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 June 30, 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)

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 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 ☒

At August 9, 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. Financial Statements	1
Condensed Consolidated Balance Sheets (unaudited)	1
Condensed Consolidated Statements of Operations (unaudited)	2
Condensed Consolidated Statements of Stockholders’ Equity (unaudited)	3
Condensed Consolidated Statements of Cash Flows (unaudited)	4
Notes to Condensed Consolidated Financial Statements (unaudited)	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3. Quantitative and Qualitative Disclosures About Market Risk	34
Item 4. Controls and Procedures	34
Part II – OTHER INFORMATION
Item 1. Legal Proceedings	35
Item 1A. Risk Factors	35
Item 6. Exhibits	35
Signatures	36

i

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

CARBON ENERGY CORPORATION

Condensed Consolidated Balance Sheets

	June 30,			December 31,
(in thousands, except share amounts)	2019			2018
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	4,651		$	5,736
Accounts receivable:
Revenue		12,936			19,671
Joint interest billings and other		1,502			1,770
Insurance receivable (Note 2)		-			522
Commodity derivative asset (Note 14)		5,146			3,517
Prepaid expense, deposits and other current assets		1,930			1,645
Inventory		1,371			1,149
Total current assets		27,536			34,010
Non-current assets:
Property and equipment (Note 4)
Oil and gas properties, full cost method of accounting:
Proved, net		244,381			248,455
Unproved		5,471			5,416
Other property and equipment, net		16,766			17,563
Total property and equipment, net		266,618			271,434
Investments in affiliates		588			598
Commodity derivative asset – non-current (Note 14)		1,582			3,505
Right-of-use assets (Note 8)		6,946			-
Other non-current assets		1,277			1,344
Total non-current assets		277,011			276,881
Total assets	$	304,547		$	310,891
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities (Note 5)	$	30,497		$	34,816
Firm transportation contract obligations (Note 15)		5,952			6,129
Lease liability – current (Note 8)		1,621			-
Commodity derivative liability (Note 14)		102			-
Credit facilities and notes payable – current (Note 7)		9,910			11,910
Total current liabilities		48,082			52,855
Non-current liabilities:
Firm transportation contract obligations (Note 15)		10,729			12,729
Lease liability – non-current (Note 8)		5,202			-
Production and property taxes payable		2,799			2,914
Asset retirement obligations (Note 6)		19,401			19,211
Credit facilities and notes payable (Note 7)		96,284			97,228
Notes payable – related party (Note 7)		45,089			49,919
Total non-current liabilities		179,504			182,001
Commitments and contingencies (Note 15)
Stockholders’ equity:
Preferred stock, $0.01 par value; liquidation preference of $374,000 at June 30, 2019 and $224,000 at December 31, 2018; authorized 1,000,000 shares, 50,000 shares issued and outstanding at June 30, 2019 and December 31, 2018		1			1
Common stock, $0.01 par value; authorized 35,000,000 shares, 7,816,030 and 7,655,759 shares issued and outstanding at June 30, 2019 and December 31, 2018, respectively		79			77
Additional paid-in capital		85,057			84,612
Accumulated deficit		(34,810	)		(36,939	)
Total Carbon stockholders’ equity		50,327			47,751
Non-controlling interests		26,634			28,284
Total stockholders’ equity		76,961			76,035
Total liabilities and stockholders’ equity	$	304,547		$	310,891

See accompanying notes to Condensed Consolidated Financial Statements.

1

CARBON ENERGY CORPORATION

Condensed Consolidated Statements of Operations

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands, except per share amounts)	2019			2018			2019			2018
Revenue:
Natural gas sales	$	14,216		$	3,523		$	33,532		$	7,462
Natural gas liquids		195			550			441			713
Oil sales		9,902			8,091			18,891			11,074
Transportation and handling		322			-			1,056			-
Marketing gas sales		3,221			-			8,165			-
Commodity derivative gain (loss)		8,680			(6,022	)		(627	)		(6,647	)
Other income		305			6			697			19
Total revenue		36,841			6,148			62,155			12,621
Expenses:
Lease operating expenses		7,480			3,970			14,095			6,058
Pipeline operating expenses		2,950			-			6,035			-
Transportation and gathering costs		1,130			1,498			2,799			2,353
Production and property taxes		1,666			615			3,676			1,048
Marketing gas purchases		4,795			-			11,097			-
General and administrative		3,947			2,542			8,636			5,491
General and administrative – related party reimbursement		-			(1,096	)		-			(2,213	)
Depreciation, depletion and amortization		3,881			1,979			7,860			3,471
Accretion of asset retirement obligations		405			162			799			303
Total expenses		26,254			9,670			54,997			16,511
Operating income (loss)		10,587			(3,522	)		7,158			(3,890	)
Other income (expense):
Interest expense, net		(3,445	)		(1,201	)		(6,725	)		(2,203	)
Warrant derivative gain		-			-			-			225
Gain on derecognized equity investment in affiliate – Carbon California		-			-			-			5,390
Investment in affiliates		21			525			40			962
Total other (expense) income		(3,424	)		(676	)		(6,685	)		4,374
Income (loss) before income taxes		7,163			(4,198	)		473			484
Provision for income taxes		-			-			-			-
Net income (loss) before non-controlling interests and preferred shares		7,163			(4,198	)		473			484
Net income (loss) attributable to non-controlling interests		934			(3,619	)		(1,656	)		(2,505	)
Net income (loss) attributable to controlling interests before preferred shares		6,229			(579	)		2,129			2,989
Net income attributable to preferred shares – preferred return		75			-			150			-
Net income (loss) attributable to common shares	$	6,154		$	(579	)	$	1,979		$	2,989
Net income (loss) per common share:
Basic	$	0.79		$	(0.08	)	$	0.26		$	0.41
Diluted	$	0.75		$	(0.23	)	$	0.24		$	0.20
Weighted average common shares outstanding:
Basic		7,815			7,693			7,739			7,346
Diluted		8,157			7,693			8,081			7,662

See accompanying notes to Condensed Consolidated Financial Statements.

2

CARBON ENERGY CORPORATION

Condensed Consolidated Statements of Stockholders’ Equity

(Unaudited)

(in thousands)

									Additional			Non-						Total
	Common Stock				Preferred Stock				Paid-in			Controlling			Accumulated			Stockholders’
	Shares		Amount		Shares		Amount		Capital			Interests			Deficit			Equity
Balance as of 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
Balance as of March 31, 2018		7,572	$	76		-	$	-	$	69,208		$	19,398		$	(40,649	)	$	48,033
Stock-based compensation		-		-		-		-		192			-			-			192
Restricted stock vested		21		-		-		-		-			-			-			-
Performance units vested		108		1		-		-		(1	)		-			-			-
Preferred share issuance (Note 11)		-		-		50		1		4,999			-			-			5,000
Beneficial conversion feature		-		-		-		-		1,125			-			(1,125	)		-
Deemed dividend		-		-		-		-		71			-			(71	)		-
Non-controlling interest contributions, net		-		-		-		-		-			5,498			-			5,498
Net loss		-		-		-		-		-			(3,619	)		(579	)		(4,198	)
Balance as of June 30, 2018		7,701	$	77		50	$	1	$	75,594		$	21,277		$	(42,424	)	$	54,525

									Additional			Non-						Total
	Common Stock				Preferred Stock				Paid-in			Controlling			Accumulated			Stockholders’
	Shares		Amount		Shares		Amount		Capital			Interests			Deficit			Equity
Balance as of 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	)
Balance as of March 31, 2019		7,791	$	79		50	$	1	$	84,833		$	25,716		$	(41,039	)	$	69,590
Stock-based compensation		-		-		-		-		224			-			-			224
Restricted stock vested		25		-		-		-		-			-			-			-
Non-controlling interests’ distributions, net		-		-		-		-		-			(16	)		-			(16	)
Net income		-		-		-		-		-			934			6,229			7,163
Balance as of June 30, 2019		7,816	$	79		50	$	1	$	85,057		$	26,634		$	(34,810	)	$	76,961

See accompanying notes to Condensed Consolidated Financial Statements.

3

CARBON ENERGY CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Six Months Ended
	June 30,
(in thousands)	2019			2018
Cash flows from operating activities:
Net income	$	473		$	484
Items not involving cash:
Depreciation, depletion and amortization		7,860			3,471
Accretion of asset retirement obligations		799			303
Unrealized commodity derivative loss		396			5,587
Warrant derivative gain		-			(225	)
Stock-based compensation expense		446			483
Investment in affiliates		(40	)		(962	)
Gain on derecognized equity investment in affiliate – Carbon California		-			(5,390	)
Amortization of debt costs		405			247
Interest expense paid-in-kind		1,244			-
Net change in:
Accounts receivable		7,525			(353	)
Prepaid expenses, deposits and other current assets		(375	)		570
Accounts payable, accrued liabilities and firm transportation contract obligations		(8,611	)		(1,416	)
Other non-current items		(327	)		(1,184	)
Net cash provided by operating activities		9,795			1,615
Cash flows from investing activities:
Development and acquisition of properties and equipment		(1,863	)		(40,472	)
Proceeds received – Carbon California Acquisition		-			275
Distribution from affiliate		50			-
Proceeds received – disposition of oil and gas properties		176			-
Net cash used in investing activities		(1,637	)		(40,197	)
Cash flows from financing activities:
Proceeds from credit facility and notes payable		4,029			31,502
Proceeds from preferred shares		-			5,000
Payments on credit facility and notes payable		(13,185	)		(14	)
Debt issuance costs		(93	)		(511	)
Contributions to non-controlling interests, net		6			4,985
Net cash (used in) provided by financing activities		(9,243	)		40,962
Net (decrease) increase in cash and cash equivalents		(1,085	)		2,380
Cash and cash equivalents, beginning of period		5,736			1,650
Cash and cash equivalents, end of period	$	4,651		$	4,030

See accompanying notes to Condensed Consolidated Financial Statements.

4

CARBON ENERGY CORPORATION

Notes to Condensed Consolidated Financial Statements

(Unaudited)

NOTE 1 – ORGANIZATION

Carbon Energy Corporation (formerly known as Carbon Natural Gas Company) is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil, natural gas and natural gas liquids properties located in the United States. The terms “we”, “us”, “our”, the “Company” or “Carbon” refer to Carbon Energy Corporation and our consolidated subsidiaries (described below). The following is an organization chart of the key subsidiaries as of June 30, 2019 discussed in this report:

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 June 30, 2019:

5

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 conducts operations on behalf of Carbon California Company, LLC (“Carbon California”). On February 1, 2018, Yorktown Energy Partners XI, L.P. (“Yorktown”) exercised the California Warrant, collectively resulting in our aggregate sharing percentage in Carbon California increasing from 17.81% to 56.40%. On May 1, 2018, Carbon California closed the acquisition with Seneca Resources Corporation (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 June 30, 2019:

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and in accordance with U.S. generally accepted accounting principles (“GAAP”) applicable to interim financial statements. These unaudited condensed consolidated financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary for a fair presentation of the results of the interim period. Operating results for the interim periods presented require management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes and are not necessarily indicative of the results that may be expected for the full year. The condensed consolidated balance sheet data as of December 31, 2018 was derived from audited financial statements but does not include all disclosures required by GAAP. These unaudited condensed consolidated financial statements 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. The Company follows the same accounting policies for preparing quarterly and annual reports.

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 98.11% of Nytis LLC. Nytis LLC holds interests in various oil and gas partnerships.

6

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 condensed 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 condensed 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 stockholders’ 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 final settlement payment from our insurance provider related to the damage caused by the California wildfires. As of June 30, 2019, we were in receipt of all funds associated with the claims.

Revenue

Upon completion of the OIE Membership Acquisition, our revenue recognition policy was amended to account for the additional revenue we receive for transportation and handling and marketing gas sales, as described below.

