “Carbon”) business is comprised of the assets and properties of us and our subsidiaries.

An illustrative organizational chart as of March 31, 2019, is below:

 

Appalachian and Illinois Basin Operations

In the Appalachian and Illinois Basins, operations are conducted by Nytis Exploration Company, LLC (“Nytis LLC”). The following organizational chart illustrates this relationship as of March 31, 2019.

 

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”), owned by Old Ironside Fund II-A Portfolio Holding Company, LLC, a Delaware limited liability company (“OIE II-A”), and Old Ironside Fund II-B Portfolio Holding Company, LLC, a Delaware limited liability company (“OIE II-B”), collectively (“Old Ironsides”) for a purchase price of $58.1 million subject to customary and standard purchase price adjustments (“OIE Membership Acquisition”). As a result of the OIE Membership Acquisition, we now hold all of the issued and outstanding ownership interests of Carbon Appalachia, along with its direct and indirect subsidiaries (Carbon Appalachia Group, LLC, Carbon Tennessee Mining Company, LLC, Carbon Appalachia Enterprises, LLC, Carbon West Virginia Company, LLC, Cranberry Pipeline Corporation, Knox Energy, LLC, Coalfield Pipeline Company and Appalachia Gas Services Company, LLC).

Ventura Basin Operations

In California, Carbon California Operating Company, LLC (“CCOC”) conducts operations on behalf of Carbon California Company, LLC’s (“Carbon California”) operations. On February 1, 2018, Yorktown Energy Partners XI, L.P. (“Yorktown”) exercised the California Warrant, resulting in our aggregate sharing percentage in Carbon California increasing from 17.81% to 56.40%. On May 1, 2018, Carbon California closed the Seneca Acquisition. Following the exercise of the California Warrant by Yorktown and the Seneca Acquisition, we own 53.92% of the voting and profits interests and Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America or its affiliates (collectively, “Prudential”) owns 46.08% of the voting and profits interest in Carbon California. As of February 1, 2018, we consolidate Carbon California for financial reporting purposes. The following organizational chart illustrates this relationship as of March 31, 2019.

 

Collectively, references to “us” include Carbon California, CCOC, Nytis Exploration (USA) Inc. (“Nytis USA”), Nytis LLC, and Carbon Appalachia.

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2019

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Note 2 – Summary of Significant Accounting Policies

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information. Accordingly, they do not include all the information and footnotes required by GAAP for complete financial statements. In the opinion of management, the accompanying unaudited condensed consolidated financial statements include all adjustments considered necessary to present fairly our financial position as of March 31, 2019, and our results of operations and cash flows for the three months ended March 31, 2019 and 2018. Operating results for the three months ended March 31, 2019 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results, seasonality, and other factors. The unaudited condensed consolidated financial statements and related notes included in this Quarterly Report on Form 10-Q should be read in conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2018. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in our 2018 Annual Report on Form 10-K.

Principles of Consolidation

The unaudited condensed consolidated financial statements include the accounts of our consolidated subsidiaries. Upon the closing of the OIE Membership Acquisition on December 31, 2018, we own 100% of Carbon Appalachia. In addition, we own 100% of Nytis USA, which owns approximately 98.1% of Nytis LLC. Nytis LLC holds interests in various oil and gas partnerships.

Partnerships and subsidiaries in which we have a controlling interest are consolidated. We are currently consolidating 46 partnerships, Carbon Appalachia, and Carbon California, and we reflect the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on our unaudited consolidated statements of operations and also reflect the non-controlling ownership interest in the net assets of the partnerships as non-controlling interests within stockholders’ equity on our unaudited consolidated balance sheets. All significant intercompany accounts and transactions have been eliminated.

In accordance with established practice in the oil and gas industry, our unaudited condensed consolidated financial statements also include our pro-rata share of assets, liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which we have a non-controlling interest.

Non-majority owned investments that do not meet the criteria for pro-rata consolidation are accounted for using the equity method when we have the ability to significantly influence the operating decisions of the investee. When we do not have the ability to significantly influence the operating decisions of an investee, the cost method is used. All transactions, if any, with investees have been eliminated in the accompanying unaudited condensed consolidated financial statements.

Reclassifications

Certain prior period balances in the consolidated balance sheets and statements of operations have been reclassified to conform to the current year presentation.  Specifically, a portion of credit facilities and notes payable balances as of December 31, 2018 were reclassified from non-current liabilities to current liabilities.  This reclassification had no impact on net income, cash flows or shareholders’ equity previously reported.

Insurance Receivable

Insurance receivable is comprised of insurance claims for the loss of property as a result of wildfires that impacted Carbon California in December 2017. The Company filed claims with its insurance provider. In January 2019, we reached a settlement agreement and received an $800,000 payment from our insurance provider related to the damage caused by the California wildfires. As of March 31, 2019, we are in receipt of all funds associated with the claims.  

Accounting for Oil and Gas Operations

We use the full cost method of accounting for oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Overhead costs incurred that are directly identified with acquisition, exploration and development activities undertaken by the Company for its own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized.

Unproved properties are excluded from amortized capitalized costs until it is determined if proved reserves can be assigned to such properties. We assess our unproved properties for impairment at least annually. Significant unproved properties are assessed individually.

Capitalized costs are depleted by an equivalent unit-of-production method, converting oil to gas at the ratio of one barrel of oil to six thousand cubic feet of natural gas. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.

No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves. All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.

We perform a ceiling test quarterly. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value based measurement, rather it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using the un-weighted arithmetic average of the first-day-of-the month price for the previous twelve month period, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs. Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds the capitalized costs in future periods.

For the three months ended March 31, 2019 and 2018, we did not recognize a ceiling test impairment as our full cost pool did not exceed the ceiling limitations. Future declines in oil and natural gas prices could result in impairments of our oil and gas properties in future periods. The effect of price declines will impact the ceiling test value until such time commodity prices stabilize or improve. Impairments are a non-cash charge and accordingly would not affect cash flows but would adversely affect our results of operations and members’ equity.

We capitalize the portion of general and administrative costs that is attributable to our acquisition, exploration and development activities.

Revenue

We recognize revenues for sales and services when persuasive evidence of an arrangement exists, when custody is transferred, or services are rendered, fees are fixed or determinable and collectability is reasonably assured.

Oil, Natural Gas and Natural Gas Liquid Sales

Oil, natural gas and natural gas liquid sales are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred, and collectability is reasonably assured. Revenues are recognized based on our net revenue interest.

Marketing Gas Sales

We sell production purchased from third parties as well as production from our own oil and gas producing properties. Marketing gas sales are recognized on a gross basis as we purchase and take control of the gas prior to sale and are the principal in the transaction.

Storage

Under fee-based arrangements, we receive a fee for storing natural gas. The revenues earned are directly related to the volume of natural gas that flows through our systems and are not directly dependent on commodity prices.

Transportation, gathering, and compression

We generally purchase natural gas from producers at the wellhead or other receipt points, gather the wellhead natural gas through our gathering systems, and then sell the natural gas based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of natural gas or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, regardless of the actual amount of the sales proceeds we receive. Our revenues under percent-of-proceeds/index arrangements generally correlate to the price of natural gas.

Investments in Affiliates

Investments in non-consolidated affiliates are accounted for under either the cost or equity method of accounting, as appropriate. The cost method of accounting is generally used for investments in affiliates in which we have less than 20% of the voting interests of a corporate affiliate (or less than a 3% to 5% interest of a partnership or limited liability company) and do not have significant influence. Investments in non-consolidated affiliates, accounted for using the cost method of accounting, are recorded at cost and impairment assessments for each investment are made annually to determine if a decline in the fair value of the investment, other than temporary, has occurred. A permanent impairment is recognized if a decline in the fair value occurs.

If we hold between 20% and 50% of the voting interest in non-consolidated corporate affiliates or generally greater than a 3% to 5% interest of a partnership or limited liability company and can exert significant influence or control (e.g., through our influence with a seat on the board of directors or management of operations), the equity method of accounting is generally used to account for the investment. Equity method investments will increase or decrease by our share of the affiliate’s profits or losses and such profits or losses are recognized in our unaudited consolidated statements of operations. We review equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred. Upon the exercise of the California Warrant on February 1, 2018 and the closing of the OIE Membership Acquisition on December 31, 2018, we consolidate Carbon California and Carbon Appalachia for financial reporting purposes and no longer account for these investments under the equity method.

Related Party Transactions

Management Reimbursements

In our role as manager of Carbon California and Carbon Appalachia we receive reimbursements for management services. Prior to consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, these management service reimbursements were included in general and administrative – related party reimbursement on our unaudited consolidated statements of operations. As we now consolidate both Carbon California and Carbon Appalachia, these reimbursements are eliminated upon consolidation.

We received approximately $753,000 and $50,000 for the three months ended March 31, 2018, and for the one month ended January 31, 2018, from Carbon Appalachia and Carbon California, respectively. These reimbursements are included in general and administrative – related party reimbursement on our unaudited consolidated statements of operations. Effective February 1, 2018, the management reimbursements received from Carbon California were eliminated at consolidation. This elimination included $100,000 for the period February 1, 2018, through March 31, 2018.

In addition to the management reimbursements, approximately $299,000 and $14,000 in general and administrative expenses were reimbursed for the three months ended March 31, 2018, and for the one month ended January 31, 2018, by Carbon Appalachia and Carbon California, respectively. The elimination of Carbon California in consolidation includes approximately $28,000 for the period February 1, 2018, through March 31, 2018.

Operating Reimbursements

In our role as operator of Carbon California and Carbon Appalachia, we receive reimbursements of operating expenses. Prior to consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, these operating reimbursements were included in operating expenses on our unaudited consolidated statements of operations. As we now consolidate both Carbon California and Carbon Appalachia, any intercompany receivable and payable balances associated with these reimbursements are eliminated upon consolidation.

Carbon California Credit Facilities

The credit facilities of Carbon California, including the Senior Revolving Notes, Carbon California Notes and Carbon California 2018 Subordinated Notes (all defined below), are held by Prudential (see Note 7).

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and expenses and disclosure of contingent assets and liabilities. Significant items subject to such estimates and assumptions include the carrying value of oil and gas properties, estimates of proved oil and gas reserve volumes and the related depletion and present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, determining the amounts recorded for fair value of commodity derivative instruments, fair value of assets acquired and liabilities assumed qualifying as business combinations or asset acquisitions, estimated lives of other property and equipment, asset retirement obligations, fair value of Class B issuances and accrued liabilities and revenues. There have been no changes in our critical accounting estimates from those that were disclosed in the 2018 Annual Report on Form 10-K. Actual results could differ from these estimates.

Earnings (Loss) Per Common Share

Basic earnings per common share is computed by dividing the net income or loss attributable to common stockholders for the period by the weighted average number of common shares outstanding during the period. The shares of restricted common stock granted to our officers, directors and employees are included in the computation of basic net income per share only after the shares become fully vested. Diluted earnings per common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise of options and warrants to acquire common stock computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by us with the proceeds from the exercise of options and warrants (which were assumed to have been made at the average market price of the common shares during the reporting period).

In periods when we report a net loss, all shares of restricted stock are excluded from the calculation of diluted weighted average shares outstanding because of its anti-dilutive effect on loss per share. As a result, approximately 269,000 potentially dilutive restricted stock awards are excluded from the calculation of diluted earnings per common share for the three months ended March 31, 2019. In addition, approximately 200,000 restricted performance units subject to future contingencies were excluded in the basic and diluted income per share calculations.

For the three months ended March 31, 2018, we had net income and the diluted income per common share calculation includes the dilutive effects of approximately 230,000 non-vested shares of restricted stock. In addition, approximately 254 ,000 restricted performance units subject to future contingencies were excluded in the basic and diluted income per share calculations.

The following table sets forth the calculation of basic and diluted (loss) income per share:

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

Recently Adopted Accounting Pronouncement

In February 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The FASB subsequently issued various ASUs which provided additional implementation guidance, and these ASUs collectively make up FASB Accounting Standards Codification (“ASC”) Topic 842 – Leases (“ASC 842”). ASC 842 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The standard permits retrospective application through recognition of a cumulative-effect adjustment at the beginning of either the earliest reporting period presented or the period of adoption. The Company adopted ASC 842 effective January 1, 2019 using the modified retrospective method as of the adoption date. Adoption of the standard resulted in the recognition of additional lease assets and liabilities on our unaudited consolidated balance sheet as well as additional disclosures. The adoption did not have a material impact to our unaudited consolidated statement of operations. Refer to Note 14 for further information on our implementation of this standard.

Recently Issued Accounting Pronouncements

There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows.