Transportation and handling

We generally purchase natural gas from producers at the wellhead or other receipt points, gather the wellhead natural gas through our gathering systems, and then sell the natural gas based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of natural gas or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, regardless of the actual amount of the sales proceeds we receive. Our revenues under percent-of-proceeds/index arrangements generally correlate to the price of natural gas. Under fee-based arrangements, we receive a fee for storing natural gas. The storage revenues earned are directly related to the volume of natural gas that flows through our systems and are not directly dependent on commodity prices.

Marketing Gas Sales

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

Recently Adopted Accounting Pronouncement

On January 1, 2019, we adopted Accounting Standards Update No. 2016-02, Leases (“Topic 842”) (ASU 2016-02), as amended, which supersedes the lease accounting guidance under Topic 840, and generally requires lessees to recognize operating and financing lease liabilities and corresponding right-of-use assets on the balance sheet and to provide enhanced disclosures surrounding the amount, timing and uncertainty of cash flows arising from leasing arrangements. We adopted the new guidance using the modified retrospective transition approach by applying the new standard to all leases existing at the date of initial application and not restating comparative periods. The most significant impact was the recognition of right-of-use assets and lease liabilities for operating leases. See Note 8 for further information on our implementation of this standard. 

Recently Issued Accounting Pronouncements

In August 2018, the Financial Accounting Standard Board issued ASU 2018-13 - Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement. The objective of this update is to improve the effectiveness of fair value measurement disclosures. This update is effective for annual periods beginning after December 15, 2019, and interim periods within those annual periods. The standard will only impact the Company’s disclosures.

7

NOTE 3 – ACQUISITIONS

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 into 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 Appalachia, 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 would 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 10.0% 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 was accounted for as a business combination in accordance with ASC 805, Business Combinations. 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 $25.0 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		25,030
Fair value of previously held equity interest		14,158
Fair value of business acquired	$	72,188

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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		108,816
Unproved		1,869
Other property, plant and equipment, net		15,626
Other non-current assets		514
Accounts payable and accrued liabilities		(20,466	)
Due to related parties		(458	)
Firm transportation contract obligations		(18,724	)
Asset retirement obligations		(5,626	)
Notes payable		(37,975	)
Total net assets acquired	$	72,188

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 cost 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 and six months ended June 30, 2018 as though the OIE Membership Acquisition had been completed as of January 1, 2018. Results for the three and six months ended June 30, 2019 are reflected in the unaudited condensed consolidated statements of operations.

	Three Months Ended June 30,			Six Months Ended June 30,
(in thousands, except per share amounts)	2018			2018
Revenue	$	23,682		$	54,841
Net (loss) income before non-controlling interests	$	(2,758	)	$	3,046
Net loss attributable to non-controlling interests	$	(3,619	)	$	(2,505	)
Net income attributable to controlling interests before preferred shares	$	861		$	5,551
Net income per share, basic	$	0.11		$	0.76
Net income per share, diluted	$	(0.04	)	$	0.54

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 56.40% of the voting and profits interests of Carbon California.

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Below are unaudited pro forma consolidated results of operations for the three and six months ended June 30, 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 condensed consolidated statements of operations for the six months ended June 30, 2018, includes the results of operations for the period February 1, 2018, through June 30, 2018. Results for the three and six months ended June 30, 2019 are reflected in the unaudited condensed consolidated statements of operations.

	Three Months Ended June 30,			Six Months Ended June 30,
(in thousands, except per share amounts)	2018			2018
Revenue	$	8,180		$	20,283
Net (loss) income before non-controlling interests	$	(3,013	)	$	4,256
Net loss attributable to non-controlling interests	$	(3,619	)	$	(2,504	)
Net income attributable to controlling interests before preferred shares	$	607		$	7,739
Net income per share, basic	$	0.27		$	1.01
Net income per share, diluted	$	0.09		$	0.84

NOTE 4 – PROPERTY AND EQUIPMENT

Property and equipment, net consists of the following:

(in thousands)	June 30, 2019			December 31, 2018
Oil and gas properties:
Proved oil and gas properties	$	346,654		$	343,736
Unproved properties not subject to depletion		5,471			5,416
Accumulated depreciation, depletion, amortization and impairment		(102,273	)		(95,281	)
Net oil and gas properties		249,852			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		6,721			6,649
Accumulated depreciation and amortization		(4,791	)		(3,922	)
Net other property and equipment		16,766			17,563
Property and equipment, net	$	266,618		$	271,434

As of June 30, 2019, and December 31, 2018, the Company had approximately $5.5 million and $5.4 million, respectively, of unproved oil and gas properties not subject to depletion. Such costs are excluded from the full cost pool until it is determined if reserves can be assigned to the related properties. Subject to industry conditions, evaluation of most of these properties and the inclusion of their costs in the full cost pool is expected to be completed within five years. Unproved properties are assessed for impairment at least annually. During the three and six months ended June 30, 2019, approximately $206,000 of expiring leasehold costs were reclassified into proved property. There were no expiring leasehold costs during the three and six months ended June 30, 2018.

We capitalized overhead applicable to acquisition, development and exploration activities of approximately $305,000 and $373,000 for the three and six months ended June 30, 2019, respectively. For the three and six months ended June 30, 2018, we capitalized overhead applicable to acquisition, development, and exploration activities of approximately $119,000 and $190,000, respectively.

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Depletion expense related to oil and gas properties for the three and six months ended June 30, 2019 was approximately $3.5 million and $7.0 million, respectively. Depletion expense related to oil and gas properties for the three and six months ended June 30, 2018 was approximately $1.8 million and $3.1 million, respectively.

For the three and six months ended June 30, 2019 and 2018, we did not recognize any ceiling test impairments as our full cost pool did not exceed the ceiling limitations.

NOTE 5 – ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Accounts payable and accrued liabilities at June 30, 2019 and December 31, 2018 consist of the following:

(in thousands)	June 30, 2019		December 31, 2018
Accounts payable	$	4,982	$	7,670
Oil and gas revenue suspense		3,123		2,675
Gathering and transportation payables		1,788		1,774
Production taxes payable		2,520		1,860
Accrued operating costs		875		3,155
Accrued ad valorem taxes – current		6,104		3,474
Accrued general and administrative expenses		1,750		3,111
Accrued asset retirement obligation – current		3,708		3,099
Accrued interest		1,513		955
Accrued gas purchases		2,912		5,440
Other liabilities		1,222		1,603
Total accounts payable and accrued liabilities	$	30,497	$	34,816

NOTE 6 – ASSET RETIREMENT OBLIGATION

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:

(in thousands)	Six Months Ended June 30,
	2019			2018
Balance at beginning of period	$	22,310		$	7,737
Accretion expense		799			303
Additions during period		-			3,560
Balance at end of period	$	23,109		$	11,600
Less:  Current portion		(3,708	)		(769	)
Non-current portion	$	19,401		$	10,831

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NOTE 7 – CREDIT FACILITIES AND NOTES PAYABLE

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

(in thousands)	June 30, 2019			December 31, 2018
2018 Credit Facility – revolver	$	71,150		$	69,150
2018 Credit Facility – term note		10,833			15,000
Old Ironsides Notes		24,232			25,065
Other debt		69			57
Total debt		106,284			109,272
Less:  unamortized debt discount		(90	)		(134	)
Total credit facilities and notes payable		106,194			109,138
Current portion of credit facilities and notes payable		(9,910	)		(11,910	)
Non-current debt, net of current portion and unamortized debt discount	$	96,284		$	97,228

Carbon Appalachia

2018 Credit Facility

In connection with and concurrently with the closing of the OIE Membership Acquisition, the Company and its subsidiaries amended and restated our prior credit facilities 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 June 30, 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 London interbank offered rate (“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 July 1, 2020.

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

The affirmative and negative covenants are subject to various exceptions, including certain basket amounts and acceptable transaction levels. In addition, the 2018 Credit Facility requires the Borrowers’ compliance, on a consolidated basis, with a maximum Net Debt (all debt of the Borrowing Parties minus all unencumbered cash and cash equivalents of the Borrowers not to exceed $3.0 million) / EBITDAX (as defined) ratio of 3.50 to 1.00 and a current ratio, as defined, minimum of 1.00 to 1.00, tested quarterly, commencing with the quarter ending March 31, 2019. We were not in compliance with our current ratio but have obtained a waiver as of June 30, 2019. We are currently negotiating an amendment to the current ratio requirement on a go-forward basis. While we have historically been successful in renegotiating covenant requirements with our lenders, there can be no assurance that we will be able to do so successfully in the future.

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As of June 30, 2019, there was approximately $71.2 million in outstanding borrowings and $3.8 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 International Swaps and Derivatives Association Master Agreements (“ISDA Master Agreements”) 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 approximately $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 $90,000 as of June 30, 2019 and is directly offset against the loan in current liabilities. As of June 30, 2019, we had unamortized deferred issuance costs of approximately $564,000 associated with the 2018 Credit Facility. During the three and six months ended June 30, 2019, we amortized approximately $63,000 and $125,000, respectively, as interest expense associated with the 2018 Credit Facility.

Old Ironsides Notes

On December 31, 2018, as part of the OIE Membership Acquisition, we delivered unsecured, promissory notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides (the “Old Ironsides Notes”). The Old Ironsides Notes bear interest at 10.0% 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 12.0% per annum. For the six months ended June 30, 2019, the Company elected payment-in-kind interest of approximately $1.2 million.

Carbon California

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

(in thousands)	June 30, 2019			December 31, 2018
Senior Revolving Notes, related party, due February 15, 2022	$	33,500		$	38,500
Subordinated Notes, related party, due February 15, 2024		13,000			13,000
Total principal		46,500			51,500
Less: Deferred notes costs		(196	)		(235	)
Less: unamortized debt discount		(1,215	)		(1,346	)
Total notes payable – related party	$	45,089		$	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 June 30, 2019, the borrowing base was $45.0 million, of which $33.5 million was outstanding.  

Carbon California may elect to incur interest at either (i) 5.50% plus LIBOR or (ii) 4.50% plus the Prime Rate (which is defined as the interest rate published daily by JPMorgan Chase Bank, N.A.). As of June 30, 2019, the effective borrowing rate for the Senior Revolving Notes was 7.60%. 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.

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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 $935,000. For the three and six months ended June 30, 2019, Carbon California amortized fees of $79,000 and $153,000, respectively.

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 12.0% 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 June 30, 2019.

Prudential received an additional 1,425 Class A Units, representing 5.0% of the total sharing percentage, for the issuance of the Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding Subordinated Notes of $10.0 million. The Company then allocated the non-cash value of the units of approximately $1.3 million, which was recorded as a discount to the Subordinated Notes. As of June 30, 2019, Carbon California has an outstanding discount of approximately $824,000, which is presented net of the Subordinated Notes within Notes payable-related party on the unaudited condensed consolidated balance sheets. During the three and six months ended June 30, 2019, Carbon California amortized $45,000 and $89,000, respectively, associated with the Subordinated Notes.

The Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45.0%, respectively.

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

2018 Subordinated Notes, Related Party

On May 1, 2018, Carbon California entered into an agreement with Prudential for the issuance and sale of $3.0 million in subordinated notes due February 15, 2024, bearing interest of 12.0% per annum (the “2018 Subordinated Notes”), of which $3.0 million remains outstanding as of June 30, 2019.

Prudential received 585 Class A Units, representing an approximate 2.0% additional sharing percentage, for the issuance of the 2018 Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding 2018 Subordinated Notes of $3.0 million. The Company then allocated the non-cash value of the units of approximately $490,000, which was recorded as a discount to the 2018 Subordinated Notes. As of June 30, 2019, Carbon California had an outstanding discount of $391,000 associated with these notes, which is presented net of the 2018 Subordinated Notes within Notes payable - related party on the unaudited condensed consolidated balance sheets. During the three and six months ended June 30, 2019, Carbon California amortized $21,000 and $42,000, respectively, associated with the 2018 Subordinated Notes.

The 2018 Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45.0%, 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.