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Acquisitions and Divestitures

3 Months Ended

Mar. 31, 2019

Business Combinations [Abstract]

Acquisitions and Divestitures

Note 3 – Acquisitions and Divestitures

Majority Control of Carbon Appalachia

On December 16, 2016, Carbon Appalachia was formed by us, entities managed by Yorktown and entities managed by Old Ironsides to acquire producing assets in the Appalachian Basin in Kentucky, Tennessee, Virginia and West Virginia. Carbon Appalachia began substantial operations on April 3, 2017 and is engaged primarily in acquiring, developing, exploiting, producing, processing, marketing, and transporting oil and natural gas in the Appalachian Basin.

On April 3, 2017, Carbon, Yorktown and Old Ironsides entered in to a limited liability company agreement (the “Carbon Appalachia LLC Agreement”), with an initial equity commitment of $100.0 million, of which $37.0 million had been contributed as of December 31, 2018. Carbon Appalachia (i) issued Class A Units to us, Yorktown and Old Ironsides for an aggregate cash consideration of $12.0 million, (ii) issued Class B Units to us, and (iii) issued Class C Units to us. Additionally, Carbon Appalachia Enterprises, LLC, formerly known as Carbon Tennessee Company, LLC (“Carbon Appalachia Enterprises”), a subsidiary of Carbon Appalachian Company, LLC, entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank (the “Revolver”) with an initial borrowing base of $10.0 million.

In connection with Carbon entering into the Carbon Appalachia LLC Agreement, and Carbon Appalachia engaging in the transactions described above, Carbon received 1,000 Class B Units and issued to Yorktown a warrant to purchase approximately 408,000 shares of our common stock at an exercise price dictated by the warrant agreement (the “Appalachia Warrant”). The Appalachia Warrant was payable exclusively with Class A Units of Carbon Appalachia held by Yorktown. On November 1, 2017, Yorktown exercised the Appalachia Warrant, resulting in us acquiring 2,940 Class A Units from Yorktown. 

On August 15, 2017, the Carbon Appalachia LLC Agreement was amended and, as a result, we agreed to contribute an initial commitment of future capital contributions as well as Yorktown’s, and Yorktown will not participate in future capital contributions. Carbon Appalachia issued Class A Units to us and Old Ironsides for an aggregate cash consideration of $14.0 million. The borrowing base of the Revolver increased to $22.0 million and Carbon Appalachia Enterprises borrowed $8.0 million under the Revolver.

On September 29, 2017, Carbon Appalachia issued Class A Units to us and Old Ironsides for an aggregate cash consideration of $11.0 million.

Prior to the closing of the OIE Membership Acquisition, Old Ironsides held 27,195 Class A Units, which equated to a 72.76% aggregate share ownership of Carbon Appalachia and we held (i) 9,805 Class A Units, (ii) 1,000 Class B Units and (iii) 121 Class C Units, which equated to a 27.24% aggregate share ownership of Carbon Appalachia.

On December 31, 2018, we acquired all of Old Ironsides’ Class A Units of Carbon Appalachia for approximately $58.1 million, subject to customary and standard closing adjustments. We paid $33.0 million in cash and delivered promissory notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides (the “Old Ironsides Notes”). The Old Ironsides Notes bear interest at 10% per annum and have a term of five years, the first three of which require interest-only payments at the end of each calendar quarter beginning with the quarter ending March 31, 2019. At the end of the three-year interest-only period, the then current outstanding principal balance and interest is to be paid in 24 equal monthly payments. The Old Ironsides Notes also provide for mandatory prepayments upon the occurrence of certain subsequent liquidity events. A mandatory, one-time principal reduction payment in the aggregate amount of $2.0 million was made to Old Ironsides on February 1, 2019.

The OIE Membership Acquisition is accounted for as a business combination in accordance with ASC 805, Business Combinations (“ASC 805”). We recognized 100% of the identifiable assets acquired and liabilities assumed at their respective fair value as of the date of the acquisition. The $58.1 million purchase price, consisting of $33.0 million in cash and $25.1 million of Old Ironsides Notes, was paid for Old Ironsides’ outstanding interest, representing approximately 72.76% interest in Carbon Appalachia.

The Company, utilizing the assistance of third-party valuation specialists, considered various factors in its estimate of fair value of the acquired assets and liabilities including (i) reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, including price differentials, (v) future cash flows, (vi) a market participant-based weighted average cost of capital, and (vii) real estate market conditions.

We followed the fair value method to allocate the consideration transferred to the identifiable net assets acquired on a preliminary basis as follows:

	Amount  (in thousands)
Cash consideration	$	33,000
Old Ironsides Notes		25,065
Fair value of previously held equity interest		14,158
Fair value of business acquired	$	72,223

Assets acquired and liabilities assumed are as follows:

	Amount (in thousands)
Cash	$	12,283
Accounts receivable:
Revenue		12,834
Trade receivable		1,941
Commodity derivative asset		198
Inventory		900
Prepaid expenses, deposits, and other current assets		456
Oil and gas properties:
Proved		107,499
Unproved		1,869
Other property, plant and equipment, net		15,626
Other non-current assets		514
Accounts payable and accrued liabilities		(19,114	)
Due to related parties		(458	)
Firm transportation contract obligations		(18,724	)
Asset retirement obligations		(5,626	)
Notes payable		(37,975	)
Total net assets acquired	$	72,223

The preliminary fair value of the assets acquired and liabilities assumed were determined using various valuation techniques, including an income approach.

On the date of the acquisition, we derecognized our equity investment in Carbon Appalachia and recognized a gain of approximately $1.3 million based on the fair value of our previously held interest compared to its carrying value.

For assets and liabilities accounted for as business combinations, including the OIE Membership Acquisition, to determine the fair value of the assets acquired, the Company primarily used the income approach and made market assumptions as to projections of estimated quantities of oil and natural gas reserves, future production rates, future commodity prices including price differentials as of the date of closing, future operating and development costs, a market participant weighted average cost of capital, and the condition of vehicles and equipment. The Company used the income approach and made market assumptions as to projections of utilization, future operating costs and a market participant weighted average costs of capital to determine the fair value of the firm transportation obligations as well as the plant facilities. The determination of the fair value of accounts payable and accrued liabilities assumed required significant judgement, including estimates relating to production assets.

Consolidation of Carbon Appalachia and OIE Membership Acquisition Unaudited Pro Forma Results of Operations

Below are unaudited pro forma consolidated results of operations for the three months ended March 31, 2019 and 2018 as though the OIE Membership Acquisition had been completed as of January 1, 2018.

	Three Months Ended March 31,			Three Months Ended March 31,
(in thousands, except per share amounts)	2019			2018
Revenue	$	24,950		$	32,316
Net (loss) income before non-controlling interests	$	(6,690	)	$	6,912
Net (loss) income attributable to non-controlling interests	$	(2,590	)	$	1,115
Net (loss) income attributable to common shareholders	$	(4,175	)	$	5,797
Net (loss) income per share (basic)	$	(0.54	)	$	0.83
Net (loss) income per share (diluted)	$	(0.54	)	$	0.77

Consolidation of Carbon California Unaudited Pro Forma Results of Operations

On February 1, 2018, Yorktown exercised the California Warrant resulting in the issuance of 1,527,778 shares of our common stock in exchange for Yorktown’s Class A Units of Carbon California representing approximately 46.96% of the outstanding Class A Units of Carbon California (a profits interest of approximately 38.59%). After giving effect to the exercise on February 1, 2018, we owned 56.4% of the voting and profits interests of Carbon California.

Below are unaudited pro forma consolidated results of operations for the three months ended March 31, 2019 and 2018 as though the Carbon California Acquisition had been completed as of January 1, 2018. The Carbon California Acquisition closed February 1, 2018, and accordingly, the Company’s unaudited consolidated statements of operations for the quarter ended March 31, 2018, includes the results of operations for the period February 1, 2018, through March 31, 2018.

	Three Months Ended March 31,			Three Months Ended March 31,
(in thousands, except per share amounts)	2019			2018
Revenue	$	24,950		$	6,672
Net (loss) income before non-controlling interests	$	(6,690	)	$	3,543
Net (loss) income attributable to non-controlling interests	$	(2,590	)	$	1,115
Net (loss) income attributable to common shareholders	$	(4,175	)	$	2,428
Net (loss) income per share (basic)	$	(0.54	)	$	0.35
Net (loss) income per share (diluted)	$	(0.54	)	$	0.30

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Property and Equipment

3 Months Ended

Mar. 31, 2019

Property, Plant and Equipment [Abstract]

Property and Equipment

Note 4 – Property and Equipment

Net property and equipment as of March 31, 2019 and December 31, 2018 consists of the following:

(in thousands)	March 31, 2019			December 31, 2018
Oil and gas properties:
Proved oil and gas properties	$	344,147		$	343,736
Unproved properties not subject to depletion		5,385			5,416
Accumulated depreciation, depletion, amortization and impairment		(98,826	)		(95,281	)
Net oil and gas properties		250,706			253,871
Pipeline facilities and equipment		12,714			12,714
Base gas		2,122			2,122
Furniture and fixtures, computer hardware and software, and other equipment		6,688			6,649
Accumulated depreciation and amortization		(4,356	)		(3,922	)
Net other property and equipment		17,168			17,563
Total net property and equipment	$	267,874		$	271,434

As of March 31, 2019, and December 31, 2018, the Company had approximately $5.4 million of unproved oil and gas properties not subject to depletion. The costs not subject to depletion relate to unproved properties that are excluded from amortized capital costs until it is determined if proved reserves can be assigned to such properties. The excluded properties are assessed for impairment at least annually. Subject to industry conditions, evaluation of most of these properties and the inclusion of their costs in amortized capital costs is expected to be completed within five years.

During the three months ended March 31, 2019 and 2018, there were no expiring leasehold costs that were reclassified into proved property. The excluded properties are assessed for impairment at least annually. Subject to industry conditions, evaluations of most of these properties and the inclusion of their costs in amortized capital costs is expected to be completed within five years.

We capitalized overhead applicable to acquisition, development and exploration activities of approximately $68,000 and $71,000 for the three months ended March 31, 2019 and 2018, respectively.

Depletion expense related to oil and gas properties for the three months ended March 31, 2019 and 2018 was approximately $3.5 million, or $0.54 per Mcfe, and $1.3 million, or $0.82 per Mcfe, respectively.

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Asset Retirement Obligation

3 Months Ended

Mar. 31, 2019

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation

Note 5 – Asset Retirement Obligation

Asset Retirement Obligations

The Company's asset retirement obligations ("ARO") relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred and the cost of such liability is recorded as an increase in the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability.

The estimated ARO liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or increased as a result of a reassessment of expected cash flows and assumptions inherent in the estimation of the liability. Upward revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. AROs are valued utilizing Level 3 fair value measurement inputs.

The following table is a reconciliation of the ARO for the three months ended March 31, 2019 and 2018:

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

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Investments in Affiliates

3 Months Ended

Mar. 31, 2019

Equity Method Investments and Joint Ventures [Abstract]

Investments in Affiliates

Note 6 – Investments in Affiliates

Carbon Appalachia

For the period April 3, 2017 (inception) through December 31, 2018, based on our 27.24% combined Class A, Class B and Class C interest (and our ability as of December 31, 2018 to earn up to an additional 14.7%) in Carbon Appalachia, our ability to appoint a member to the board of directors and our role of manager of Carbon Appalachia, we accounted for our investment in Carbon Appalachia under the equity method of accounting as we believed we exerted significant influence. We used the HLBV to determine our share of profits or losses in Carbon Appalachia and adjusted the carrying value of our investment accordingly. Our investment in Carbon Appalachia is represented by our Class A and C interests, which we acquired by contributing approximately $6.9 million in cash and unevaluated property. In the event of liquidation of Carbon Appalachia, available proceeds are first distributed to members holding Class C Units then to holders of Class A Units until their contributed capital is recovered with an internal rate of return of 10%. Any additional distributions would then be shared between holders of Class A, Class B and Class C Units.

On December 31, 2018, we acquired all of Old Ironsides’ Class A Units of Carbon Appalachia for approximately $58.1 million, subject to customary and standard closing adjustments. We paid $ 33.0 million in cash and issued the Old Ironsides Notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides.

Effective December 31, 2018, upon the closing of the OlE Membership Acquisition, we consolidate Carbon Appalachia in our consolidated financial statements.

Carbon California

For the period February 15, 2017 (inception) through January 31, 2018, based on our 17.81% interest in Carbon California, our ability to appoint a member to the board of directors and our role of manager of Carbon California, we accounted for our investment in Carbon California under the equity method of accounting as we believed we exerted significant influence. We used the Hypothetical Liquidation at Book Value Method (“HLBV”) to determine our share of profits or losses in Carbon California and adjusted the carrying value of our investment accordingly. The HLBV is a balance-sheet approach that calculates the amount each member of Carbon California would have received if Carbon California were liquidated at book value at the end of each measurement period. The change in the allocated amount to each member during the period represents the income or loss allocated to that member. In the event of liquidation of Carbon California, to the extent that Carbon California has net income, available proceeds are first distributed to members holding Class B Units and any remaining proceeds are then distributed to members holding Class A Units.

Effective February 1, 2018, upon the exercise of the California Warrant, we consolidate Carbon California in our consolidated financial statements.

Other Affiliates

At March 31, 2019 and December 31, 2018, we retained interests in two equity method investments associated with the development and transportation of oil and gas.

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Credit Facilities and Notes Payable

3 Months Ended

Mar. 31, 2019

Debt Disclosure [Abstract]

Credit Facilities and Notes Payable

Note 7 – Credit Facilities and Notes Payable

Carbon Appalachia

The table below summarizes the outstanding credit facilities and notes payable:

(in thousands)	March 31, 2019			December 31, 2018
2018 Credit Facility – revolver	$	70,150		$	69,150
2018 Credit Facility – term note		13,333			15,000
Old Ironsides Notes		23,659			25,065
Other debt		48			57
Total principal		107,190			109,272
Less:  unamortized debt discount		(112	)		(134	)
Total credit facilities and notes payable	$	107,078		$	109,138

The current portion of the outstanding credit facilities and notes payable was approximately $9.9 million as of March 31, 2019 and $11.9 million as of December 31, 2018.

2018 Credit Facility

In connection with and concurrently with the closing of the OIE Membership Acquisition, the Company and its subsidiaries amended and restated our prior credit facilities for a new $500.0 million senior secured asset-based revolving credit facility maturing December 31, 2022 and a $15.0 million term loan which matures in 2020 (the “2018 Credit Facility”). The 2018 Credit Facility includes a sublimit of $1.5 million for letters of credit. The borrowers under the 2018 Credit Facility are Carbon Appalachia Enterprises, LLC (“CAE”) and various other subsidiaries of the Company (including Nytis USA, together with CAE, the “Borrowers”). Under the 2018 Credit Facility, Carbon Energy Corporation is neither a borrower nor a guarantor. The initial borrowing base under the 2018 Credit Facility was $75.0 million, and remained so as of March 31, 2019.

The 2018 Credit Facility is guaranteed by each existing and future direct or indirect subsidiary of the Borrowers and certain other subsidiaries of the Company (subject to various exceptions) and the obligations under the 2018 Credit Facility are secured by essentially all tangible, intangible and real property (subject to certain exclusions).

Interest accrues on borrowings under the 2018 Credit Facility at a rate per annum equal to either (i) the base rate plus an applicable margin equal to 0.25% - 0.75% depending on the utilization percentage or (ii) the Adjusted LIBOR rate plus an applicable margin equal to 2.75% - 3.75% depending on the utilization percentage, at the Borrowers’ option. The Borrowers are obligated to pay certain fees and expenses in connection the 2018 Credit Facility, including a commitment fee for any unused amounts of 0.50% and an origination fee of 0.50%. Loans under the 2018 Credit Facility may be prepaid without premium or penalty.

The 2018 Credit Facility also provides for a $15.0 million term loan which bears interest at a rate of 6.25% and is payable in 18 equal monthly installments beginning February 1, 2019 with the last payment due on June 30, 2020.

The 2018 Credit Facility contains certain affirmative and negative covenants that, among other things, limit the Company’s ability to (i) incur additional debt; (ii) incur additional liens; (iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distribution on, or repurchase of, equity; (vi) make certain investments; (vii) enter into certain transactions with their affiliates; (viii) enter in sale-leaseback transactions; (ix) make optional or voluntary payment of debt other than obligations under the 2018 Credit Facility; (x) change the nature of their business; (xi) change their fiscal year or make changes to the accounting treatment or reporting practices; (xii) amend their constituent documents; and (xiii) enter into certain hedging transactions.

The affirmative and negative covenants are subject to various exceptions, including certain basket amounts and acceptable transaction levels. In addition, the 2018 Credit Facility requires the Borrowers’ compliance, on a consolidated basis, with a maximum Net Debt (all debt of the Borrowing Parties minus all unencumbered cash and cash equivalents of the Borrowers not to exceed $3.0 million) / EBITDAX (as defined) ratio of 3.50 to 1.00 and a current ratio, as defined, minimum of 1.00 to 1.00, tested quarterly, commencing with the quarter ending March 31, 2019. We are in compliance with our financial covenants as of March 31, 2019 and expect to be in compliance with these covenants throughout the next twelve month period. We are currently engaged in discussions with LegacyTexas Bank to decrease the required hedging period of our expected future production from 30 months to 24 months.

As of March 31, 2019, there was approximately $70.2 million in outstanding borrowings and $4.8 million of additional borrowing capacity under the 2018 Credit Facility.

The terms of the 2018 Credit Facility require us to enter into derivative contracts at fixed pricing for a certain percentage of our production. We are party to an ISDA Master Agreement with BP Energy Company that establishes standard terms for the derivative contracts and an inter-creditor agreement with LegacyTexas Bank and BP Energy Company whereby any credit exposure related to the derivative contracts entered into by us and BP Energy Company is secured by the collateral and backed by the guarantees supporting the 2018 Credit Facility.

Fees paid in connection with the 2018 Credit Facility totaled $779,000, of which $134,000 was associated with the term loan. The current portion of unamortized fees is included in prepaid expense, deposits and other current assets and the non-current portion is included in other non-current assets. The unamortized portion associated with the term loan was $112,000 as of March 31, 2019, and is directly offset against the loan in non-current liabilities. As of March 31, 2019, we had unamortized deferred issuance costs of $604,000 associated with the 2018 Credit Facility. During the three months ended March 31, 2019, we amortized approximately $63,000 as interest expense associated with the 2018 Credit Facility.

Old Ironsides Notes

On December 31, 2018, as part of the OIE Membership Acquisition, we delivered unsecured, promissory notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides (the “Old Ironsides Notes”). The Old Ironsides Notes bear interest at 10% per annum and have a term of five years, the first three of which require interest-only payments at the end of each calendar quarter beginning with the quarter ending March 31, 2019. At the end of the three-year interest-only period, the then current outstanding principal balance and interest is to be paid in 24 equal monthly payments. The Old Ironsides Notes also require mandatory prepayments upon the occurrence of certain subsequent liquidity events. A mandatory, one-time principal reduction payment in the aggregate amount of $2.0 million was made to Old Ironsides on February 1, 2019. Subsequent to the closing of the OIE Membership Acquisition Old Ironsides ceased to be a related party.

The interest payable under the Old Ironsides Notes can be paid-in-kind at the election of the Company. This provision allows the Company to increase the principal balance associated with the Old Ironsides Notes. This election creates a second tranche of principal, which bears interest at 12% per annum. On March 31, 2019, the Company elected to pay-in-kind approximately $594,000.

Carbon California

The table below summarizes the outstanding notes payable – related party:

(in thousands)	March 31, 2019			December 31, 2018
Senior Revolving Notes, related party, due February 15, 2022	$	38,500		$	38,500
Subordinated Notes, related party, due February 15, 2024		13,000			13,000
Total principal		51,500			51,500
Less: Deferred notes costs		(255	)		(235	)
Less: unamortized debt discount		(1,281	)		(1,346	)
Total notes payable – related party	$	49,964		$	49,919

Senior Revolving Notes, Related Party

On February 15, 2017, Carbon California entered into a Note Purchase Agreement (the “Note Purchase Agreement”) for the issuance and sale of Senior Secured Revolving Notes to Prudential with an initial revolving borrowing capacity of $25.0 million which mature on February 15, 2022 (the “Senior Revolving Notes”). Carbon Energy Corporation is not a guarantor of the Senior Revolving Notes. The closing of the Note Purchase Agreement on February 15, 2017 resulted in the sale and issuance by Carbon California of Senior Revolving Notes in the principal amount of $10.0 million. The maximum principal amount available under the Senior Revolving Notes is based upon the borrowing base attributable to Carbon California’s proved oil and gas reserves which is to be determined at least semi-annually. As of March 31, 2019, the borrowing base was $41.0 million, of which $38.5 million was outstanding.

Carbon California may elect to incur interest at either (i) 5.50% plus the London interbank offered rate (“LIBOR”) or (ii) 4.50% plus the Prime Rate (which is defined as the interest rate published daily by JPMorgan Chase Bank, N.A.). As of March 31, 2019, the effective borrowing rate for the Senior Revolving Notes was 7.80%. In addition, the Senior Revolving Notes include a commitment fee for any unused amounts at 0.50% as well as an annual administrative fee of $75,000, payable on February 15 each year.

The Senior Revolving Notes are secured by all the assets of Carbon California. The Senior Revolving Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated proved developed production at such time for year one, two and three at a rate of 75%, 65% and 50%, respectively. Carbon California may make principal payments in minimum installments of $500,000. Distributions to equity members are generally restricted.

Carbon California incurred fees directly associated with the issuance of the Senior Revolving Notes and amortizes these fees over the life of the Senior Revolving Notes. The current portion of these fees are included in prepaid expense and deposits and the long-term portion is included in other non-current assets for a combined value of approximately $939,000. For the three months ended March 31, 2019, Carbon California amortized fees of $74,000.

Carbon California may at any time repay the Senior Revolving Notes, in whole or in part, without penalty. Carbon California must pay down Senior Revolving Notes or provide mortgages of additional oil and natural gas properties to the extent that outstanding loans and letters of credit exceed the borrowing base.  

Subordinated Notes, Related Party

On February 15, 2017, Carbon California entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”) with Prudential Capital Energy Partners, L.P. for the issuance and sale of Subordinated Notes due February 15, 2024, bearing interest of 12% per annum (the “Subordinated Notes”). Carbon Energy Corporation is not a guarantor of the Subordinated Notes. The closing of the Securities Purchase Agreement on February 15, 2017 resulted in the sale and issuance by Carbon California of Subordinated Notes in the original principal amount of $10.0 million, all of which remains outstanding as of March 31, 2019.

Prudential received an additional 1,425 Class A Units, representing 5% of total sharing percentage, for the issuance of the Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding Subordinated Notes of $10.0 million. The Company then allocated the non-cash value of the units of approximately $1.3 million, which was recorded as a discount to the Subordinated Notes. As of March 31, 2019, Carbon California has an outstanding discount of approximately $869,000, which is presented net of the Subordinated Notes within Credit facility-related party on the unaudited consolidated balance sheets. During the three months ended March 31, 2019, Carbon California amortized $45,000 associated with the Subordinated Notes.

The Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively.

Prepayment of the Subordinated Notes is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted.

2018 Subordinated Notes, Related Party

On May 1, 2018, Carbon California entered into an agreement with Prudential for the issuance and sale of $3.0 million in Subordinated Notes due February 15, 2024, bearing interest of 12% per annum (the “2018 Subordinated Notes”), of which $3.0 million remains outstanding as of March 31, 2019.

Prudential received 585 Class A Units, representing an approximate 2% additional sharing percentage, for the issuance of the Carbon California 2018 Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding 2018 Subordinated Notes of $3.0 million. The Company then allocated the non-cash value of the units of approximately $490,000, which was recorded as a discount to the 2018 Subordinated Notes. As of March 31, 2019, Carbon California had an outstanding discount of $412,000 associated with these notes, which is presented net of the 2018 Subordinated Notes within Credit facility - related party on the unaudited consolidated balance sheets. During the three months ended March 31, 2019, Carbon California amortized $21,000 associated with the 2018 Subordinated Notes.

The 2018 Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively.

Prepayment of the 2018 Subordinated Notes is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted.

Restrictions and Covenants

The Senior Revolving Notes, Subordinated Notes and 2018 Subordinated Notes contain affirmative and negative covenants that, among other things, limit Carbon California’s ability to (i) incur additional debt; (ii) incur additional liens; (iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distributions on, or repurchases of, equity; (vi) make certain investments; (vii) enter into certain transactions with our affiliates; (viii) enter into sales-leaseback transactions; (ix) make optional or voluntary payments of debt; (x) change the nature of our business; (xi) change our fiscal year to make changes to the accounting treatment or reporting practices; (xii) amend constituent documents; and (xiii) enter into certain hedging transactions.