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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 with (A) a maximum Debt/EBITDA ratio of 4.0 to 1.0 (B) a maximum Senior Revolving Notes/EBITDA ratio of 2.5 to 1.0, (C) a minimum interest coverage ratio of 2.0 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 with (A) a maximum Debt/EBITDA ratio of 4.75 to 1.0, (B) a maximum Senior Revolving Notes/EBITDA ratio of 3.0 to 1.0, (C) a minimum interest coverage ratio of 1.6 to 1.0, (D) an asset coverage test whereby indebtedness may not exceed the product of 0.65 times Adjusted PV-10 set forth in the most recent reserve report, (E) maintenance of a minimum borrowing base of $10.0 million under the Senior Revolving Notes and (F) a minimum current ratio of 0.85 to 1.00.

As of June 30, 2019, Carbon California was in compliance with its covenants.

NOTE 8 – LEASES

On January 1, 2019, we adopted Topic 842. Results for reporting periods beginning January 1, 2019 are presented in accordance with Topic 842, while prior period amounts are reported in accordance with Topic 840 – Leases. 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 Topic 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 Topic 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.

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.

Our right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet. All leases recognized on our unaudited condensed 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	$	3,644	$	3,644
Corporate leases		2,378		2,388
Vehicles		924		791
Total	$	6,946	$	6,823

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

The following table summarizes the components of our gross operating lease costs incurred during the three and six months ended June 30, 2019:

(in thousands)	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
Operating lease cost	$	7		$	538
Short-term lease cost		(5	)		156
Total lease cost	$	2		$	694

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. See Note 7 for additional information on our credit facilities.

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

	June 30, 2019
Weighted-average lease term (years)		4.0
Weighted-average discount rate		6.36	%

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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)	Six Months Ended June 30, 2019
Operating cash flows for operating leases	$	1,191

Minimum future commitments by year for our long-term operating leases as of June 30, 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	$	1,021
2020		1,960
2021		1,902
2022		1,704
2023		1,157
Thereafter		11
Total future minimum lease payments	$	7,755
Less: imputed interest		(932	)
Total lease liabilities	$	6,823

NOTE 9 – REVENUE

The following tables present our disaggregated revenue by primary region within the United States and major product line:

For the three months ended June 30, 2019 and 2018 (in thousands):

	Appalachian and Illinois Basins				Ventura Basin				Total
	Three Months Ended June 30,				Three Months Ended June 30,				Three Months Ended June 30,
	2019		2018		2019		2018		2019		2018
Natural gas sales	$	13,879	$	3,114	$	337	$	409	$	14,216	$	3,523
Natural gas liquids sales		-		-		195		550		195		550
Oil sales		1,558		2,377		8,344		5,714		9,902		8,091
Transportation and handling		322		-		-		-		322		-
Marketing gas sales		3,221		-		-		-		3,221		-
Total	$	18,980	$	5,491	$	8,876	$	6,673	$	27,856	$	12,164

For the six months ended June 30, 2019 and 2018 (in thousands):

	Appalachian and Illinois Basins				Ventura Basin				Total
	Six Months Ended June 30,				Six Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018		2019		2018
Natural gas sales	$	32,671	$	6,919	$	861	$	543	$	33,532	$	7,462
Natural gas liquids sales		-		-		441		713		441		713
Oil sales		3,095		2,624		15,796		8,450		18,891		11,074
Transportation and handling		1,056		-		-		-		1,056		-
Marketing gas sales		8,165		-		-		-		8,165		-
Total	$	44,987	$	9,543	$	17,098	$	9,706	$	62,085	$	19,249

We record revenue in the month production is delivered to the purchaser, but settlement statements may not be received until 30 to 90 days after the month of production. As such, we estimate the production delivered and the related pricing. The estimated revenue is recorded within Accounts receivable – Revenue on the unaudited condensed consolidated balance sheets. Any differences between our initial estimates and actuals are recorded in the month payment is received from the customer. These differences have not historically been material. Revenue recognized for the six months ended June 30, 2019, that related to performance obligations satisfied in prior reporting periods, was immaterial.

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NOTE 10 – STOCK-BASED COMPENSATION PLANS

We have three stock plans, the Carbon 2011 Stock Incentive Plan, the Carbon 2015 Stock Incentive Plan and the Carbon 2019 Long Term Incentive Plan (collectively the “Carbon Plans”). The Carbon 2019 Long Term Incentive Plan was approved by the Company’s stockholders in May 2019. The Carbon Plans provide for the issuance of approximately 1.6 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 June 30, 2019, approximately 748,000 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 six months ended June 30, 2019, approximately 65,000 restricted stock units vested.

Compensation costs recognized for these restricted stock grants were approximately $224,000 and $403,000 for the three and six months ended June 30, 2019, respectively, and approximately $190,000 and $348,000 for the three and six months ended June 30, 2018, respectively. As of June 30, 2019, there was approximately $1.9 million unrecognized compensation costs related to these restricted stock grants which we expect to be recognized over the next 6.8 years.

Restricted Performance Units

As of June 30, 2019, approximately 699,000 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. During the six months ended June 30, 2019, approximately 95,000 performance units vested.

We account for the performance units granted during 2017 through 2019 at their fair value determined at the date of grant, which were $7.20, $9.80 and $10.00 per share, respectively. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At June 30, 2019, we estimated that none of the performance units granted in 2017 through 2019 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 six months ended June 30, 2019 and 2018, respectively. As of June 30, 2019, compensation costs related to the performance units granted in 2015 and 2016 have been fully recognized. As of June 30, 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 outstanding performance units would be approximately $3.8 million.

NOTE 11 – EARNINGS (LOSS) PER COMMON SHARE

Basic earnings (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders for the period by the basic weighted average number of common shares outstanding during the period. Basic shares exclude the dilutive effect of common shares that could potentially be issued due to the exercise of stock options and warrants or the vesting of restricted stock or performance units. Diluted earnings (loss) per common share includes potentially issuable shares, other than anti-dilutive shares. We use the treasury method to determine the dilutive effect, 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 common stock equivalents are excluded from the calculation of diluted weighted average shares outstanding because they would have an anti-dilutive effect, meaning the loss per share would be reduced.

For the three months ended June 30, 2019 and 2018, approximately 276,000 and 598,000 shares, respectively, and for the six months ended June 30, 2019 and 2018, approximately 276,000 and 282,000 shares, respectively, were considered anti-dilutive and were excluded from the computation of diluted earnings per share.

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

	Three months ended June 30,					Six months ended June 30,
(in thousands, except per share amounts)	2019		2018			2019		2018
Net income (loss) attributable to controlling interests before preferred shares	$	6,229	$	(579	)	$	2,129	$	2,989
Less: net income attributable to preferred shares – preferred return		75		-			150		-
Net income (loss) attributable to common stockholders, basic		6,154		(579	)		1,979		2,989
Less: warrant derivative gain		-		-			-		(225	)
Less: beneficial conversion feature		-		(1,125	)		-		(1,125	)
Less: deemed dividend for convertible preferred shares		-		(71	)		-		(71	)
Net income (loss) attributable to common stockholders, diluted		6,154		(1,775	)		1,979		1,568
Weighted-average number of common shares outstanding, basic		7,815		7,693			7,739		7,346
Add dilutive effects of non-vested shares of restricted stock		342		-			342		316
Weighted-average number of common shares outstanding, diluted		8,157		7,693			8,081		7,662
Net income (loss) per common share, basic	$	0.79	$	(0.08	)	$	0.26	$	0.41
Net income (loss) per common share, diluted	$	0.75	$	(0.23	)	$	0.24	$	0.20

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 15.0% 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 6.0% of the initial issue price of $100 per share per annum. The holders of the Preferred Stock are entitled to the same number of votes of common stock that such share of Preferred Stock would represent on an as converted basis. The holders of the Preferred Stock receive liquidation preference based on the initial issue price of $100 per share plus a preferred return over common stockholders and the holders of any junior ranking stock. The preferred return was approximately $374,000 as of June 30, 2019 and increased by $150,000 during the six months ended June 30, 2019.

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. 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 June 30, 2018. We recorded the BCF as a reduction of retained earnings and an increase to additional paid-in capital 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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NOTE 12 – 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 June 30, 2019, the Company has established a full valuation allowance against the balance of net deferred tax assets.

NOTE 13 – FAIR VALUE MEASUREMENTS

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

(in thousands)	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Total
June 30, 2019
Assets:
Commodity derivatives	$	-	$	6,728	$	-	$	6,728
Liabilities:
Commodity derivatives	$	-	$	102	$	-	$	102
December 31, 2018
Asset:
Commodity derivatives	$	-	$	7,022	$	-	$	7,022

Commodity Derivative

As of June 30, 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 June 30, 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.

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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. During the six months ended June 30, 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.

NOTE 14 – COMMODITY DERIVATIVES

We historically use commodity-based derivative contracts to manage exposures to commodity price on a portion of our oil and natural gas production. We do not hold or issue derivative financial instruments for speculative or trading purposes. We also have entered into, on occasion, oil and natural gas physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. These contracts are not recorded at fair value in the 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 June 30, 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		5,925,000	$	2.82		1,129,500	$	2.60 – $3.03
2020		6,433,000	$	2.81		4,128,0000	$	2.40 – $2.75
2021		960,000	$	2.79		2,809,000	$	2.40 – $2.75

	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		125,178	$	53.39		81,493	$	67.01		1,200	$	47.50 - $56.60		21,800	$	47.00 - $75.00
2020		121,147	$	55.37		151,982	$	66.03		23,700	$	47.00 - $60.15		37,400	$	47.00 - $75.00
2021		-	$	-		86,341	$	67.12		33,000	$	47.00 - $60.15		98,000	$	47.00 - $75.00

*	Includes 100% of Carbon California’s outstanding derivative hedges at June 30, 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.

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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 condensed consolidated balance sheets. These derivative instruments are not designated as cash flow hedging instruments for accounting purposes:

(in thousands)	June 30, 2019		December 31, 2018
Commodity derivative contracts:
Commodity derivative asset	$	5,146	$	3,517
Commodity derivative asset – non-current	$	1,582	$	3,505
Commodity derivative liability	$	102	$	-

The table below summarizes the commodity settlements and unrealized gains and losses related to the Company’s derivative instruments for the three and six months ended June 30, 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 condensed consolidated statements of operations. 

	Three Months Ended June 30,					Six Months Ended June 30,
(in thousands)	2019		2018			2019			2018
Commodity derivative contracts:
Settlement gains (losses)	$	225	$	(674	)	$	(231	)	$	(1,060	)
Unrealized gains (losses)		8,455		(5,348	)		(396	)		(5,587	)
Total settlement and unrealized gains (losses), net	$	8,680	$	(6,022	)	$	(627	)	$	(6,647	)

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

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, gross fair value amounts, the amounts offset, and the net fair value of all derivative instruments in the unaudited condensed consolidated balance sheet as of June 30, 2019.

						Net
	Gross					Recognized
	Recognized		Gross			Fair Value
	Assets/		Amounts			Assets/
Balance Sheet Classification (in thousands)	Liabilities		Offset			Liabilities
Commodity derivative assets:
Commodity derivative asset	$	6,176	$	(1,030	)	$	5,146
Commodity derivative asset – non-current		2,792		(1,210	)		1,582
Total derivative assets	$	8,968	$	(2,240	)	$	6,728
Commodity derivative liabilities:
Commodity derivative liability	$	1,132	$	(1,030	)	$	(102	)
Commodity derivative liability – non-current		1,210		(1,210	)		-
Total derivative liabilities	$	2,342	$	(2,240	)	$	(102	)

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 15 – COMMITMENTS AND CONTINGENCIES

Delivery Commitments

We have entered into firm transportation contracts to ensure the transport for certain of our gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts as of June 30, 2019 are summarized in the table below.