The affirmative and negative covenants are subject to various exceptions, including basket amounts and acceptable transaction levels. In addition, (i) the Senior Revolving Notes require Carbon California’s compliance, on a consolidated basis, with (A) a maximum Debt/EBITDA ratio of 4.0 to 1.0, stepping down to 3.5 to 1.0 starting with the quarter ending June 30, 2018, (B) a maximum Senior Revolving Notes/EBITDA ratio of 2.5 to 1.0, (C) a minimum interest coverage ratio of 3.0 to 1.0 and (D) a minimum current ratio of 1.0 to 1.0 and (ii) the Subordinated Notes require Carbon California’s compliance, on a consolidated basis, with (A) a maximum Debt/EBITDA ratio of 4.5 to 1.0, stepping down to 4.0 to 1.0 starting with the quarter ending June 30, 2018, (B) a maximum Senior Revolving Notes/EBITDA ratio of 3.0 to 1.0, (C) a minimum interest coverage ratio of 2.5 to 1.0, (D) an asset coverage test whereby indebtedness may not exceed the product of 0.65 times Adjusted PV-10 set forth in the most recent reserve report, (E) maintenance of a minimum borrowing base of $10,000,000 under the Senior Revolving Notes and (F) a minimum current ratio of 0.85 to 1.00.

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Income Taxes

3 Months Ended

Mar. 31, 2019

Income Tax Disclosure [Abstract]

Income Taxes

Note 8 – Income Taxes

We recognize deferred income tax assets and liabilities for the estimated future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. We have net operating loss carryforwards available in certain jurisdictions to reduce future taxable income. Future tax benefits for net operating loss carryforwards are recognized to the extent that realization of these benefits is considered more likely than not. To the extent that available evidence raises doubt about the realization of a deferred income tax asset, a valuation allowance is established.

At March 31, 2019 the Company has established a full valuation allowance against the balance of net deferred tax assets.

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Stockholders' Equity

3 Months Ended

Mar. 31, 2019

Equity [Abstract]

Stockholders' Equity

Note 9 – Stockholders’ Equity

Authorized and Issued Capital Stock

Effective March 15, 2017 and pursuant to a reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. References to the number of shares and price per share give retroactive effect to the reverse stock split for all periods presented. On June 1, 2018, we amended our charter to increase the number of authorized shares of our common stock from 10.0 million to 35.0 million.

As of March 31, 2019, we had 35.0 million shares of common stock authorized with a par value of $0.01 per share, of which approximately 7.8 million were issued and outstanding, and 1.0 million shares of preferred stock authorized with a par value of $0.01 per share. During the first three months of 2019, the increase in the Company’s issued and outstanding common stock was a result of restricted stock and performance units that vested during the period.

Carbon Stock Incentive Plans

We have two stock plans, the Carbon 2011 Stock Incentive Plan and the Carbon 2015 Stock Incentive Plan (collectively the “Carbon Plans”). The Carbon Plans were approved by our shareholders and in the aggregate provide for the issuance of approximately 1.1 million shares of common stock to our officers, directors, employees or consultants eligible to receive the awards under the Carbon Plans.

The Carbon Plans provide for the granting of incentive stock options, non-qualified stock options, restricted stock awards, performance awards and phantom stock awards, or a combination of the foregoing, to employees, officers, directors or consultants, provided that only employees may be granted incentive stock options and directors may only be granted restricted stock awards and phantom stock awards.

Restricted Stock

As of March 31, 2019, approximately 649,000 shares of restricted stock have been granted under the terms of the Carbon Plans. Restricted stock awards for employees vest ratably over a three-year service period or cliff vest at the end of a three-year service period. For non-employee directors, the awards vest upon the earlier of a change in control of us or the date their membership on the Board of Directors is terminated other than for cause. During the three months ended March 31, 2019, approximately 40,000 restricted stock units vested.

Compensation costs recognized for these restricted stock grants were approximately $179,000 for the three months ended March 31, 2019. For the three months ended March 31, 2018, we recognized compensation expense of approximately $158,000. As of March 31, 2019, there was approximately $1.2 million unrecognized compensation costs related to these restricted stock grants which we expect to be recognized over the next six years.

Restricted Performance Units

As of March 31, 2019, approximately 621,000 shares of performance units have been granted under the terms of the Carbon Plans. Performance units represent a contractual right to receive one share of our common stock subject to the terms and conditions of the agreements, including the achievement of certain performance measures relative to a defined peer group or the growth of certain performance measures over a defined period of time as well as, in some cases, continued service requirements.

We account for the performance units granted during 2015 through 2018 at their fair value determined at the date of grant, which were $8.00, $5.40, $7.20 and $9.80 per share, respectively. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At March 31, 2019, we estimated that none of the performance units granted in 2017 and 2018 would vest, and, accordingly, no compensation cost has been recorded for these performance units. We estimated that it was probable that the performance units granted in 2015 and 2016 would vest and therefore compensation costs of approximately $43,000 and $135,000 related to these performance units were recognized for the three months ended March 31, 2019 and 2018, respectively. As of March 31, 2019, compensation costs related to the performance units granted in 2015 and 2016 have been fully recognized. As of March 31, 2019, if change in control and other performance provisions pursuant to the terms and conditions of these award agreements are met in full, the estimated unrecognized compensation cost related to the performance units granted in 2012, 2017 and 2018 would be approximately $2.7 million.

Preferred Stock

Series B Convertible Preferred Stock - Related Party

In connection with the closing of the Seneca Acquisition, we raised $5.0 million through the issuance of 50,000 shares of Preferred Stock to Yorktown. The Preferred Stock converts into common stock at the election of the holder or will automatically convert into shares of our common stock upon completion of a qualifying equity financing event. The number of shares of common stock issuable upon conversion is dependent upon the price per share of common stock issued in connection with any such qualifying equity financing but has a floor conversion price equal to $8.00 per share. The conversion ratio at which the Preferred Stock will convert into common stock is equal to an amount per share of $100 plus all accrued but unpaid dividends payable in respect thereof divided by the greater of (i) $8.00 per share or (ii) the price that is 15% less than the lowest price per share of shares sold to the public in the next equity financing. Using the floor of $8.00 per share would yield 12.5 shares of common stock for every unit of Preferred Stock. The conversion price will be proportionately increased or decreased to reflect changes to the outstanding shares of common stock, such as the result of a combination, reclassification, subdivision, stock split, stock dividend or other similar transaction involving the common stock. Additionally, after the third anniversary of the issuance of the Preferred Stock, we have the option to redeem the shares for cash.

The Preferred Stock accrues cash dividends at a rate of six percent (6%) of the initial issue price of $100 per share per annum. The holders of the Preferred Stock are entitled to the same number of votes of common stock that such share of Preferred Stock would represent on an as converted basis. The holders of the Preferred Stock receive liquidation preference based on the initial issue price of $100 per share plus a preferred return over common stock holders and the holders of any junior ranking stock. As of March 31, 2019, the preferred return was approximately $299,000.

We apply the guidance in ASC 480 “Distinguishing Liabilities from Equity” when determining the classification and measurement of the Preferred Stock. The Preferred Stock does not feature any redemption rights within the holders’ control or conditional redemption features not within our control as of March 31, 2019. Accordingly, the Preferred Stock is presented as a component of consolidated stockholders’ equity.

We have evaluated the Preferred Stock in accordance with ASC 815, “Derivatives and Hedging”, including consideration of embedded derivatives requiring bifurcation. The issuance of the Preferred Stock could generate a beneficial conversion feature (“BCF”), which arises when a debt or equity security is issued with an embedded conversion option that is beneficial to the investor or in the money at inception because the conversion option has an effective strike price that is less than the market price of the underlying stock at the commitment date. Based on the conversion terms and the price at the commitment date, we determined that a BCF was required to be recorded related to the voluntary conversion option by the holder as of March 31, 2019. We recorded the BCF as a reduction of retained earnings and an increase to Additional Paid in Capital (“APIC”) of $1.1 million, which is based on the difference between the floor price of $8.00 and our stock price as of the commitment date multiplied by the number of shares to be issued. We are also required to evaluate a contingent BCF for the automatic conversion feature, but in accordance with ASC 470, “Debt”, we will not record the effect of the BCF until the contingency is resolved.

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Revenue Recognition

3 Months Ended

Mar. 31, 2019

Revenue Recognition and Deferred Revenue [Abstract]

Revenue Recognition

Note 10 – Revenue Recognition

Revenue from Contracts with Customers

The Company recognizes revenue in accordance with FASB ASC Topic 606 – Revenue Recognition (“ASC 606”).  Revenue is recognized when it satisfies a performance obligation by transferring control over a product to a customer. Revenue is measured based on the consideration we expect to receive in exchange for those products. Revenues from contracts with customers are recorded on the unaudited consolidated statements of operations based on the type of product being sold.

Performance Obligations and Significant Judgments

We sell oil and natural gas products in the United States through a single reportable segment. We primarily sell products within two regions of the United States: Appalachian Basin and Ventura Basin. We enter into contracts that generally include one type of distinct product in variable quantities and priced based on a specific index related to the type of product. Most of our contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions.

The oil and natural gas is typically sold in an unprocessed state to third party purchasers. We recognize revenue based on the net proceeds received from the purchaser when control of the oil or natural gas passes to the purchaser. For oil sales, control is typically transferred to the purchaser upon receipt at the wellhead or a contractually agreed upon delivery point. Under our natural gas contracts with purchasers, control transfers upon delivery at the wellhead or the inlet of the purchaser’s system. For our other natural gas contracts, control transfers upon delivery to the inlet or to a contractually agreed upon delivery point.

Transfer of control drives the presentation of transportation and gathering costs within the accompanying unaudited consolidated statements of operations. Transportation and gathering costs incurred prior to control transfer are recorded within the transportation and gathering expense line item on the accompanying unaudited consolidated statements of operations, while transportation and gathering costs incurred subsequent to control transfer are recognized as a reduction to the related revenue.

A portion of our product sales are short-term in nature. For those contracts, we use the practical expedient in ASC 606 exempting us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606 which states we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to an unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore, future volumes are unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. We have no unsatisfied performance obligations at the end of each reporting period.

We do not believe that significant judgments are required with respect to the determination of the transaction price, including any variable consideration identified. There is a low level of uncertainty due to the precision of measurement and use of index-based pricing with predictable differentials. Additionally, any variable consideration identified is not constrained.

Disaggregation of Revenues

In the following tables, revenue for the three months ended March 31, 2019, is disaggregated by primary region within the United States and major product line. As noted above, we operate as one reportable segment.

For the three months ended March 31, 2019:

(in thousands)
Type	Appalachian Basin		Ventura Basin		Total
Natural gas sales	$	18,792	$	524	$	19,316
Natural gas liquids sales		-		247		247
Oil sales		1,537		7,452		8,989
Transportation and handling		734		-		734
Marketing gas sales		4,944		-		4,944
Total revenue	$	26,007	$	8,223	$	34,230

Contract Balances

Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not typically give rise to contract assets or liabilities under ASC 606.

Prior Period Performance Obligations

We record revenue in the month production is delivered to the purchaser, but settlement statements may not be received until 30 to 90 days after the month of production. As such, we estimate the production delivered and the related pricing. Any differences between our initial estimates and actuals are recorded in the month payment is received from the customer. These differences have not historically been material. For the three months ended March 31, 2019, revenue recognized in the reporting period related to prior period performance obligations is immaterial.

The estimated revenue is recorded within Accounts receivable – Revenue on the unaudited consolidated balance sheets.

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Accounts Payable and Accrued Liabilities

3 Months Ended

Mar. 31, 2019

Payables and Accruals [Abstract]

Accounts Payable and Accrued Liabilities

Note 11 – Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities at March 31, 2019 and December 31, 2018 consist of the following:

(in thousands)	March 31, 2019		December 31, 2018
Accounts payable	$	6,064	$	7,670
Oil and gas revenue suspense		2,766		2,675
Gathering and transportation payables		1,228		1,774
Production taxes payable		2,411		1,860
Accrued operating costs		2,431		3,155
Accrued ad valorem taxes – current		3,731		3,474
Accrued general and administrative expenses		2,217		3,111
Accrued asset retirement obligation – current		3,392		3,099
Accrued interest		1,543		955
Accrued gas purchases		2,959		5,440
Other liabilities		1,278		1,603
Total accounts payable and accrued liabilities	$	30,020	$	34,816

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Fair Value Measurements

3 Months Ended

Mar. 31, 2019

Fair Value Disclosures [Abstract]

Fair Value Measurements

Note 12 – Fair Value Measurements

Authoritative guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of us. Unobservable inputs are inputs that reflect our assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

Level 1: Quoted prices are available in active markets for identical assets or liabilities;

Level 2: Quoted prices in active markets for similar assets or liabilities that are observable for the asset or liability; or

Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our policy is to recognize transfers in and/or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. We have consistently applied the valuation techniques discussed below for all periods presented.