Period	Dekatherms per day		Demand Charges
Jul 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 June 30, 2019, the remaining commitment related to the firm transportation contracts assumed in the EXCO Acquisition in 2016 and OIE Membership Acquisition is $16.7 million and reflected in the Company’s unaudited condensed 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 expiring in 2022. We have an option to extend the term of the agreement by another five years. The related demand charges for volume commitments over the remaining term of the agreement are approximately $1.8 million per year. We will pay a processing fee of $2.50 per Mcf for the term of the agreement, with a minimum annual volume commitment of 720,000 Mcf.

Capital Commitments

As of June 30, 2019, we had no capital commitments.

NOTE 16 – SUPPLEMENTAL CASH FLOW DISCLOSURE

Supplemental cash flow disclosures for the six months ended June 30, 2019 and 2018 are presented below:

	Six Months Ended June 30,
(in thousands)	2019		2018
Cash paid during the period for:
Interest	$	4,536	$	909
Non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	39	$	(161	)
Adjustments to OIE Membership Acquisition purchase price	$	1,317	$	-
Increase in asset retirement obligations	$	-	$	3,560
Non-cash acquisition of Carbon California interests	$	-	$	(18,906	)
Carbon California Acquisition on February 1, 2018	$	-	$	17,114
Obligations assumed with Seneca asset purchase	$	-	$	330
Accrued dividend for convertible preferred stock	$	-	$	71
Beneficial conversion feature for convertible preferred stock	$	-	$	1,125
Exercise of warrant derivative	$	-	$	(1,792	)

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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 for the fiscal year ended December 31, 2018 (the “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 98.11% of 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 June 30, 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
	Q3		Q4		Q1		Q2		Q3		Q4		Q1		Q2
Oil (Bbl)	$	48.19	$	55.39	$	62.89	$	67.90	$	69.50	$	58.83	$	54.90	$	59.96
Natural Gas (MMBtu)	$	2.89	$	2.87	$	3.13	$	2.77	$	2.88	$	3.62	$	3.00	$	2.57

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 is 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 lenders and may make it more difficult to comply with the covenants and other restrictions under our bank credit facilities. 

We use the full cost method of accounting for our oil and gas properties and perform a ceiling test quarterly. The ceiling calculation utilizes a rolling 12-month average commodity price. We did not recognize an impairment for the three and six months ended June 30, 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.

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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 2018 and the first two quarters of 2019, we concentrated our efforts on the acquisition and development of producing properties through the acquisitions consummated by Carbon California and Carbon Appalachia. In December 2018, 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 June 30, 2019, we owned working interests in approximately 7,800 gross wells (7,500 net), royalty interests located primarily in California, Illinois, Indiana, Kentucky, Ohio, Tennessee, Virginia, and West Virginia and held leasehold positions in approximately 336,400 net developed acres and approximately 1,311,000 net undeveloped acres. Approximately 67% 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 areas 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.

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	%

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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 completed the 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.

● In July 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 oil wells and one non-operated oil well 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 to Yorktown.

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.

● 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.

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● 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 and six months ended June 30, 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, net.  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. Interest expense, net is net of interest income.

● 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 carryforwards.

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Results of Operations

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018

The following discussion and analysis relates to items that have affected our results of operations for the three months ended June 30, 2019 and 2018. The following table sets forth, for the periods presented, selected historical unaudited condensed 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.

	Three Months Ended
	June 30,						Percent
(in thousands, except production and per unit data)	2019			2018 (1)			Change
Revenue:
Natural gas sales	$	14,216		$	3,523			303	%
Natural gas liquids sales		195			550			(65	%)
Oil sales		9,902			8,091			22	%
Transportation and handling		322			-			*
Marketing gas sales		3,221			-			*
Commodity derivative loss		8,680			(6,022	)		*
Other income		305			6			4983	%
Total revenues		36,841			6,148			499	%
Expenses:
Lease operating expenses		7,480			3,970			88	%
Pipeline operating expenses		2,950			-			*
Transportation costs		1,130			1,498			(25	%)
Production and property taxes		1,666			615			171	%
Marketing gas purchases		4,795			-			*
General and administrative		3,947			2,542			55	%
General and administrative – related party reimbursement		-			(1,096	)		*
Depreciation, depletion and amortization		3,881			1,979			96	%
Accretion of asset retirement obligations		405			162			150	%
Total expenses		26,254			9,670			171	%
Operating income (loss)	$	10,587		$	(3,522	)		*
Other income and (expense):
Interest expense, net		(3,445	)		(1,201	)		187	%
Equity investment income		21			525			(96	%)
Total other income (expense)	$	(3,424	)	$	(676	)		406	%
Production data:
Natural gas (Mcf)		5,299,644			1,525,436			247	%
Oil (Bbl)		150,274			112,776			33	%
Natural gas liquids (Bbl)		11,780			13,897			(15	%)
Combined (Mcfe)		6,271,968			2,285,474			174	%
Average prices before effects of hedges:
Natural gas (per Mcf)	$	2.68		$	2.31			16	%
Oil (per Bbl)	$	65.89		$	71.75			(8	%)
Natural gas liquids (per Bbl)	$	16.53		$	39.53			(58	%)
Combined (per Mcfe)	$	3.88		$	5.32			(27	%)
Average prices after effects of hedges**:
Natural gas (per Mcf)	$	2.82		$	2.44			16	%
Oil (per Bbl)	$	62.43		$	63.90			(2	%)
Natural gas liquids (per Bbl)	$	16.53		$	39.53			(58	%)
Combined (per Mcfe)	$	3.91		$	5.02			(22	%)
Average costs (per Mcfe):
Lease operating expenses	$	1.19		$	1.74			(32	%)
Transportation costs	$	0.18		$	0.66			(73	%)
Production and property taxes	$	0.27		$	0.27			-	%
Cash-based general and administrative expense, net of related party reimbursement	$	0.59		$	0.55			8	%
Depreciation, depletion and amortization	$	0.62		$	0.87			(29	%)

*	Not meaningful or applicable
**	Includes effect of settled commodity derivative gains and losses
(1)	Excludes 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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Natural gas, natural gas liquids, and oil sales – Sales of natural gas, natural gas liquids and oil increased approximately 100% for the three months ended June 30, 2019 compared to the same period in 2018, primarily due to a 174% increase in natural gas, natural gas liquids and oil sales volumes and partially offset by a 27% decrease in combined product pricing. The increases in production were a direct result of the acquisition of Carbon Appalachia and the resultant consolidation of the related activity for the three months ended June 30, 2019. Carbon Appalachia operating results are included in each of the three months ended June 30, 2019 whereas no Carbon Appalachia results were included in the three months ended June 30, 2018. Additionally, the December 2017 California wildfires significantly impacted Carbon California results of operations in the second quarter of 2018. Carbon California oil production was not impacted during the three months ended June 30, 2019 and average daily production increased from development efforts completed during 2018 and the first half of 2019.

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 June 30, 2019 and 2018, we had hedging gains of approximately $8.7 million and hedging losses of $6.0 million, respectively.

Lease operating expenses – Lease operating expenses for the three months ended June 30, 2019 increased primarily due to the OIE Membership Acquisition and the resultant increased production volumes. Expenses during the three months ended June 30, 2018 were also lower as a result of the December 2017 California wildfires. On a per Mcfe basis, lease operating expenses decreased to $1.19 per Mcfe for the three months ended June 30, 2019 from $1.74 per Mcfe for the three months ended June 30, 2018. We experience higher costs on a per Mcfe basis associated with the production of oil versus gas. Oil production accounted for approximately 30% of our production mix for the three months ended June 30, 2018 and 14% for the three months ended June 30, 2019.

Transportation costs – Transportation costs for the three months ended June 30, 2019 decreased as a result of a change in estimated transportation related liabilities. On a per Mcfe basis, these expenses decreased from $0.66 per Mcfe for the three months ended June 30, 2018 to $0.18 per Mcfe for the three months ended June 30, 2019.

Production and property taxes – Production and property taxes increased for the three months ended June 30, 2019 due to increased oil and natural gas sales as a result of consolidation of Carbon Appalachia. Production taxes averaged approximately 4.0% and 2.0% of product sales for the three months ended June 30, 2019 and 2018, respectively. Production taxes associated with oil production are generally lower on a per Mcfe basis versus gas production. Oil production accounted for approximately 30% of our production mix for the three months ended June 30, 2018 and 14% for the three months ended June 30, 2019. 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 for the three months ended June 30, 2019 primarily due to the consolidation of Carbon Appalachia. On a per Mcfe basis, DD&A decreased from $0.87 per Mcfe for the three months ended June 30, 2018 to $0.62 per Mcfe for the three months ended June 30, 2019. The decrease in the depletion rate is primarily attributable to the consolidation of Carbon Appalachia.

General and administrative expenses – General and administrative expenses increased for the three months ended June 30, 2019, primarily due to the consolidation of Carbon Appalachia. As a result of the consolidation of Carbon Appalachia during the three months ended June 30, 2019, management reimbursements which offset general and administrative expenses decreased by approximately $1.1 million compared to the three months ended June 30, 2018.

We define the term cash-based general and administrative expense (non-GAAP measure) as consolidated general and administrative expense adjusted to exclude non-cash stock-based compensation and related party reimbursements. On a per Mcfe basis, cash-based general and administrative expenses, net of related party reimbursements, increased from $0.55 per Mcfe for the three months ended June 30, 2018 to $0.59 per Mcfe for the three months ended June 30, 2019. Cash-based general and administrative expenses for the three months ended June 30, 2019 and 2018 are summarized in the following table:

General and administrative expenses	Three Months Ended June 30,				Increase/
(in thousands)	2019		2018		(Decrease)
General and administrative expenses	$	3,947	$	2,542	$	1,405
Adjustments:
Stock-based compensation		224		190		34
General and administrative – related party reimbursement		-		1,096		(1,096	)
Cash-based general and administrative expense	$	3,723	$	1,256	$	2,467

Interest expense, net – Interest expense, net increased for the three months ended June 30, 2019, primarily due to higher outstanding debt balances related to borrowings to complete the OIE Membership Acquisition and the Seneca Acquisition in 2018. On a per Mcfe basis, interest expense, net increased from $0.53 per Mcfe for the three months ended June 30, 2018 to $0.55 per Mcfe for the three months ended June 30, 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 June 30, 2019. These operations were not presented in our unaudited consolidated statements of operations during the three months ended June 30, 2018.

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Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

The following discussion and analysis relates to items that have affected our results of operations for the six months ended June 30, 2019 and 2018. The following table sets forth, for the periods presented, selected historical unaudited condensed consolidated statements of operations and production data.