The following table presents our financial assets and liabilities that were accounted for at fair value on a recurring basis by level within the fair value hierarchy:

(in thousands)	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Total
March 31, 2019
Assets:
Commodity derivatives	$	-	$	147	$	-	$	147
Liabilities:
Commodity derivatives	$	-	$	1,975	$	-	$	1,975
December 31, 2018
Asset:
Commodity derivatives	$	-	$	7,022	$	-	$	7,022

Commodity Derivative

As of March 31, 2019, our commodity derivative financial instruments are comprised of natural gas and oil swaps and costless collars. The fair values of these agreements are determined under an income valuation technique. The valuation model requires a variety of inputs, including contractual terms, published forward prices, volatilities for options and discount rates, as appropriate. Our estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, our credit worthiness and the time value of money. The consideration of these factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. All the significant inputs are observable, either directly or indirectly; therefore, our derivative instruments are included within the Level 2 fair value hierarchy. The counterparty for all our outstanding commodity derivative financial instruments as of March 31, 2019, is BP Energy Company.

Assets and Liabilities Measured and Recorded at Fair Value on a Non-Recurring Basis

The fair value of each of the following assets and liabilities measured and recorded at fair value on a non-recurring basis are based on unobservable pricing inputs and therefore, are included within the Level 3 fair value hierarchy.

The fair value of the non-controlling interest in the partnerships we are required to consolidate was determined based on the net discounted cash flows of the proved developed producing properties attributable to the non-controlling interests in these partnerships.

We assume, at times, certain firm transportation contracts as part of our acquisitions of oil and natural gas properties. The fair value of the firm transportation contract obligations was determined based upon the contractual obligations assumed by us and discounted based upon our effective borrowing rate. These contractual obligations are reduced on a monthly basis as we pay these firm transportation obligations in the future.

The fair value measurements associated with the assets acquired and liabilities assumed in the business combination for the OIE Membership Acquisition of Carbon Appalachia are outlined within Note 3.

Debt Discount

The fair value of the debt discount from the 1,425 and 585 additional Class A Units issued in connection with the Subordinated Notes and 2018 Subordinated Notes was $1.3 million and $490,000, respectively. The debt discount was a Level 3 fair value assessment and was based on the relative fair value of Class A Units. Class A Units were issued contemporaneously at $1,000 per Class A Unit.

Asset Retirement Obligation

The fair value of our asset retirement obligation liability is recorded in the period in which it is incurred or assumed by taking into account the cost of abandoning oil and gas wells ranging from $20,000 to $45,000, which is based on our historical experience and industry expectations for similar work; the estimated timing of reclamation ranging from one to 75 years based on estimates from reserve engineers; an inflation rate between 1.52% to 2.79%; and a credit adjusted risk-free rate between 3.28% to 8.27%, which takes into account our credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs (see Note 3). During the three month period ended March 31, 2019, we did not record any additions to asset retirement obligations. We use the income valuation technique to estimate the fair value of asset retirement obligations using the amounts and timing of expected future dismantlement costs, credit-adjusted risk-free rates and time value of money.

Class B Units

We received Class B units from Carbon California and Carbon Appalachia as part of the entry into the Carbon California LLC Agreement and Carbon Appalachia LLC Agreement, respectively. We estimated the fair value of the Class B units, in each case, by utilizing the assistance of third-party valuation specialists. The fair values were based upon enterprise values derived from inputs including estimated future production rates, future commodity prices including price differentials as of the dates of closing, future operating and development costs and comparable market participants.

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Commodity Derivatives

3 Months Ended

Mar. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Commodity Derivatives

Note 13 – Commodity Derivatives

We historically use commodity-based derivative contracts to manage exposures to commodity price on a portion of our oil and natural gas production. We do not hold or issue derivative financial instruments for speculative or trading purposes. We also have entered into, on occasion, oil and natural gas physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. These contracts are not recorded at fair value in the unaudited condensed consolidated financial statements.

Pursuant to the terms of our credit facilities with LegacyTexas Bank and Prudential, we have entered into swap and costless collar derivative agreements to hedge a portion of our oil and natural gas production through 2021. As of March 31, 2019, these derivative agreements consisted of the following:

	Natural Gas Swaps				Natural Gas Collars
			Weighted Average				Weighted Average Price
Year	MMBtu		Price (a)		MMBtu		Range (a)
2019		11,762,000,	$	2.82		374,000	$	2.60 – $3.03
2020		12,433,000	$	2.73		1,018,000	$	2.50 – $2.70
2021		6,448,000	$	2.58		-	$	-

	Oil Swaps								Oil Collars
Year	WTI Bbl		Weighted Average  Price (b)		Brent Bbl		Weighted Average Price (c)		WTI Bbl		Weighted  Average Price (b)		Brent Bbl		Weighted  Average Price (c)
2019		180,775	$	53.46		121,079	$	66.93		-		-		29,800	$	47.00 - $75.00
2020		121,147	$	55.37		151,982	$	66.03		18,000	$	47.00 - $60.15		37,400	$	47.00 - $75.00
2021		-	$	-		86,341	$	67.12		30,000	$	47.00 - $60.15		98,000	$	47.00 - $75.00

*	Includes 100% of Carbon California’s outstanding derivative hedges at March 31, 2019, and not our proportionate share.
(a)	NYMEX Henry Hub Natural Gas futures contract for the respective period.
(b)	NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective period.
(c)	Brent future contracts for the respective period.

For our swap instruments, we receive a fixed price for the hedged commodity and pay a floating price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. Costless collars are designed to establish floor and ceiling prices on anticipated future oil and gas production. The ceiling establishes a maximum price that the Company will receive for the volumes under contract, while the floor establishes a minimum price.

The following table summarizes the fair value of the derivatives recorded in the unaudited consolidated balance sheets.

These derivative instruments are not designated as cash flow hedging instruments for accounting purposes:

(in thousands)	March 31, 2019		December 31, 2018
Commodity derivative contracts:
Commodity derivative asset	$	-	$	3,517
Commodity derivative asset – non-current	$	147	$	3,505
Commodity derivative liability	$	1,657	$	-
Commodity derivative liability – non-current	$	318	$	-

The table below summarizes the commodity settlements and unrealized gains and losses related to the Company’s derivative instruments for the three months ended March 31, 2019 and 2018. These commodity derivative settlements and unrealized gains and losses are recorded and included in commodity derivative income or loss in the accompanying unaudited consolidated statements of operations. 

	Three Months Ended March 31,
(in thousands)	2019			2018
Commodity derivative contracts:
Settlement losses	$	(456	)	$	(377	)
Unrealized losses		(8,850	)		(249	)
Total settlement and unrealized losses, net	$	(9,306	)	$	(626	)

Commodity derivative settlement gains and losses are included in cash flows from operating activities in our unaudited consolidated statements of cash flows.

The counterparty in all of our derivative instruments is BP Energy Company. We have entered into ISDA Master Agreements with BP Energy Company that establishes standard terms for the derivative contracts and inter-creditor agreements with LegacyTexas Bank, Prudential and BP Energy Company whereby any credit exposure related to the derivative contracts entered into by us and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facilities.

We net our derivative instrument fair value amounts executed with BP Energy Company pursuant to ISDA master agreements, which provides for the net settlement over the term of the contracts and in the event of default or termination of the contracts. The following table summarizes the location and fair value amounts of all derivative instruments in the unaudited consolidated balance sheet, as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited consolidated balance sheet as of March 31, 2019.

						Net
	Gross					Recognized
	Recognized		Gross			Fair Value
	Assets/		Amounts			Assets/
Balance Sheet Classification (in thousands)	Liabilities		Offset			Liabilities
Commodity derivative assets:
Commodity derivative asset	$	1,063	$	(1,063	)	$	-
Commodity derivative asset – non-current		2,049		(1,902	)		147
Total derivative assets	$	3,112	$	(2,965	)	$	147
Commodity derivative liabilities:
Commodity derivative liability	$	2,720	$	(1,063	)	$	(1,657	)
Commodity derivative liability – non-current		2,220		(1,902	)		(318	)
Total derivative liabilities	$	4,940	$	(2,965	)	$	(1,975	)

Due to the volatility of oil and natural gas prices, the estimated fair value of our derivatives are subject to fluctuations from period to period. 

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Leases

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Leases

Note 14 – Leases

On January 1, 2019, we adopted ASC 842. Results for reporting periods beginning January 1, 2019 are presented in accordance with ASC 842, while prior period amounts are reported in accordance with FASB ASC Topic 840 – Leases. On January 1, 2019, we recognized approximately $7.7 million in right-of-use assets and approximately $7.7 million in lease liabilities, representing the present value of minimum payment obligations associated with compressor, vehicle, and office space operating leases with non-cancellable lease terms in excess of one year. We do not have any finance leases, nor are we the lessor in any leasing arrangements. We have elected certain practical expedients available under ASC 842 including those that permit us to (i) account for lease and non-lease components in our contracts as a single lease component for all asset classes; (ii) not evaluate existing and expired land easements; (iii) not apply the recognition requirements of ASC 842 to leases with a lease term of twelve months or less; and (iv) retain our existing lease assessment and classification. As such, there was no cumulative-effect adjustment to retained earnings required at January 1, 2019. Additionally, the Company has elected the short-term lease recognition exemption for all classes of underlying assets and therefore, leases with a term of one year or less will not be recognized on the unaudited consolidated balance sheet. 

The lease amounts disclosed herein are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners, and our net share of these costs, once paid, are included in lease operating expenses, pipeline operating expenses or general and administrative expenses, as applicable.

During the three months ended March 31, 2019, we did not acquire any right-of-use assets or incur any lease liabilities. Our right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet at $7.3 million as of March 31, 2019. All leases recognized on our unaudited consolidated balance sheet are classified as operating leases, which include leases related to the asset classes reflected in the table below:

(in thousands)	Right-of-Use Assets		Lease Liability
Compressors	$	4,178	$	4,178
Corporate leases		2,433		2,438
Vehicles		645		645
Total	$	7,256	$	7,261

We recognize lease expense on a straight-line basis excluding short-term and variable lease payments which are recognized as incurred. Short-term lease cost represents payments for leases with a lease term of one year or less, excluding leases with a term of one month or less. Short-term leases include certain compressors and vehicles that have a non-cancellable lease term of less than one year.

The following table summarizes the components of our gross operating lease costs incurred during the three months ended March 31, 2019:

(in thousands)	Three Months Ended March 31, 2019
Operating lease cost	$	531
Short-term lease cost		161
Total lease cost	$	692

We do not have any leases with an implicit interest rate that can be readily determined. As a result, we calculate collateralized incremental borrowing rates to use as discount rates. We utilize the benchmark rates defined in our credit facilities, and adjust for facility utilization and term considerations, to establish collateralized incremental borrowing rates. Refer to Note 7 for additional information on our credit facilities.

Our weighted-average lease term and discount rate used are as follows:

(in thousands)	Three Months Ended March 31, 2019
Weighted-average lease term (years)		4.3
Weighted-average discount rate		6.34	%

The following table summarizes supplemental cash flow information related to leases:

Cash paid for amounts included in measurement of lease liabilities (in thousands)	Three Months Ended March 31, 2019
Operating cash flows for operating leases	$	526

Minimum future commitments by year for our long-term operating leases as of March 31, 2019 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet as follows:

(in thousands)	Amount
Remainder of 2019	$	1,535
2020		1,946
2021		1,889
2022		1,718
2023		1,222
Thereafter		11
Total lease payments	$	8,321
Less: imputed interest		(1,060	)
Total lease liability	$	7,261

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 15 – Commitments and Contingencies

We have entered into employment agreements with certain of our executives and officers. The term of the agreements generally ranges from one to two years and provides for renewal provisions in one-year increments thereafter. The agreements provide for, among other items, severance and continuation of benefit payments upon termination of employment or certain change of control events.

We have entered into non-current firm transportation contracts to ensure the transport for certain of our gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts at March 31, 2019 are summarized in the table below.

Period	Dekatherms per day		Demand Charges
Apr 2019 – Mar 2020		58,871	$	0.20 - 0.62
Apr 2020 – May 2020		57,791	$	0.20 - 0.56
Jun 2020 – Oct 2020		56,641	$	0.20 - 0.56
Nov 2020 – Aug 2022		50,341	$	0.20 - 0.56
Sep 2022 – May 2027		30,990	$	0.20 - 0.21
Jun 2027 – May 2036		1,000	$	0.20

As of March 31, 2019, the remaining commitment related to the firm transportation contracts assumed in the EXCO Acquisition in 2016 and OIE Membership Acquisition is $17.8 million and reflected in the Company’s unaudited consolidated balance sheet. The fair values of these firm transportation obligations were determined based upon the contractual obligations assumed by the Company and discounted based upon the Company’s effective borrowing rate. These contractual obligations are being reduced monthly as the Company pays these firm transportation obligations in the future.

Natural gas processing agreement

We have entered into an initial five-year gas processing agreement. We have an option to extend the term of the agreement by another five years. The related demand charges for volume commitments over the remaining term of the agreement at March 31, 2019 are approximately $1.8 million per year. We will pay a processing fee of $2.50 per MCF for the term of the agreement, with a minimum annual volume commitment of 720,000 MCF.