	Six Months Ended
	June 30,						Percent
(in thousands, except production and per unit data)	2019			2018 (1)			Change
Revenue:
Natural gas sales	$	33,532		$	7,462			349	%
Natural gas liquids sales		441			713			(38	%)
Oil sales		18,891			11,074			71	%
Transportation and handling		1,056			-			*
Marketing gas sales		8,165			-			*
Commodity derivative loss		(627	)		(6,647	)		(91	%)
Other income		697			19			3568	%
Total revenues		62,155			12,621			392	%
Expenses:
Lease operating expenses		14,095			6,058			133	%
Pipeline operating expenses		6,035			-			*
Transportation costs		2,799			2,353			19	%
Production and property taxes		3,676			1,048			251	%
Marketing gas purchases		11,097			-			*
General and administrative		8,636			5,491			57	%
General and administrative – related party reimbursement		-			(2,213	)		(100	%)
Depreciation, depletion and amortization		7,860			3,471			126	%
Accretion of asset retirement obligations		799			303			163	%
Total expenses		54,997			16,511			233	%
Operating income (loss)	$	7,158		$	(3,890	)		*
Other income and (expense):
Interest expense, net		(6,725	)		(2,203	)		205	%
Warrant derivative gain		-			225			*
Gain on derecognized equity investments in affiliate-Carbon California		-			5,390			*
Equity investment income		40			962			(96	%)
Total other income (expense)	$	(6,685	)	$	4,374			*
Production data:
Natural gas (Mcf)		10,843,696			2,848,528			281	%
Oil (Bbl)		297,766			159,879			86	%
Natural gas liquids (Bbl)		24,990			18,399			36	%
Combined (Mcfe)		12,780,232			3,918,196			226	%
Average prices before effects of hedges:
Natural gas (per Mcf)	$	3.09		$	2.62			18	%
Oil (per Bbl)	$	63.44		$	69.27			(8	%)
Natural gas liquids (per Bbl)	$	17.66		$	38.74			(54	%)
Combined (per Mcfe)	$	4.14		$	4.91			(16	%)
Average prices after effects of hedges**:
Natural gas (per Mcf)	$	3.09		$	2.70			14	%
Oil (per Bbl)	$	62.85		$	61.33			2	%
Natural gas liquids (per Bbl)	$	17.66		$	38.74			(54	%)
Combined (per Mcfe)	$	4.12		$	4.64			(11	%)
Average costs (per Mcfe):
Lease operating expenses	$	1.10		$	1.55			(29	%)
Transportation costs	$	0.22		$	0.60			(63	%)
Production and property taxes	$	0.29		$	0.27			7	%
Cash-based general and administrative expense, net of related party reimbursement	$	0.64		$	0.71			(10	%)
Depreciation, depletion and amortization	$	0.62		$	0.89			(30	%)

* 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 June 30, 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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Natural gas, natural gas liquids, and oil sales – Sales of natural gas, natural gas liquids and oil increased approximately 175% for the six months ended June 30, 2019 compared to the same period in 2018 primarily due to a 226% increase in natural gas, natural gas liquids and oil sales volumes and partially offset by a 16% decrease in combined product pricing. The increases in production were a direct result of the acquisitions of Carbon Appalachia and Carbon California and the resultant consolidation of the related activity for the six months ended June 30, 2019. Carbon Appalachia operating results are included in each of the six months ended June 30, 2019 whereas no Carbon Appalachia results were included in the six months ended June 30, 2018. Additionally, the December 2017 California wildfires significantly impacted Carbon California results of operations for the six months ended June 30, 2018. Carbon California oil production was not impacted during the six months ended June 30, 2019 and average daily production increased from development efforts completed during 2018 and the first half of 2019. Finally, the Seneca Acquisition closed May 1, 2018, and therefore operations for the six months ended June 30, 2018 include only two months of operations from the assets acquired compared to their inclusion for all six months during 2019.

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 six months ended June 30, 2019 and 2018, we had hedging losses of approximately $627,000 and $6.6 million, respectively.

Lease operating expenses – Lease operating expenses for the six months ended June 30, 2019 increased primarily due to the OIE Membership Acquisition, the exercise of the California Warrant and the Seneca Acquisition and the resultant increased production volumes. Expenses during the six months ended June 30, 2018 were also lower as a result of the December 2017 California wildfires. On a per Mcfe basis, lease operating expenses decreased to $1.10 per Mcfe for the six months ended June 30, 2019 from $1.55 per Mcfe for the six months ended June 30, 2018. We experience higher costs on a per Mcfe basis associated with the production of oil versus gas. Oil production accounted for approximately 24% of our production mix for the six months ended June 30, 2018 and 14% for the six months ended June 30, 2019.

Transportation costs – Transportation costs for the six months ended June 30, 2019 increased due to an increase in production as a result of the OIE Membership Acquisition and a full six months of Carbon California operations, including Seneca Acquisition assets. On a per Mcfe basis, these expenses decreased from $0.60 per Mcfe for the six months ended June 30, 2018 to $0.22 per Mcfe for the six months ended June 30, 2019.

Production and property taxes – Production and property taxes increased for the six months ended June 30, 2019 due to increased oil and natural gas sales as a result of the consolidation of Carbon Appalachia and a full six months of Carbon California production. Production taxes averaged approximately 3.7% and 2.4% of product sales for the six months ended June 30, 2019 and 2018, respectively. Production taxes associated with oil production are generally lower on a per Mcfe basis versus gas production. Oil production accounted for approximately 24% of our production mix for the six months ended June 30, 2018 and 14% for the six months ended June 30, 2019. 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 for the six months ended June 30, 2019 primarily due to the consolidation of Carbon Appalachia and a full six months of Carbon California operations, including the Seneca Acquisition assets. On a per Mcfe basis, DD&A decreased from $0.89 per Mcfe for the six months ended June 30, 2018 to $0.62 per Mcfe for the six months ended June 30, 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 for the six months ended June 30, 2019 primarily due to the consolidation of Carbon Appalachia and a full six months of Carbon California operations. As a result of the consolidation of Carbon Appalachia and Carbon California during the six months ended June 30, 2019, management reimbursements which offset general and administrative expenses, decreased by approximately $2.2 million compared to the six months ended June 30, 2018. On a per Mcfe basis, cash-based general and administrative expenses, net of related party reimbursements, decreased from $0.71 per Mcfe for the six months ended June 30, 2018 to $0.64 per Mcfe for the six months ended June 30, 2019. Cash-based general and administrative expenses for the six months ended June 30, 2019 and 2018 are summarized in the following table:

General and administrative expenses	Six Months Ended June 30,				Increase/
(in thousands)	2019		2018		(Decrease)
General and administrative expenses	$	8,636	$	5,491	$	3,145
Adjustments:
Stock-based compensation		446		483		(37	)
General and administrative – related party reimbursement		-		2,213		(2,213	)
Cash-based general and administrative expense	$	8,190	$	2,795	$	5,395

Interest expense, net – Interest expense, net increased for the six months ended June 30, 2019 primarily due to higher outstanding debt balances related to borrowings to complete the OIE Membership Acquisition and the Seneca Acquisition in 2018. On a per Mcfe basis, interest expense, net decreased from $0.56 per Mcfe for the six months ended June 30, 2018 to $0.53 per Mcfe for the six months ended June 30, 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 six months ended June 30, 2019. These operations were not presented in our unaudited consolidated statements of operations during the six months ended June 30, 2018.

Liquidity and Capital Resources

Our primary sources of liquidity and capital resources are cash flows from operations, borrowings under our credit facilities and senior revolving notes, and on occasion, we have engaged in the sale of non-core assets. Borrowings under the credit facilities and senior revolving notes may be used to fund field development projects and to fund future complementary acquisitions and for general working capital purposes. We may use other sources of capital, including the issuance of debt or equity securities, to fund acquisitions or maintain our financial flexibility.

As of June 30, 2019, our liquidity was $20.0 million, consisting of cash on hand of $4.7 million and $15.3 million of available borrowing capacity on our credit facilities and Senior Revolving Notes.

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 receive 100% of cash flows associated with Carbon Appalachia.

Prior to the consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, we generated operating cash flow by providing management services to these unconsolidated subsidiaries. These management service reimbursements were included in general and administrative – related party reimbursement on our unaudited condensed consolidated statements of operations. We also received reimbursements of operating expenses, our share of which were included in investment in affiliates on our unaudited condensed consolidated statements of operations. As we now consolidate Carbon California and Carbon Appalachia, these management and operating reimbursements are eliminated in the unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2019.

Commodity Derivatives

Our exploration, development and acquisition activities may require us to make significant operating and capital expenditures. 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 to moderate the effects of commodity price fluctuations on our cash flow.

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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 2018 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. See Note 14, Commodity Derivatives, in Part I, Item 1 to this Quarterly Report for more information, including our outstanding derivatives.

Sources and Uses of Cash

The following table presents net cash provided by or used in operating, investing and financing activities for the six months ended June 30, 2019 and 2018:

	Six Months Ended
	June 30,
(in thousands)	2019			2018
Net cash provided by operating activities	$	9,795		$	1,615
Net cash used in investing activities	$	(1,637	)	$	(40,197	)
Net cash (used in) provided by financing activities	$	(9,243	)	$	40,962

Operating Activities

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 $8.2 million for the six months ended June 30, 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, including the Seneca Acquisition.

Investment Activities

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 $38.6 million for the six months ended June 30, 2019 as compared to the same period in 2018, primarily due to the Seneca Acquisition.

Financing Activities

Net cash provided by or used in financing activities is primarily comprised of activities associated with our credit facilities. During the six months ended June 30, 2019, the Company paid $2.0 million in principal associated with the Old Ironsides Notes, paid approximately $6.2 million in principal associated with the 2018 Credit Facility, and paid approximately $5.0 million in principal associated with the Senior Revolving Notes. The payments were partially offset by an increase in borrowings under the 2018 Credit Facility by approximately $4.0 million. During the six months ended June 30, 2018, the Company increased borrowings by approximately $31.5 million, received $5.0 million in proceeds from the issuance of preferred stock to Yorktown, and received an equity contribution of $5.0 million from Prudential for the Seneca Acquisition.

Capital Expenditures

Capital expenditures incurred for the six months ended June 30, 2019 and 2018 are summarized in the following table:

	Six Months Ended June 30,
(in thousands)	2019		2018
Drilling and development	$	1,792	$	788
Other		71		39,684
Total capital expenditures	$	1,863	$	40,472

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 the first half of 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. 

32

Credit Facilities and Notes Payable

For a discussion of our long-term debt, see Note 7, Credit Facilities and Notes Payable, in Part I, Item 1 to this Quarterly Report.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of June 30, 2019.

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 June 30, 2019, there have been no significant changes to our critical accounting policies and estimates since our 2018 Annual Report on Form 10-K 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 several 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.

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.

33

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

As a smaller reporting company, we are not required to provide information for 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 June 30, 2019. Based on this evaluation, they believe that as of June 30, 2019 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 June 30, 2019, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

34

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

There have been no material changes to the risk factors disclosed in our 2018 Annual Report on Form 10-K. 

ITEM 6. Exhibits

Exhibit No.	Description
10.1	Carbon Energy Corporation 2019 Long Term Incentive Plan, incorporated by reference to Appendix A to the definitive proxy statement filed on April 23, 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

35

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: August 14, 2019	By:	/s/ Patrick R. McDonald
		PATRICK R. MCDONALD,
		Chief Executive Officer
Date: August 14, 2019	By:	/s/ Kevin D. Struzeski
		KEVIN D. STRUZESKI
		Chief Financial Officer

36

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.

August 14, 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.

August 14, 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 June 30, 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: August 14, 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 June 30, 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: August 14, 2019	/s/ Kevin D. Struzeski
	Kevin D. Struzeski
	Chief Financial Officer

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2019	Aug. 09, 2019
Document and Entity Information [Abstract]
Entity Registrant Name	Carbon Energy Corp
Entity Central Index Key	0000086264
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Type	10-Q
Document Period End Date	Jun. 30, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Shell Company	false
Entity Emerging Growth Company	false
Entity Ex Transition Period	false
Entity File Number	000-02040
Entity Interactive Data Current	Yes
Entity Incorporation State Country Code	DE
Entity Common Stock, Shares Outstanding		7,816,030

XML

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 4,651	$ 5,736
Accounts receivable:
Revenue	12,936	19,671
Joint interest billings and other	1,502	1,770
Insurance receivable (Note 2)		522
Commodity derivative asset (Note 14)	5,146	3,517
Prepaid expense, deposits and other current assets	1,930	1,645
Inventory	1,371	1,149
Total current assets	27,536	34,010
Oil and gas properties, full cost method of accounting:
Proved, net	244,381	248,455
Unproved	5,471	5,416
Other property and equipment, net	16,766	17,563
Total property and equipment, net	266,618	271,434
Investments in affiliates	588	598
Commodity derivative asset - non-current (Note 14)	1,582	3,505
Right-of-use assets (Note 8)	6,946
Other non-current assets	1,277	1,344
Total non-current assets	277,011	276,881
Total assets	304,547	310,891
Current liabilities:
Accounts payable and accrued liabilities (Note 5)	30,497	34,816
Firm transportation contract obligations (Note 15)	5,952	6,129
Lease liability - current (Note 8)	1,621
Commodity derivative liability (Note 14)	102
Credit facilities and notes payable - current (Note 7)	9,910	11,910
Total current liabilities	48,082	52,855
Non-current liabilities:
Firm transportation contract obligations (Note 15)	10,729	12,729
Lease liability - non-current (Note 8)	5,202
Production and property taxes payable	2,799	2,914
Asset retirement obligations (Note 6)	19,401	19,211
Credit facilities and notes payable (Note 7)	96,284	97,228
Notes payable - related party (Note 7)	45,089	49,919
Total non-current liabilities	179,504	182,001
Commitments and contingencies (Note 15)
Stockholders' equity:
Preferred stock, $0.01 par value; liquidation preference of $374,000 at June 30, 2019 and $224,000 at December 31, 2018; authorized 1,000,000 shares, 50,000 shares issued and outstanding at June 30, 2019 and December 31, 2018	1	1
Common stock, $0.01 par value; authorized 35,000,000 shares, 7,816,030 and 7,655,759 shares issued and outstanding at June 30, 2019 and December 31, 2018, respectively	79	77
Additional paid-in capital	85,057	84,612
Accumulated deficit	(34,810)	(36,939)
Total Carbon stockholders' equity	50,327	47,751
Non-controlling interests	26,634	28,284
Total stockholders' equity	76,961	76,035
Total liabilities and stockholders' equity	$ 304,547	$ 310,891

XML

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	1,000,000	1,000,000
Preferred stock, shares issued	50,000	50,000
Preferred stock, shares outstanding	50,000	50,000
Preferred stock, liquidation preference	$ 374,000	$ 224,000
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	35,000,000	35,000,000
Common stock, shares issued	7,816,030	7,655,759
Common stock, shares outstanding	7,816,030	7,655,759

XML

Condensed Consolidated Statements of Operations (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Revenue:
Commodity derivative gain (loss)	$ 8,680	$ (6,022)	$ (627)	$ (6,647)
Other income	305	6	697	19
Total revenue	36,841	6,148	62,155	12,621
Expenses:
Lease operating expenses	7,480	3,970	14,095	6,058
Pipeline operating expenses	2,950		6,035
Transportation and gathering costs	1,130	1,498	2,799	2,353
Production and property taxes	1,666	615	3,676	1,048
Marketing gas purchases	4,795		11,097
General and administrative	3,947	2,542	8,636	5,491
General and administrative - related party reimbursement		(1,096)		(2,213)
Depreciation, depletion and amortization	3,881	1,979	7,860	3,471
Accretion of asset retirement obligations	405	162	799	303
Total expenses	26,254	9,670	54,997	16,511
Operating income (loss)	10,587	(3,522)	7,158	(3,890)
Other income (expense):
Interest expense, net	(3,445)	(1,201)	(6,725)	(2,203)
Warrant derivative gain				225
Gain on derecognized equity investment in affiliate - Carbon California				5,390
Investment in affiliates	21	525	40	962
Total other (expense) income	(3,424)	(676)	(6,685)	4,374
Income (loss) before income taxes	7,163	(4,198)	473	484
Provision for income taxes
Net income (loss) before non-controlling interests and preferred shares	7,163	(4,198)	473	484
Net income (loss) attributable to non-controlling interests	934	(3,619)	(1,656)	(2,505)
Net income (loss) attributable to controlling interests before preferred shares	6,229	(579)	2,129	2,989
Net income attributable to preferred shares - preferred return	75		150
Net income (loss) attributable to common shares	$ 6,154	$ (579)	$ 1,979	$ 2,989
Net income (loss) per common share:
Basic (in dollars per share)	$ 0.79	$ (0.08)	$ 0.26	$ 0.41
Diluted (in dollars per share)	$ 0.75	$ (0.23)	$ 0.24	$ 0.20
Weighted average common shares outstanding:
Basic (in shares)	7,815	7,693	7,739	7,346
Diluted (in shares)	8,157	7,693	8,081	7,662
Natural gas sales [Member]
Revenue:
Total revenue	$ 14,216	$ 3,523	$ 33,532	$ 7,462
Natural gas liquids [Member]
Revenue:
Total revenue	195	550	441	713
Oil sales [Member]
Revenue:
Total revenue	9,902	8,091	18,891	11,074
Transportation and handling [Member]
Revenue:
Total revenue	322		1,056
Marketing gas sales [Member]
Revenue:
Total revenue	$ 3,221		$ 8,165

XML

Condensed 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 (in shares) at Dec. 31, 2017	6,006
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation			292			292
Restricted stock vested	$ 1					1
Restricted stock vested (in shares)	38
CCC warrant exercise - share issuance	$ 15		8,311	16,466		24,792
CCC warrant exercise - share issuance (in 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 (in shares) at Mar. 31, 2018	7,572
Balances at Dec. 31, 2017	$ 60		58,813	1,841	(44,218)	16,496
Balances (in shares) at Dec. 31, 2017	6,006
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)						484
Balances at Jun. 30, 2018	$ 77	$ 1	75,594	21,277	(42,424)	54,525
Balances (in shares) at Jun. 30, 2018	7,701	50
Balances at Mar. 31, 2018	$ 76		69,208	19,398	(40,649)	48,033
Balances (in shares) at Mar. 31, 2018	7,572
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation			192			192
Restricted stock vested
Restricted stock vested (in shares)	21
Preferred share issuance (Note 11)		$ 1	4,999			5,000
Preferred share issuance (Note 11) (in shares)		50
Deemed dividend			71		(71)
Non-controlling interest distributions, net				5,498		5,498
Net income (loss)				(3,619)	(579)	(4,198)
Balances at Jun. 30, 2018	$ 77	$ 1	75,594	21,277	(42,424)	54,525
Balances (in shares) at Jun. 30, 2018	7,701	50
Balances at Dec. 31, 2018	$ 77	$ 1	84,612	28,284	(36,939)	76,035
Balances (in shares) at Dec. 31, 2018	7,656	50
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation			222			222
Restricted stock vested	$ 1					1
Restricted stock vested (in shares)	40
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 (in shares) at Mar. 31, 2019	7,791	50
Balances at Dec. 31, 2018	$ 77	$ 1	84,612	28,284	(36,939)	76,035
Balances (in shares) at Dec. 31, 2018	7,656	50
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)						473
Balances at Jun. 30, 2019	$ 79	$ 1	85,057	26,634	(34,810)	76,961
Balances (in shares) at Jun. 30, 2019	7,816	50
Balances at Mar. 31, 2019	$ 79	$ 1	84,833	25,716	(41,039)	69,590
Balances (in shares) at Mar. 31, 2019	7,791	50
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation			224			224
Restricted stock vested
Restricted stock vested (in shares)	25
Deemed dividend
Non-controlling interest distributions, net				(16)		(16)
Net income (loss)				934	6,229	7,163
Balances at Jun. 30, 2019	$ 79	$ 1	$ 85,057	$ 26,634	$ (34,810)	$ 76,961
Balances (in shares) at Jun. 30, 2019	7,816	50

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Cash flows from operating activities:
Net income	$ 473	$ 484
Items not involving cash:
Depreciation, depletion and amortization	7,860	3,471
Accretion of asset retirement obligations	799	303
Unrealized commodity derivative loss	396	5,587
Warrant derivative gain		(225)
Stock-based compensation expense	446	483
Investment in affiliates	(40)	(962)
Gain on derecognized equity investment in affiliate - Carbon California		(5,390)
Amortization of debt costs	405	247
Interest expense paid-in-kind	1,244
Net change in:
Accounts receivable	7,525	(353)
Prepaid expenses, deposits and other current assets	(375)	570
Accounts payable, accrued liabilities and firm transportation contract obligations	(8,611)	(1,416)
Other non-current items	(327)	(1,184)
Net cash provided by operating activities	9,795	1,615
Cash flows from investing activities:
Development and acquisition of properties and equipment	(1,863)	(40,472)
Proceeds received - Carbon California Acquisition		275
Distribution from affiliate	50
Proceeds received - disposition of oil and gas properties	176
Net cash used in investing activities	(1,637)	(40,197)
Cash flows from financing activities:
Proceeds from credit facility and notes payable	4,029	31,502
Proceeds from preferred shares		5,000
Payments on credit facility and notes payable	(13,185)	(14)
Debt issuance costs	(93)	(511)
Contributions to non-controlling interests, net	6	4,985
Net cash (used in) provided by financing activities	(9,243)	40,962
Net (decrease) increase in cash and cash equivalents	(1,085)	2,380
Cash and cash equivalents, beginning of period	5,736	1,650
Cash and cash equivalents, end of period	$ 4,651	$ 4,030

XML

Organization

6 Months Ended

Jun. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

ORGANIZATION

NOTE 1 – ORGANIZATION

Carbon Energy Corporation (formerly known as Carbon Natural Gas Company) is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil, natural gas and natural gas liquids properties located in the United States. The terms “we”, “us”, “our”, the “Company” or “Carbon” refer to Carbon Energy Corporation and our consolidated subsidiaries (described below). The following is an organization chart of the key subsidiaries as of June 30, 2019 discussed in this report:

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 June 30, 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 conducts operations on behalf of Carbon California Company, LLC (“Carbon California”). On February 1, 2018, Yorktown Energy Partners XI, L.P. (“Yorktown”) exercised the California Warrant, collectively resulting in our aggregate sharing percentage in Carbon California increasing from 17.81% to 56.40%. On May 1, 2018, Carbon California closed the acquisition with Seneca Resources Corporation (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 June 30, 2019:

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 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 the rules and regulations of the Securities and Exchange Commission ("SEC") and in accordance with U.S. generally accepted accounting principles ("GAAP") applicable to interim financial statements. These unaudited condensed consolidated financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary for a fair presentation of the results of the interim period. Operating results for the interim periods presented require management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes and are not necessarily indicative of the results that may be expected for the full year. The condensed consolidated balance sheet data as of December 31, 2018 was derived from audited financial statements but does not include all disclosures required by GAAP. These unaudited condensed consolidated financial statements 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. The Company follows the same accounting policies for preparing quarterly and annual reports.

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 98.11% 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 condensed 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 condensed 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 stockholders' 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 final settlement payment from our insurance provider related to the damage caused by the California wildfires. As of June 30, 2019, we were in receipt of all funds associated with the claims.

Revenue

Upon completion of the OIE Membership Acquisition, our revenue recognition policy was amended to account for the additional revenue we receive for transportation and handling and marketing gas sales, as described below.

Transportation and handling

We generally purchase natural gas from producers at the wellhead or other receipt points, gather the wellhead natural gas through our gathering systems, and then sell the natural gas based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of natural gas or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, regardless of the actual amount of the sales proceeds we receive. Our revenues under percent-of-proceeds/index arrangements generally correlate to the price of natural gas. Under fee-based arrangements, we receive a fee for storing natural gas. The storage revenues earned are directly related to the volume of natural gas that flows through our systems and are not directly dependent on commodity prices.

Marketing Gas Sales

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

Recently Adopted Accounting Pronouncement

On January 1, 2019, we adopted Accounting Standards Update No. 2016-02, Leases ("Topic 842") (ASU 2016-02), as amended, which supersedes the lease accounting guidance under Topic 840, and generally requires lessees to recognize operating and financing lease liabilities and corresponding right-of-use assets on the balance sheet and to provide enhanced disclosures surrounding the amount, timing and uncertainty of cash flows arising from leasing arrangements. We adopted the new guidance using the modified retrospective transition approach by applying the new standard to all leases existing at the date of initial application and not restating comparative periods. The most significant impact was the recognition of right-of-use assets and lease liabilities for operating leases. See Note 8 for further information on our implementation of this standard. 

Recently Issued Accounting Pronouncements

In August 2018, the Financial Accounting Standard Board issued ASU 2018-13 - Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement. The objective of this update is to improve the effectiveness of fair value measurement disclosures. This update is effective for annual periods beginning after December 15, 2019, and interim periods within those annual periods. The standard will only impact the Company's disclosures.