Capital Commitments

As of March 31, 2019, we had no capital commitments associated with Carbon California. 

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Supplemental Cash Flow Disclosure

3 Months Ended

Mar. 31, 2019

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Disclosure

Note 16 – Supplemental Cash Flow Disclosure

Supplemental cash flow disclosures for the three months ended March 31, 2019 and 2018 are presented below:

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

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Subsequent Events

3 Months Ended

Mar. 31, 2019

Subsequent Events [Abstract]

Subsequent Events

Note 17 – Subsequent Events

We evaluated activities from March 31, 2019, to the date these financial statements were available for issuance. We believe there are no subsequent events requiring recognition or disclosure.

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Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2019

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information. Accordingly, they do not include all the information and footnotes required by GAAP for complete financial statements. In the opinion of management, the accompanying unaudited condensed consolidated financial statements include all adjustments considered necessary to present fairly our financial position as of March 31, 2019, and our results of operations and cash flows for the three months ended March 31, 2019 and 2018. Operating results for the three months ended March 31, 2019 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results, seasonality, and other factors. The unaudited condensed consolidated financial statements and related notes included in this Quarterly Report on Form 10-Q should be read in conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2018. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in our 2018 Annual Report on Form 10-K.

Principles of Consolidation

Principles of Consolidation

The unaudited condensed consolidated financial statements include the accounts of our consolidated subsidiaries. Upon the closing of the OIE Membership Acquisition on December 31, 2018, we own 100% of Carbon Appalachia. In addition, we own 100% of Nytis USA, which owns approximately 98.1% of Nytis LLC. Nytis LLC holds interests in various oil and gas partnerships.

Partnerships and subsidiaries in which we have a controlling interest are consolidated. We are currently consolidating 46 partnerships, Carbon Appalachia, and Carbon California, and we reflect the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on our unaudited consolidated statements of operations and also reflect the non-controlling ownership interest in the net assets of the partnerships as non-controlling interests within stockholders’ equity on our unaudited consolidated balance sheets. All significant intercompany accounts and transactions have been eliminated.

In accordance with established practice in the oil and gas industry, our unaudited condensed consolidated financial statements also include our pro-rata share of assets, liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which we have a non-controlling interest.

Non-majority owned investments that do not meet the criteria for pro-rata consolidation are accounted for using the equity method when we have the ability to significantly influence the operating decisions of the investee. When we do not have the ability to significantly influence the operating decisions of an investee, the cost method is used. All transactions, if any, with investees have been eliminated in the accompanying unaudited condensed consolidated financial statements.

Reclassifications

Reclassifications

Certain prior period balances in the consolidated balance sheets and statements of operations have been reclassified to conform to the current year presentation.  Specifically, a portion of credit facilities and notes payable balances as of December 31, 2018 were reclassified from non-current liabilities to current liabilities.  This reclassification had no impact on net income, cash flows or shareholders’ equity previously reported.

Insurance Receivable

Insurance Receivable

Insurance receivable is comprised of insurance claims for the loss of property as a result of wildfires that impacted Carbon California in December 2017. The Company filed claims with its insurance provider. In January 2019, we reached a settlement agreement and received an $800,000 payment from our insurance provider related to the damage caused by the California wildfires. As of March 31, 2019, we are in receipt of all funds associated with the claims.  

Accounting for Oil and Gas Operations

Accounting for Oil and Gas Operations

We use the full cost method of accounting for oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Overhead costs incurred that are directly identified with acquisition, exploration and development activities undertaken by the Company for its own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized.

Unproved properties are excluded from amortized capitalized costs until it is determined if proved reserves can be assigned to such properties. We assess our unproved properties for impairment at least annually. Significant unproved properties are assessed individually.

Capitalized costs are depleted by an equivalent unit-of-production method, converting oil to gas at the ratio of one barrel of oil to six thousand cubic feet of natural gas. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.

No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves. All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.

We perform a ceiling test quarterly. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value based measurement, rather it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using the un-weighted arithmetic average of the first-day-of-the month price for the previous twelve month period, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs. Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds the capitalized costs in future periods.

For the three months ended March 31, 2019 and 2018, we did not recognize a ceiling test impairment as our full cost pool did not exceed the ceiling limitations. Future declines in oil and natural gas prices could result in impairments of our oil and gas properties in future periods. The effect of price declines will impact the ceiling test value until such time commodity prices stabilize or improve. Impairments are a non-cash charge and accordingly would not affect cash flows but would adversely affect our results of operations and members’ equity.

We capitalize the portion of general and administrative costs that is attributable to our acquisition, exploration and development activities.

Revenue

Revenue

We recognize revenues for sales and services when persuasive evidence of an arrangement exists, when custody is transferred, or services are rendered, fees are fixed or determinable and collectability is reasonably assured.

Oil, Natural Gas and Natural Gas Liquid Sales

Oil, natural gas and natural gas liquid sales are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred, and collectability is reasonably assured. Revenues are recognized based on our net revenue interest.

Marketing Gas Sales

We sell production purchased from third parties as well as production from our own oil and gas producing properties. Marketing gas sales are recognized on a gross basis as we purchase and take control of the gas prior to sale and are the principal in the transaction.

Storage

Under fee-based arrangements, we receive a fee for storing natural gas. The revenues earned are directly related to the volume of natural gas that flows through our systems and are not directly dependent on commodity prices.

Transportation, gathering, and compression

We generally purchase natural gas from producers at the wellhead or other receipt points, gather the wellhead natural gas through our gathering systems, and then sell the natural gas based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of natural gas or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, regardless of the actual amount of the sales proceeds we receive. Our revenues under percent-of-proceeds/index arrangements generally correlate to the price of natural gas.

Investments in Affiliates

Investments in Affiliates

Investments in non-consolidated affiliates are accounted for under either the cost or equity method of accounting, as appropriate. The cost method of accounting is generally used for investments in affiliates in which we have less than 20% of the voting interests of a corporate affiliate (or less than a 3% to 5% interest of a partnership or limited liability company) and do not have significant influence. Investments in non-consolidated affiliates, accounted for using the cost method of accounting, are recorded at cost and impairment assessments for each investment are made annually to determine if a decline in the fair value of the investment, other than temporary, has occurred. A permanent impairment is recognized if a decline in the fair value occurs.

If we hold between 20% and 50% of the voting interest in non-consolidated corporate affiliates or generally greater than a 3% to 5% interest of a partnership or limited liability company and can exert significant influence or control (e.g., through our influence with a seat on the board of directors or management of operations), the equity method of accounting is generally used to account for the investment. Equity method investments will increase or decrease by our share of the affiliate’s profits or losses and such profits or losses are recognized in our unaudited consolidated statements of operations. We review equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred. Upon the exercise of the California Warrant on February 1, 2018 and the closing of the OIE Membership Acquisition on December 31, 2018, we consolidate Carbon California and Carbon Appalachia for financial reporting purposes and no longer account for these investments under the equity method.

Related Party Transactions

Related Party Transactions

Management Reimbursements

In our role as manager of Carbon California and Carbon Appalachia we receive reimbursements for management services. Prior to consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, these management service reimbursements were included in general and administrative – related party reimbursement on our unaudited consolidated statements of operations. As we now consolidate both Carbon California and Carbon Appalachia, these reimbursements are eliminated upon consolidation.

We received approximately $753,000 and $50,000 for the three months ended March 31, 2018, and for the one month ended January 31, 2018, from Carbon Appalachia and Carbon California, respectively. These reimbursements are included in general and administrative – related party reimbursement on our unaudited consolidated statements of operations. Effective February 1, 2018, the management reimbursements received from Carbon California were eliminated at consolidation. This elimination included $100,000 for the period February 1, 2018, through March 31, 2018.

In addition to the management reimbursements, approximately $299,000 and $14,000 in general and administrative expenses were reimbursed for the three months ended March 31, 2018, and for the one month ended January 31, 2018, by Carbon Appalachia and Carbon California, respectively. The elimination of Carbon California in consolidation includes approximately $28,000 for the period February 1, 2018, through March 31, 2018.

Operating Reimbursements

In our role as operator of Carbon California and Carbon Appalachia, we receive reimbursements of operating expenses. Prior to consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, these operating reimbursements were included in operating expenses on our unaudited consolidated statements of operations. As we now consolidate both Carbon California and Carbon Appalachia, any intercompany receivable and payable balances associated with these reimbursements are eliminated upon consolidation.

Carbon California Credit Facilities

The credit facilities of Carbon California, including the Senior Revolving Notes, Carbon California Notes and Carbon California 2018 Subordinated Notes (all defined below), are held by Prudential (see Note 7).

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and expenses and disclosure of contingent assets and liabilities. Significant items subject to such estimates and assumptions include the carrying value of oil and gas properties, estimates of proved oil and gas reserve volumes and the related depletion and present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, determining the amounts recorded for fair value of commodity derivative instruments, fair value of assets acquired and liabilities assumed qualifying as business combinations or asset acquisitions, estimated lives of other property and equipment, asset retirement obligations, fair value of Class B issuances and accrued liabilities and revenues. There have been no changes in our critical accounting estimates from those that were disclosed in the 2018 Annual Report on Form 10-K. Actual results could differ from these estimates.

Earnings (Loss) Per Common Share

Earnings (Loss) Per Common Share

Basic earnings per common share is computed by dividing the net income or loss attributable to common stockholders for the period by the weighted average number of common shares outstanding during the period. The shares of restricted common stock granted to our officers, directors and employees are included in the computation of basic net income per share only after the shares become fully vested. Diluted earnings per common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise of options and warrants to acquire common stock computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by us with the proceeds from the exercise of options and warrants (which were assumed to have been made at the average market price of the common shares during the reporting period).

In periods when we report a net loss, all shares of restricted stock are excluded from the calculation of diluted weighted average shares outstanding because of its anti-dilutive effect on loss per share. As a result, approximately 269,000 potentially dilutive restricted stock awards are excluded from the calculation of diluted earnings per common share for the three months ended March 31, 2019. In addition, approximately 200,000 restricted performance units subject to future contingencies were excluded in the basic and diluted income per share calculations.

For the three months ended March 31, 2018, we had net income and the diluted income per common share calculation includes the dilutive effects of approximately 230,000 non-vested shares of restricted stock. In addition, approximately 254 ,000 restricted performance units subject to future contingencies were excluded in the basic and diluted income per share calculations.

The following table sets forth the calculation of basic and diluted (loss) income per share:

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

Recently Adopted Accounting Pronouncement

Recently Adopted Accounting Pronouncement

In February 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The FASB subsequently issued various ASUs which provided additional implementation guidance, and these ASUs collectively make up FASB Accounting Standards Codification (“ASC”) Topic 842 – Leases (“ASC 842”). ASC 842 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The standard permits retrospective application through recognition of a cumulative-effect adjustment at the beginning of either the earliest reporting period presented or the period of adoption. The Company adopted ASC 842 effective January 1, 2019 using the modified retrospective method as of the adoption date. Adoption of the standard resulted in the recognition of additional lease assets and liabilities on our unaudited consolidated balance sheet as well as additional disclosures. The adoption did not have a material impact to our unaudited consolidated statement of operations. Refer to Note 14 for further information on our implementation of this standard.

Recently Issued Accounting Pronouncements

Recently Issued Accounting Pronouncements

There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows.

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Summary of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2019

Accounting Policies [Abstract]

Schedule of basic and diluted income (loss) per share

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

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Acquisitions and Divestitures (Tables)

3 Months Ended

Mar. 31, 2019

Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]

Schedule of unaudited pro-forma consolidated results

	Three Months Ended March 31,			Three Months Ended March 31,
(in thousands, except per share amounts)	2019			2018
Revenue	$	24,950		$	6,672
Net (loss) income before non-controlling interests	$	(6,690	)	$	3,543
Net (loss) income attributable to non-controlling interests	$	(2,590	)	$	1,115
Net (loss) income attributable to common shareholders	$	(4,175	)	$	2,428
Net (loss) income per share (basic)	$	(0.54	)	$	0.35
Net (loss) income per share (diluted)	$	(0.54	)	$	0.30

OIE Membership Acquisition [Member]

Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]

Schedule of fair value of business acquired

	Amount  (in thousands)
Cash consideration	$	33,000
Old Ironsides Notes		25,065
Fair value of previously held equity interest		14,158
Fair value of business acquired	$	72,223

Schedule of assets acquired and liabilities assumed

	Amount (in thousands)
Cash	$	12,283
Accounts receivable:
Revenue		12,834
Trade receivable		1,941
Commodity derivative asset		198
Inventory		900
Prepaid expenses, deposits, and other current assets		456
Oil and gas properties:
Proved		107,499
Unproved		1,869
Other property, plant and equipment, net		15,626
Other non-current assets		514
Accounts payable and accrued liabilities		(19,114	)
Due to related parties		(458	)
Firm transportation contract obligations		(18,724	)
Asset retirement obligations		(5,626	)
Notes payable		(37,975	)
Total net assets acquired	$	72,223

Schedule of unaudited pro-forma consolidated results

	Three Months Ended March 31,			Three Months Ended March 31,
(in thousands, except per share amounts)	2019			2018
Revenue	$	24,950		$	32,316
Net (loss) income before non-controlling interests	$	(6,690	)	$	6,912
Net (loss) income attributable to non-controlling interests	$	(2,590	)	$	1,115
Net (loss) income attributable to common shareholders	$	(4,175	)	$	5,797
Net (loss) income per share (basic)	$	(0.54	)	$	0.83
Net (loss) income per share (diluted)	$	(0.54	)	$	0.77

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Property and Equipment (Tables)

3 Months Ended

Mar. 31, 2019

Property, Plant and Equipment [Abstract]

Schedule of net property and equipment

(in thousands)	March 31, 2019			December 31, 2018
Oil and gas properties:
Proved oil and gas properties	$	344,147		$	343,736
Unproved properties not subject to depletion		5,385			5,416
Accumulated depreciation, depletion, amortization and impairment		(98,826	)		(95,281	)
Net oil and gas properties		250,706			253,871
Pipeline facilities and equipment		12,714			12,714
Base gas		2,122			2,122
Furniture and fixtures, computer hardware and software, and other equipment		6,688			6,649
Accumulated depreciation and amortization		(4,356	)		(3,922	)
Net other property and equipment		17,168			17,563
Total net property and equipment	$	267,874		$	271,434

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Asset Retirement Obligation (Tables)

3 Months Ended

Mar. 31, 2019

Asset Retirement Obligation Tables Abstract

Summary of reconciliation of the ARO

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

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Credit Facilities and Notes Payable (Tables)

3 Months Ended

Mar. 31, 2019

Debt Disclosure [Abstract]

Schedule of outstanding credit facilities and notes payable

(in thousands)	March 31, 2019			December 31, 2018
2018 Credit Facility – revolver	$	70,150		$	69,150
2018 Credit Facility – term note		13,333			15,000
Old Ironsides Notes		23,659			25,065
Other debt		48			57
Total principal		107,190			109,272
Less:  unamortized debt discount		(112	)		(134	)
Total credit facilities and notes payable	$	107,078		$	109,138

Schedule of outstanding notes payable – related party

(in thousands)	March 31, 2019			December 31, 2018
Senior Revolving Notes, related party, due February 15, 2022	$	38,500		$	38,500
Subordinated Notes, related party, due February 15, 2024		13,000			13,000
Total principal		51,500			51,500
Less: Deferred notes costs		(255	)		(235	)
Less: unamortized debt discount		(1,281	)		(1,346	)
Total notes payable – related party	$	49,964		$	49,919

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Revenue Recognition (Tables)

3 Months Ended

Mar. 31, 2019

Revenue Recognition and Deferred Revenue [Abstract]

Schedule of disaggregation of revenue

(in thousands)
Type	Appalachian Basin		Ventura Basin		Total
Natural gas sales	$	18,792	$	524	$	19,316
Natural gas liquids sales		-		247		247
Oil sales		1,537		7,452		8,989
Transportation and handling		734		-		734
Marketing gas sales		4,944		-		4,944
Total revenue	$	26,007	$	8,223	$	34,230

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Accounts Payable and Accrued Liabilities (Tables)

3 Months Ended

Mar. 31, 2019

Payables and Accruals [Abstract]

Schedule of accounts payable and accrued liabilities

(in thousands)	March 31, 2019		December 31, 2018
Accounts payable	$	6,064	$	7,670
Oil and gas revenue suspense		2,766		2,675
Gathering and transportation payables		1,228		1,774
Production taxes payable		2,411		1,860
Accrued operating costs		2,431		3,155
Accrued ad valorem taxes – current		3,731		3,474
Accrued general and administrative expenses		2,217		3,111
Accrued asset retirement obligation – current		3,392		3,099
Accrued interest		1,543		955
Accrued gas purchases		2,959		5,440
Other liabilities		1,278		1,603
Total accounts payable and accrued liabilities	$	30,020	$	34,816

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2019

Fair Value Disclosures [Abstract]

Schedule of financial assets and liabilities at fair value

(in thousands)	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Total
March 31, 2019
Assets:
Commodity derivatives	$	-	$	147	$	-	$	147
Liabilities:
Commodity derivatives	$	-	$	1,975	$	-	$	1,975
December 31, 2018
Asset:
Commodity derivatives	$	-	$	7,022	$	-	$	7,022

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Commodity Derivatives (Tables)

3 Months Ended

Mar. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of swap derivative agreements

	Natural Gas Swaps				Natural Gas Collars
			Weighted Average				Weighted Average Price
Year	MMBtu		Price (a)		MMBtu		Range (a)
2019		11,762,000,	$	2.82		374,000	$	2.60 – $3.03
2020		12,433,000	$	2.73		1,018,000	$	2.50 – $2.70
2021		6,448,000	$	2.58		-	$	-

	Oil Swaps								Oil Collars
Year	WTI Bbl		Weighted Average  Price (b)		Brent Bbl		Weighted Average Price (c)		WTI Bbl		Weighted  Average Price (b)		Brent Bbl		Weighted  Average Price (c)
2019		180,775	$	53.46		121,079	$	66.93		-		-		29,800	$	47.00 - $75.00
2020		121,147	$	55.37		151,982	$	66.03		18,000	$	47.00 - $60.15		37,400	$	47.00 - $75.00
2021		-	$	-		86,341	$	67.12		30,000	$	47.00 - $60.15		98,000	$	47.00 - $75.00

*	Includes 100% of Carbon California’s outstanding derivative hedges at March 31, 2019, and not our proportionate share.
(a)	NYMEX Henry Hub Natural Gas futures contract for the respective period.
(b)	NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective period.
(c)	Brent future contracts for the respective period.

Schedule of fair value of the derivatives recorded

(in thousands)	March 31, 2019		December 31, 2018
Commodity derivative contracts:
Commodity derivative asset	$	-	$	3,517
Commodity derivative asset – non-current	$	147	$	3,505
Commodity derivative liability	$	1,657	$	-
Commodity derivative liability – non-current	$	318	$	-

Schedule of realized and unrealized gains and losses

	Three Months Ended March 31,
(in thousands)	2019			2018
Commodity derivative contracts:
Settlement losses	$	(456	)	$	(377	)
Unrealized losses		(8,850	)		(249	)
Total settlement and unrealized losses, net	$	(9,306	)	$	(626	)

Schedule of fair value amounts of all derivative instruments assets and liabilities

						Net
	Gross					Recognized
	Recognized		Gross			Fair Value
	Assets/		Amounts			Assets/
Balance Sheet Classification (in thousands)	Liabilities		Offset			Liabilities
Commodity derivative assets:
Commodity derivative asset	$	1,063	$	(1,063	)	$	-
Commodity derivative asset – non-current		2,049		(1,902	)		147
Total derivative assets	$	3,112	$	(2,965	)	$	147
Commodity derivative liabilities:
Commodity derivative liability	$	2,720	$	(1,063	)	$	(1,657	)
Commodity derivative liability – non-current		2,220		(1,902	)		(318	)
Total derivative liabilities	$	4,940	$	(2,965	)	$	(1,975	)

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Leases (Tables)

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Schedule of operating leases related to the asset classes

(in thousands)	Right-of-Use Assets		Lease Liability
Compressors	$	4,178	$	4,178
Corporate leases		2,433		2,438
Vehicles		645		645
Total	$	7,256	$	7,261

Schedule of gross operating lease costs

(in thousands)	Three Months Ended March 31, 2019
Operating lease cost	$	531
Short-term lease cost		161
Total lease cost	$	692

Schedule of weighted-average lease term and discount rate

(in thousands)	Three Months Ended March 31, 2019
Weighted-average lease term (years)		4.3
Weighted-average discount rate		6.34	%

Schedule of supplemental cash flow information related to leases

Cash paid for amounts included in measurement of lease liabilities (in thousands)	Three Months Ended March 31, 2019
Operating cash flows for operating leases	$	526

Schedule of undiscounted values and discounted present value

(in thousands)	Amount
Remainder of 2019	$	1,535
2020		1,946
2021		1,889
2022		1,718
2023		1,222
Thereafter		11
Total lease payments	$	8,321
Less: imputed interest		(1,060	)
Total lease liability	$	7,261

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Commitments and Contingencies (Tables)

3 Months Ended

Mar. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Schedule of firm transportation volumes and related demand charges

Period	Dekatherms per day		Demand Charges
Apr 2019 – Mar 2020		58,871	$	0.20 - 0.62
Apr 2020 – May 2020		57,791	$	0.20 - 0.56
Jun 2020 – Oct 2020		56,641	$	0.20 - 0.56
Nov 2020 – Aug 2022		50,341	$	0.20 - 0.56
Sep 2022 – May 2027		30,990	$	0.20 - 0.21
Jun 2027 – May 2036		1,000	$	0.20

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Supplemental Cash Flow Disclosure (Tables)

3 Months Ended

Mar. 31, 2019

Supplemental Cash Flow Elements [Abstract]

Schedule of supplemental cash flow disclosures

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

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Organization (Details) - USD ($) $ in Thousands		12 Months Ended
	May 01, 2018	Dec. 31, 2018	Feb. 01, 2018
Delaware Limited Liability Company [Member]
Organization (Textual)
Business acquisation purchase price		$ 58,100
Carbon California [Member]
Organization (Textual)
Divestitures, description	The voting and profits interests and Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America or its affiliates ("Prudential") owns 46.08% of the voting and profits interest in Carbon California.
Carbon California [Member] | Minimum [Member]
Organization (Textual)
Voting percentage			17.81%
Carbon California [Member] | Maximum [Member]
Organization (Textual)
Voting percentage			56.40%

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

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Summary of Significant Accounting Policies (Details Textual) - USD ($)	1 Months Ended	2 Months Ended	3 Months Ended		12 Months Ended
	Jan. 31, 2018	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Summary of Significant Accounting Policies (Textual)
Description of cost method investments, additional information			The cost method of accounting is generally used for investments in affiliates in which we have less than 20% of the voting interests of a corporate affiliate (or less than a 3% to 5% interest of a partnership or limited liability company) and do not have significant influence.
Description of equity method investment, additional information			If we hold between 20% and 50% of the voting interest in non-consolidated corporate affiliates or generally greater than a 3% to 5% interest of a partnership or limited liability company and can exert significant influence or control (e.g., through our influence with a seat on the board of directors or management of operations), the equity method of accounting is generally used to account for the investment.
Management reimbursement elimination amount		$ 100,000
Carbon Appalachia [Member]
Summary of Significant Accounting Policies (Textual)
Percentage of ownership interest in the subsidiary			100.00%
Management provision reimbursements				$ 299,000
Received related party amount				$ 753,000
Carbon California [Member]
Summary of Significant Accounting Policies (Textual)
Management reimbursement elimination amount		$ 28,000
General and administrative expenses reimbursed amount	$ 14,000
Received related party amount	$ 50,000
Restricted Stock [Member]
Summary of Significant Accounting Policies (Textual)
Anti-dilutive earnings per shares				254,000
Non-vested shares		230,000		230,000
Restricted Performance Units [Member]
Summary of Significant Accounting Policies (Textual)
Common stock equivalent restricted to future contingencies			200,000
Anti-dilutive earnings per shares			269,000
Nytis Usa [Member]
Summary of Significant Accounting Policies (Textual)
Percentage of ownership interest in the subsidiary					100.00%
Nytis Llc [Member]
Summary of Significant Accounting Policies (Textual)
Percentage of ownership interest in the subsidiary					98.10%