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Acquisitions

6 Months Ended

Jun. 30, 2019

Business Combinations [Abstract]

ACQUISITIONS

NOTE 3 – ACQUISITIONS

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 into 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 Appalachia, 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 would 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 10.0% 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 was accounted for as a business combination in accordance with ASC 805, Business Combinations. 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 $25.0 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		25,030
Fair value of previously held equity interest		14,158
Fair value of business acquired	$	72,188

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		108,816
Unproved		1,869
Other property, plant and equipment, net		15,626
Other non-current assets		514
Accounts payable and accrued liabilities		(20,466	)
Due to related parties		(458	)
Firm transportation contract obligations		(18,724	)
Asset retirement obligations		(5,626	)
Notes payable		(37,975	)
Total net assets acquired	$	72,188

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 cost 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 and six months ended June 30, 2018 as though the OIE Membership Acquisition had been completed as of January 1, 2018. Results for the three and six months ended June 30, 2019 are reflected in the unaudited condensed consolidated statements of operations.

	Three Months Ended June 30,			Six Months Ended June 30,
(in thousands, except per share amounts)	2018			2018
Revenue	$	23,682		$	54,841
Net (loss) income before non-controlling interests	$	(2,758	)	$	3,046
Net loss attributable to non-controlling interests	$	(3,619	)	$	(2,505	)
Net income attributable to controlling interests before preferred shares	$	861		$	5,551
Net income per share, basic	$	0.11		$	0.76
Net income per share, diluted	$	(0.04	)	$	0.54

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 56.40% of the voting and profits interests of Carbon California.

Below are unaudited pro forma consolidated results of operations for the three and six months ended June 30, 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 condensed consolidated statements of operations for the six months ended June 30, 2018, includes the results of operations for the period February 1, 2018, through June 30, 2018. Results for the three and six months ended June 30, 2019 are reflected in the unaudited condensed consolidated statements of operations.

	Three Months Ended June 30,			Six Months Ended June 30,
(in thousands, except per share amounts)	2018			2018
Revenue	$	8,180		$	20,283
Net (loss) income before non-controlling interests	$	(3,013	)	$	4,256
Net loss attributable to non-controlling interests	$	(3,619	)	$	(2,504	)
Net income attributable to controlling interests before preferred shares	$	607		$	7,739
Net income per share, basic	$	0.27		$	1.01
Net income per share, diluted	$	0.09		$	0.84

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Property and Equipment

6 Months Ended

Jun. 30, 2019

Property, Plant and Equipment [Abstract]

PROPERTY AND EQUIPMENT

NOTE 4 – PROPERTY AND EQUIPMENT

Property and equipment, net consists of the following:

(in thousands)	June 30, 2019			December 31, 2018
Oil and gas properties:
Proved oil and gas properties	$	346,654		$	343,736
Unproved properties not subject to depletion		5,471			5,416
Accumulated depreciation, depletion, amortization and impairment		(102,273	)		(95,281	)
Net oil and gas properties		249,852			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		6,721			6,649
Accumulated depreciation and amortization		(4,791	)		(3,922	)
Net other property and equipment		16,766			17,563
Property and equipment, net	$	266,618		$	271,434

As of June 30, 2019, and December 31, 2018, the Company had approximately $5.5 million and $5.4 million, respectively, of unproved oil and gas properties not subject to depletion. Such costs are excluded from the full cost pool until it is determined if reserves can be assigned to the related properties. Subject to industry conditions, evaluation of most of these properties and the inclusion of their costs in the full cost pool is expected to be completed within five years. Unproved properties are assessed for impairment at least annually. During the three and six months ended June 30, 2019, approximately $206,000 of expiring leasehold costs were reclassified into proved property. There were no expiring leasehold costs during the three and six months ended June 30, 2018.

We capitalized overhead applicable to acquisition, development and exploration activities of approximately $305,000 and $373,000 for the three and six months ended June 30, 2019, respectively. For the three and six months ended June 30, 2018, we capitalized overhead applicable to acquisition, development, and exploration activities of approximately $119,000 and $190,000, respectively.

Depletion expense related to oil and gas properties for the three and six months ended June 30, 2019 was approximately $3.5 million and $7.0 million, respectively. Depletion expense related to oil and gas properties for the three and six months ended June 30, 2018 was approximately $1.8 million and $3.1 million, respectively.

For the three and six months ended June 30, 2019 and 2018, we did not recognize any ceiling test impairments as our full cost pool did not exceed the ceiling limitations.

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Accounts Payable and Accrued Liabilities

6 Months Ended

Jun. 30, 2019

Payables and Accruals [Abstract]

ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

NOTE 5 – ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Accounts payable and accrued liabilities at June 30, 2019 and December 31, 2018 consist of the following:

(in thousands)	June 30, 2019		December 31, 2018
Accounts payable	$	4,982	$	7,670
Oil and gas revenue suspense		3,123		2,675
Gathering and transportation payables		1,788		1,774
Production taxes payable		2,520		1,860
Accrued operating costs		875		3,155
Accrued ad valorem taxes – current		6,104		3,474
Accrued general and administrative expenses		1,750		3,111
Accrued asset retirement obligation – current		3,708		3,099
Accrued interest		1,513		955
Accrued gas purchases		2,912		5,440
Other liabilities		1,222		1,603
Total accounts payable and accrued liabilities	$	30,497	$	34,816

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Asset Retirement Obligation

6 Months Ended

Jun. 30, 2019

Asset Retirement Obligation [Abstract]

ASSET RETIREMENT OBLIGATION

NOTE 6 – ASSET RETIREMENT OBLIGATION

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:

(in thousands)	Six Months Ended June 30,
	2019			2018
Balance at beginning of period	$	22,310		$	7,737
Accretion expense		799			303
Additions during period		-			3,560
Balance at end of period	$	23,109		$	11,600
Less:  Current portion		(3,708	)		(769	)
Non-current portion	$	19,401		$	10,831

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Credit Facilities and Notes Payable

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

CREDIT FACILITIES AND NOTES PAYABLE

NOTE 7 – CREDIT FACILITIES AND NOTES PAYABLE

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

(in thousands)	June 30, 2019			December 31, 2018
2018 Credit Facility – revolver	$	71,150		$	69,150
2018 Credit Facility – term note		10,833			15,000
Old Ironsides Notes		24,232			25,065
Other debt		69			57
Total debt		106,284			109,272
Less:  unamortized debt discount		(90	)		(134	)
Total credit facilities and notes payable		106,194			109,138
Current portion of credit facilities and notes payable		(9,910	)		(11,910	)
Non-current debt, net of current portion and unamortized debt discount	$	96,284		$	97,228

Carbon Appalachia

2018 Credit Facility

In connection with and concurrently with the closing of the OIE Membership Acquisition, the Company and its subsidiaries amended and restated our prior credit facilities 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 June 30, 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 London interbank offered rate ("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 July 1, 2020.

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

The affirmative and negative covenants are subject to various exceptions, including certain basket amounts and acceptable transaction levels. In addition, the 2018 Credit Facility requires the Borrowers' compliance, on a consolidated basis, with a maximum Net Debt (all debt of the Borrowing Parties minus all unencumbered cash and cash equivalents of the Borrowers not to exceed $3.0 million) / EBITDAX (as defined) ratio of 3.50 to 1.00 and a current ratio, as defined, minimum of 1.00 to 1.00, tested quarterly, commencing with the quarter ending March 31, 2019. We were not in compliance with our current ratio but have obtained a waiver as of June 30, 2019. We are currently negotiating an amendment to the current ratio requirement on a go-forward basis. While we have historically been successful in renegotiating covenant requirements with our lenders, there can be no assurance that we will be able to do so successfully in the future.

As of June 30, 2019, there was approximately $71.2 million in outstanding borrowings and $3.8 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 International Swaps and Derivatives Association Master Agreements ("ISDA Master Agreements") 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 approximately $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 $90,000 as of June 30, 2019 and is directly offset against the loan in current liabilities. As of June 30, 2019, we had unamortized deferred issuance costs of approximately $564,000 associated with the 2018 Credit Facility. During the three and six months ended June 30, 2019, we amortized approximately $63,000 and $125,000, respectively, as interest expense associated with the 2018 Credit Facility.

Old Ironsides Notes

On December 31, 2018, as part of the OIE Membership Acquisition, we delivered unsecured, promissory notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides (the "Old Ironsides Notes"). The Old Ironsides Notes bear interest at 10.0% 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 12.0% per annum. For the six months ended June 30, 2019, the Company elected payment-in-kind interest of approximately $1.2 million.

Carbon California

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

(in thousands)	June 30, 2019			December 31, 2018
Senior Revolving Notes, related party, due February 15, 2022	$	33,500		$	38,500
Subordinated Notes, related party, due February 15, 2024		13,000			13,000
Total principal		46,500			51,500
Less: Deferred notes costs		(196	)		(235	)
Less: unamortized debt discount		(1,215	)		(1,346	)
Total notes payable – related party	$	45,089		$	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 June 30, 2019, the borrowing base was $45.0 million, of which $33.5 million was outstanding.  

Carbon California may elect to incur interest at either (i) 5.50% plus LIBOR or (ii) 4.50% plus the Prime Rate (which is defined as the interest rate published daily by JPMorgan Chase Bank, N.A.). As of June 30, 2019, the effective borrowing rate for the Senior Revolving Notes was 7.60%. 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 $935,000. For the three and six months ended June 30, 2019, Carbon California amortized fees of $79,000 and $153,000, respectively.

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 12.0% 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 June 30, 2019.

Prudential received an additional 1,425 Class A Units, representing 5.0% of the total sharing percentage, for the issuance of the Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding Subordinated Notes of $10.0 million. The Company then allocated the non-cash value of the units of approximately $1.3 million, which was recorded as a discount to the Subordinated Notes. As of June 30, 2019, Carbon California has an outstanding discount of approximately $824,000, which is presented net of the Subordinated Notes within Notes payable-related party on the unaudited condensed consolidated balance sheets. During the three and six months ended June 30, 2019, Carbon California amortized $45,000 and $89,000, respectively, associated with the Subordinated Notes.

The Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45.0%, respectively.

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

2018 Subordinated Notes, Related Party

On May 1, 2018, Carbon California entered into an agreement with Prudential for the issuance and sale of $3.0 million in subordinated notes due February 15, 2024, bearing interest of 12.0% per annum (the "2018 Subordinated Notes"), of which $3.0 million remains outstanding as of June 30, 2019.

Prudential received 585 Class A Units, representing an approximate 2.0% additional sharing percentage, for the issuance of the 2018 Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding 2018 Subordinated Notes of $3.0 million. The Company then allocated the non-cash value of the units of approximately $490,000, which was recorded as a discount to the 2018 Subordinated Notes. As of June 30, 2019, Carbon California had an outstanding discount of $391,000 associated with these notes, which is presented net of the 2018 Subordinated Notes within Notes payable - related party on the unaudited condensed consolidated balance sheets. During the three and six months ended June 30, 2019, Carbon California amortized $21,000 and $42,000, respectively, associated with the 2018 Subordinated Notes.

The 2018 Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45.0%, 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 (B) a maximum Senior Revolving Notes/EBITDA ratio of 2.5 to 1.0, (C) a minimum interest coverage ratio of 2.0 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 with (A) a maximum Debt/EBITDA ratio of 4.75 to 1.0, (B) a maximum Subordinated Notes/EBITDA ratio of 3.0 to 1.0, (C) a minimum interest coverage ratio of 1.6 to 1.0, (D) an asset coverage test whereby indebtedness may not exceed the product of 0.65 times Adjusted PV-10 set forth in the most recent reserve report, (E) maintenance of a minimum borrowing base of $10.0 million under the Senior Revolving Notes and (F) a minimum current ratio of 0.85 to 1.00.