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

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

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

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Acquisitions and Divestitures (Details Textual) - USD ($) $ in Thousands					1 Months Ended	3 Months Ended	24 Months Ended
	Feb. 01, 2019	Feb. 01, 2018	Nov. 01, 2017	Apr. 03, 2017	Sep. 29, 2017	Mar. 31, 2019	Dec. 31, 2018	Aug. 15, 2017
Acquisitions and Divestitures (Textual)
Consisting cash paid amount						$ 25,100
Borrowing Revolver Increased								$ 8,000
Old Ironsides [Member]
Acquisitions and Divestitures (Textual)
Principal amount	$ 2,000
Bearing interest of per annum						10.00%
Percentage of identifiable assets acquired and liabilities						72.76%
OIE Membership Acquisition [Member]
Acquisitions and Divestitures (Textual)
Principal amount						$ 25,100
Yorktown Energy Partners [Member] | Class Units [Member]
Acquisitions and Divestitures (Textual)
Warrant to purchase common stock			2,940
Carbon Appalachia [Member]
Acquisitions and Divestitures (Textual)
Recognized gain based on fair value						1,300
Purchase price						5,810
Consisting cash paid amount						$ 33,000
Description of seneca acquisition				i) issued Class A Units to us, Yorktown and Old Ironsides for an aggregate cash consideration of $12.0 million, (ii) issued Class B Units to us, and (iii) issued Class C Units to us. Additionally, Carbon Appalachia Enterprises, LLC, formerly known as Carbon Tennessee Company, LLC ("Carbon Appalachia Enterprises"), a subsidiary of the Company, entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank (the "Revolver") with an initial borrowing base of $10.0 million.
Equity commitment				$ 100,000			$ 37,000
Aggregate cash consideration								14,000
Borrowing Revolver Increased								$ 22,000
Carbon Appalachia [Member] | Class Units [Member]
Acquisitions and Divestitures (Textual)
Acquisitions issuance shares, description					Prior to the closing of the OIE Membership Acquisition, Old Ironsides held 27,195 Class A Units, which equated to a 72.76% aggregate share ownership of Carbon Appalachia and we held (i) 9,805 Class A Units, (ii) 1,000 Class B Units and (iii) 121 Class C Units, which equated to a 27.24% aggregate share ownership of Carbon Appalachia.
Aggregate cash consideration					$ 11,000
Acquired of Class A Units							5,810
Acquired cash paid							$ 33,000
Carbon Appalachia [Member] | Class B Units [Member]
Acquisitions and Divestitures (Textual)
Warrant to purchase common stock				1,000
Carbon Appalachia [Member] | Yorktown Energy Partners [Member]
Acquisitions and Divestitures (Textual)
Warrant to purchase common stock				408,000
Carbon California [Member]
Acquisitions and Divestitures (Textual)
Acquisitions issuance shares, description		Yorktown exercised the California Warrant resulting in the issuance of 1,527,778 shares of our common stock in exchange for Yorktown's Class A Units of Carbon California representing approximately 46.96% of the outstanding Class A Units of Carbon California (a profits interest of approximately 38.59%). After giving effect to the exercise on February 1, 2018, we owned 56.4% of the voting and profits interests of Carbon California.

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

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

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

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

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

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

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

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Stockholders' Equity (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended		12 Months Ended
	Mar. 15, 2017	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jun. 01, 2018
Stockholders' Equity (Textual)
Compensation costs for restricted stock grants				$ 2,700	$ 2,700
Granted, Number of Shares		649,000
Exercise price		$ 100
Grant date fair value				$ 9.80	$ 7.20	$ 5.40	$ 8.00
Number of shares issued				50,000
Proceeds from issuance of preferred stock		$ 5,000
Conversion of common stock, description		The number of shares of common stock issuable upon conversion is dependent upon the price per share of common stock issued in connection with any such qualifying equity financing but has a floor conversion price equal to $8.00 per share. The conversion ratio at which the Preferred Stock will convert into common stock is equal to an amount per share of $100 plus all accrued but unpaid dividends payable in respect thereof divided by the greater of (i) $8.00 per share or (ii) the price that is 15% less than the lowest price per share of shares sold to the public in the next equity financing. Using the floor of $8.00 per share would yield 12.5 shares of common stock for every unit of Preferred Stock.
Beneficial conversion feature
Accrued dividends		299
Beneficial conversion feature, description		We recorded the BCF as a reduction of retained earnings and an increase to APIC of $1.1 million, which is based on the difference between the floor price of $8.00 and our stock price as of the commitment date multiplied by the number of shares to be issued.
Common stock, shares authorized		35,000,000		35,000,000
Common stock, par value		$ 0.01		$ 0.01
Common stock, shares issued		7,791,292		7,655,759
Common stock, shares outstanding		7,791,292		7,655,759
Preferred stock, shares authorized		1,000,000		1,000,000
Preferred stock, par value		$ 0.01		$ 0.01
Minimum [Member]
Stockholders' Equity (Textual)
Common stock, shares authorized								10,000,000
Maximum [Member]
Stockholders' Equity (Textual)
Common stock, shares authorized								35,000,000
Issued Capital Stock [Member]
Stockholders' Equity (Textual)
Common stock, shares authorized				35,000,000
Common stock, par value				$ 0.01
Common stock, shares issued				7,800,000
Common stock, shares outstanding				7,800,000
Preferred stock, shares authorized				1,000,000
Preferred stock, par value				$ 0.01
Restricted Performance Units [Member]
Stockholders' Equity (Textual)
Unrecognized compensation cost			$ 158
Compensation cost recognized		43	135
Restricted stock vested shares		40,000
Restricted Stock Units (Rsus) [Member]
Stockholders' Equity (Textual)
Unrecognized compensation cost		$ 1,200
Compensation costs for restricted stock grants		$ 179
Expected period of recognition of unrecognized compensation costs		6 years
Granted, Number of Shares		621,000
Accrued dividends		100
Series B Convertible Preferred Stock [Member]
Stockholders' Equity (Textual)
Accrue cash dividends rate		6.00%
Stockholders And Board Of Directors [Member]
Stockholders' Equity (Textual)
Reverse stock split, description	A reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. References to the number of shares and price per share give retroactive effect to the reverse stock split for all periods presented.

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

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

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

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

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

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Commodity Derivatives (Details)	Mar. 31, 2019 USD_Bbl USD-MMBtu $ / shares
Natural Gas Swaps [Member] | Carbon Energy Corporation [Member] | 2019 [Member]
Derivative agreements details:
Quantity | USD-MMBtu	11,762,000
Weighted Average Price	$ 2.82	[1]
Natural Gas Swaps [Member] | Carbon Energy Corporation [Member] | 2020 [Member]
Derivative agreements details:
Quantity | USD_Bbl	12,433,000
Weighted Average Price	$ 2.73	[1]
Natural Gas Swaps [Member] | Carbon Energy Corporation [Member] | 2021 [Member]
Derivative agreements details:
Quantity | USD_Bbl	6,448,000
Weighted Average Price	$ 2.58	[1]
Natural Gas Collars [Member] | Carbon Energy Corporation [Member] | 2019 [Member]
Derivative agreements details:
Quantity | USD-MMBtu	374,000
Natural Gas Collars [Member] | Carbon Energy Corporation [Member] | 2020 [Member]
Derivative agreements details:
Quantity | USD_Bbl	1,018,000
Natural Gas Collars [Member] | Carbon Energy Corporation [Member] | 2021 [Member]
Derivative agreements details:
Quantity | USD_Bbl
Weighted Average Price		[1]
Oil Swaps [Member] | Carbon Energy Corporation [Member] | 2019 [Member]
Derivative agreements details:
Quantity | USD_Bbl	180,775
Weighted Average Price	$ 53.46	[2]
Oil Swaps [Member] | Carbon Energy Corporation [Member] | 2020 [Member]
Derivative agreements details:
Quantity | USD_Bbl	121,147
Weighted Average Price	$ 55.37	[2]
Oil Swaps [Member] | Carbon Energy Corporation [Member] | 2021 [Member]
Derivative agreements details:
Quantity | USD_Bbl
Weighted Average Price		[2]
Oil Swaps [Member] | Brent Bbl [Member] | Carbon California [Member] | 2019 [Member]
Derivative agreements details:
Quantity | USD_Bbl	121,079
Weighted Average Price	$ 66.93	[3]
Oil Swaps [Member] | Brent Bbl [Member] | Carbon California [Member] | 2020 [Member]
Derivative agreements details:
Quantity | USD_Bbl	151,982
Weighted Average Price	$ 66.03	[3]
Oil Swaps [Member] | Brent Bbl [Member] | Carbon California [Member] | 2021 [Member]
Derivative agreements details:
Quantity | USD_Bbl	86,341
Weighted Average Price	$ 67.12	[3]
Oil Collars [Member] | Carbon Energy Corporation [Member] | 2020 [Member]
Derivative agreements details:
Quantity | USD_Bbl	18,000
Oil Collars [Member] | Carbon Energy Corporation [Member] | 2021 [Member]
Derivative agreements details:
Quantity | USD_Bbl	30,000
Oil Collars [Member] | Carbon California [Member] | 2019 [Member]
Derivative agreements details:
Quantity | USD_Bbl
Weighted Average Price
Oil Collars [Member] | Brent Bbl [Member] | Carbon California [Member] | 2019 [Member]
Derivative agreements details:
Quantity | USD_Bbl	29,800
Oil Collars [Member] | Brent Bbl [Member] | Carbon California [Member] | 2020 [Member]
Derivative agreements details:
Quantity | USD_Bbl	37,400
Oil Collars [Member] | Brent Bbl [Member] | Carbon California [Member] | 2021 [Member]
Derivative agreements details:
Quantity | USD_Bbl	98,000
Minimum [Member] | Natural Gas Collars [Member] | Carbon Energy Corporation [Member] | 2020 [Member]
Derivative agreements details:
Weighted Average Price	$ 2.50	[1]
Minimum [Member] | Natural Gas Collars [Member] | Carbon California [Member] | 2019 [Member]
Derivative agreements details:
Weighted Average Price	2.60	[1]
Minimum [Member] | Oil Collars [Member] | Carbon Energy Corporation [Member] | 2020 [Member]
Derivative agreements details:
Weighted Average Price	47.00	[2]
Minimum [Member] | Oil Collars [Member] | Carbon Energy Corporation [Member] | 2021 [Member]
Derivative agreements details:
Weighted Average Price	47.00	[2]
Minimum [Member] | Oil Collars [Member] | Brent Bbl [Member] | Carbon California [Member] | 2019 [Member]
Derivative agreements details:
Weighted Average Price	47.00	[3]
Minimum [Member] | Oil Collars [Member] | Brent Bbl [Member] | Carbon California [Member] | 2020 [Member]
Derivative agreements details:
Weighted Average Price	47.00	[3]
Minimum [Member] | Oil Collars [Member] | Brent Bbl [Member] | Carbon California [Member] | 2021 [Member]
Derivative agreements details:
Weighted Average Price	47.00	[3]
Maximum [Member] | Natural Gas Collars [Member] | Carbon Energy Corporation [Member] | 2019 [Member]
Derivative agreements details:
Weighted Average Price	3.03	[1]
Maximum [Member] | Natural Gas Collars [Member] | Carbon Energy Corporation [Member] | 2020 [Member]
Derivative agreements details:
Weighted Average Price	2.70	[1]
Maximum [Member] | Oil Collars [Member] | Carbon Energy Corporation [Member] | 2020 [Member]
Derivative agreements details:
Weighted Average Price	60.15	[2]
Maximum [Member] | Oil Collars [Member] | Carbon Energy Corporation [Member] | 2021 [Member]
Derivative agreements details:
Weighted Average Price	60.15	[2]
Maximum [Member] | Oil Collars [Member] | Brent Bbl [Member] | Carbon California [Member] | 2019 [Member]
Derivative agreements details:
Weighted Average Price	75.00	[3]
Maximum [Member] | Oil Collars [Member] | Brent Bbl [Member] | Carbon California [Member] | 2020 [Member]
Derivative agreements details:
Weighted Average Price	75.00	[3]
Maximum [Member] | Oil Collars [Member] | Brent Bbl [Member] | Carbon California [Member] | 2021 [Member]
Derivative agreements details:
Weighted Average Price	$ 75.00	[3]

[1] NYMEX Henry Hub Natural Gas futures contract for the respective period.

[2] NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective period.

[3] Brent future contracts for the respective period.

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

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

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

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

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

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

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

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

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

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Commitments and Contingencies (Details)	3 Months Ended
	Mar. 31, 2019 $ / shares Partnership
Apr 2019 - Mar 2020 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Partnership	58,871
Apr 2019 - Mar 2020 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.20
Apr 2019 - Mar 2020 [Member] | Maximum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.62
Apr 2020 - May 2020 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Partnership	57,791
Apr 2020 - May 2020 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.20
Apr 2020 - May 2020 [Member] | Maximum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.56
Jun 2020 - Oct 2020 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Partnership	56,641
Jun 2020 - Oct 2020 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.20
Jun 2020 - Oct 2020 [Member] | Maximum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.56
Nov 2020 - Aug 2022 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Partnership	50,341
Nov 2020 - Aug 2022 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.20
Nov 2020 - Aug 2022 [Member] | Maximum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.56
Sep 2022 - May 2027 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Partnership	30,990
Sep 2022 - May 2027 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.20
Sep 2022 - May 2027 [Member] | Maximum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.21
Jun 2027 - May 2036 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Partnership	1,000
Demand Charges (in dollars per dekatherm)	0.20

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

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