As of June 30, 2019, Carbon California was in compliance with its covenants.

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Leases

6 Months Ended

Jun. 30, 2019

Leases [Abstract]

LEASES

NOTE 8 – LEASES

On January 1, 2019, we adopted Topic 842. Results for reporting periods beginning January 1, 2019 are presented in accordance with Topic 842, while prior period amounts are reported in accordance with Topic 840 – Leases. 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 Topic 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 Topic 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.

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.

Our right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet. All leases recognized on our unaudited condensed 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	$	3,644	$	3,644
Corporate leases		2,378		2,388
Vehicles		924		791
Total	$	6,946	$	6,823

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

The following table summarizes the components of our gross operating lease costs incurred during the three and six months ended June 30, 2019:

(in thousands)	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
Operating lease cost	$	7		$	538
Short-term lease cost		(5	)		156
Total lease cost	$	2		$	694

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. See Note 7 for additional information on our credit facilities.

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

	June 30, 2019
Weighted-average lease term (years)		4.0
Weighted-average discount rate		6.36	%

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

Cash paid for amounts included in measurement of lease liabilities (in thousands)	Six Months Ended June 30, 2019
Operating cash flows for operating leases	$	1,191

Minimum future commitments by year for our long-term operating leases as of June 30, 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	$	1,021
2020		1,960
2021		1,902
2022		1,704
2023		1,157
Thereafter		11
Total future minimum lease payments	$	7,755
Less: imputed interest		(932	)
Total lease liabilities	$	6,823

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Revenue

6 Months Ended

Jun. 30, 2019

Revenue Recognition and Deferred Revenue [Abstract]

REVENUE

NOTE 9 – REVENUE

The following tables present our disaggregated revenue by primary region within the United States and major product line:

For the three months ended June 30, 2019 and 2018 (in thousands):

	Appalachian and Illinois Basins				Ventura Basin				Total
	Three Months Ended June 30,				Three Months Ended June 30,				Three Months Ended June 30,
	2019		2018		2019		2018		2019		2018
Natural gas sales	$	13,879	$	3,114	$	337	$	409	$	14,216	$	3,523
Natural gas liquids sales		-		-		195		550		195		550
Oil sales		1,558		2,377		8,344		5,714		9,902		8,091
Transportation and handling		322		-		-		-		322		-
Marketing gas sales		3,221		-		-		-		3,221		-
Total	$	18,980	$	5,491	$	8,876	$	6,673	$	27,856	$	12,164

For the six months ended June 30, 2019 and 2018 (in thousands):

	Appalachian and Illinois Basins				Ventura Basin				Total
	Six Months Ended June 30,				Six Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018		2019		2018
Natural gas sales	$	32,671	$	6,919	$	861	$	543	$	33,532	$	7,462
Natural gas liquids sales		-		-		441		713		441		713
Oil sales		3,095		2,624		15,796		8,450		18,891		11,074
Transportation and handling		1,056		-		-		-		1,056		-
Marketing gas sales		8,165		-		-		-		8,165		-
Total	$	44,987	$	9,543	$	17,098	$	9,706	$	62,085	$	19,249

We record revenue in the month production is delivered to the purchaser, but settlement statements may not be received until 30 to 90 days after the month of production. As such, we estimate the production delivered and the related pricing. The estimated revenue is recorded within Accounts receivable – Revenue on the unaudited condensed consolidated balance sheets. Any differences between our initial estimates and actuals are recorded in the month payment is received from the customer. These differences have not historically been material. Revenue recognized for the six months ended June 30, 2019, that related to performance obligations satisfied in prior reporting periods, was immaterial.

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Stock-Based Compensation Plans

6 Months Ended

Jun. 30, 2019

Share-based Payment Arrangement [Abstract]

STOCK-BASED COMPENSATION PLANS

NOTE 10 – STOCK-BASED COMPENSATION PLANS

We have three stock plans, the Carbon 2011 Stock Incentive Plan, the Carbon 2015 Stock Incentive Plan and the Carbon 2019 Long Term Incentive Plan (collectively the "Carbon Plans"). The Carbon 2019 Long Term Incentive Plan was approved by the Company's stockholders in May 2019. The Carbon Plans provide for the issuance of approximately 1.6 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 June 30, 2019, approximately 748,000 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 six months ended June 30, 2019, approximately 65,000 restricted stock units vested.

Compensation costs recognized for these restricted stock grants were approximately $224,000 and $403,000 for the three and six months ended June 30, 2019, respectively, and approximately $190,000 and $348,000 for the three and six months ended June 30, 2018, respectively. As of June 30, 2019, there was approximately $1.9 million unrecognized compensation costs related to these restricted stock grants which we expect to be recognized over the next 6.8 years.

Restricted Performance Units

As of June 30, 2019, approximately 699,000 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. During the six months ended June 30, 2019, approximately 95,000 performance units vested.

We account for the performance units granted during 2017 through 2019 at their fair value determined at the date of grant, which were $7.20, $9.80 and $10.00 per share, respectively. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At June 30, 2019, we estimated that none of the performance units granted in 2017 through 2019 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 six months ended June 30, 2019 and 2018, respectively. As of June 30, 2019, compensation costs related to the performance units granted in 2015 and 2016 have been fully recognized. As of June 30, 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 outstanding performance units would be approximately $3.8 million.

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Earnings (Loss) Per Common Share

6 Months Ended

Jun. 30, 2019

Earnings Per Share [Abstract]

EARNINGS (LOSS) PER COMMON SHARE

NOTE 11 – EARNINGS (LOSS) PER COMMON SHARE

Basic earnings (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders for the period by the basic weighted average number of common shares outstanding during the period. Basic shares exclude the dilutive effect of common shares that could potentially be issued due to the exercise of stock options and warrants or the vesting of restricted stock or performance units. Diluted earnings (loss) per common share includes potentially issuable shares, other than anti-dilutive shares. We use the treasury method to determine the dilutive effect, 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 common stock equivalents are excluded from the calculation of diluted weighted average shares outstanding because they would have an anti-dilutive effect, meaning the loss per share would be reduced.

For the three months ended June 30, 2019 and 2018, approximately 276,000 and 598,000 shares, respectively, and for the six months ended June 30, 2019 and 2018, approximately 276,000 and 282,000 shares, respectively, were considered anti-dilutive and were excluded from the computation of diluted earnings per share.

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

	Three months ended June 30,					Six months ended June 30,
(in thousands, except per share amounts)	2019		2018			2019		2018
Net income (loss) attributable to controlling interests before preferred shares	$	6,229	$	(579	)	$	2,129	$	2,989
Less: net income attributable to preferred shares – preferred return		75		-			150		-
Net income (loss) attributable to common stockholders, basic		6,154		(579	)		1,979		2,989
Less: warrant derivative gain		-		-			-		(225	)
Less: beneficial conversion feature		-		(1,125	)		-		(1,125	)
Less: deemed dividend for convertible preferred shares		-		(71	)		-		(71	)
Net income (loss) attributable to common stockholders, diluted		6,154		(1,775	)		1,979		1,568
Weighted-average number of common shares outstanding, basic		7,815		7,693			7,739		7,346
Add dilutive effects of non-vested shares of restricted stock		342		-			342		316
Weighted-average number of common shares outstanding, diluted		8,157		7,693			8,081		7,662
Net income (loss) per common share, basic	$	0.79	$	(0.08	)	$	0.26	$	0.41
Net income (loss) per common share, diluted	$	0.75	$	(0.23	)	$	0.24	$	0.20

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 15.0% 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 6.0% of the initial issue price of $100 per share per annum. The holders of the Preferred Stock are entitled to the same number of votes of common stock that such share of Preferred Stock would represent on an as converted basis. The holders of the Preferred Stock receive liquidation preference based on the initial issue price of $100 per share plus a preferred return over common stockholders and the holders of any junior ranking stock. The preferred return was approximately $374,000 as of June 30, 2019 and increased by $150,000 during the six months ended June 30, 2019.

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. 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 June 30, 2018. We recorded the BCF as a reduction of retained earnings and an increase to additional paid-in capital 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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Income Taxes

6 Months Ended

Jun. 30, 2019

Income Tax Disclosure [Abstract]

INCOME TAXES

NOTE 12 – 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 June 30, 2019, the Company has established a full valuation allowance against the balance of net deferred tax assets.

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Fair Value Measurements

6 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

NOTE 13 – FAIR VALUE MEASUREMENTS

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

(in thousands)	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Total
June 30, 2019
Assets:
Commodity derivatives	$	-	$	6,728	$	-	$	6,728
Liabilities:
Commodity derivatives	$	-	$	102	$	-	$	102
December 31, 2018
Asset:
Commodity derivatives	$	-	$	7,022	$	-	$	7,022

Commodity Derivative

As of June 30, 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 June 30, 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. During the six months ended June 30, 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

6 Months Ended

Jun. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

COMMODITY DERIVATIVES

NOTE 14 – COMMODITY DERIVATIVES

We historically use commodity-based derivative contracts to manage exposures to commodity price on a portion of our oil and natural gas production. We do not hold or issue derivative financial instruments for speculative or trading purposes. We also have entered into, on occasion, oil and natural gas physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. These contracts are not recorded at fair value in the 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 June 30, 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		5,925,000	$	2.82		1,129,500	$	2.60 – $3.03
2020		6,433,000	$	2.81		4,128,0000	$	2.40 – $2.75
2021		960,000	$	2.79		2,809,000	$	2.40 – $2.75

	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		125,178	$	53.39		81,493	$	67.01		1,200	$	47.50 - $56.60		21,800	$	47.00 - $75.00
2020		121,147	$	55.37		151,982	$	66.03		23,700	$	47.00 - $60.15		37,400	$	47.00 - $75.00
2021		-	$	-		86,341	$	67.12		33,000	$	47.00 - $60.15		98,000	$	47.00 - $75.00

*	Includes 100% of Carbon California's outstanding derivative hedges at June 30, 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 condensed consolidated balance sheets. These derivative instruments are not designated as cash flow hedging instruments for accounting purposes:

(in thousands)	June 30, 2019		December 31, 2018
Commodity derivative contracts:
Commodity derivative asset	$	5,146	$	3,517
Commodity derivative asset – non-current	$	1,582	$	3,505
Commodity derivative liability	$	102	$	-

The table below summarizes the commodity settlements and unrealized gains and losses related to the Company's derivative instruments for the three and six months ended June 30, 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 condensed consolidated statements of operations. 

	Three Months Ended June 30,					Six Months Ended June 30,
(in thousands)	2019		2018			2019			2018
Commodity derivative contracts:
Settlement gains (losses)	$	225	$	(674	)	$	(231	)	$	(1,060	)
Unrealized gains (losses)		8,455		(5,348	)		(396	)		(5,587	)
Total settlement and unrealized gains (losses), net	$	8,680	$	(6,022	)	$	(627	)	$	(6,647	)

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

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, gross fair value amounts, the amounts offset, and the net fair value of all derivative instruments in the unaudited condensed consolidated balance sheet as of June 30, 2019.

						Net
	Gross					Recognized
	Recognized		Gross			Fair Value
	Assets/		Amounts			Assets/
Balance Sheet Classification (in thousands)	Liabilities		Offset			Liabilities
Commodity derivative assets:
Commodity derivative asset	$	6,176	$	(1,030	)	$	5,146
Commodity derivative asset – non-current		2,792		(1,210	)		1,582
Total derivative assets	$	8,968	$	(2,240	)	$	6,728
Commodity derivative liabilities:
Commodity derivative liability	$	1,132	$	(1,030	)	$	(102	)
Commodity derivative liability – non-current		1,210		(1,210	)		-
Total derivative liabilities	$	2,342	$	(2,240	)	$	(102	)

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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Commitments and Contingencies

6 Months Ended

Jun. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

NOTE 15 – COMMITMENTS AND CONTINGENCIES

Delivery Commitments

We have entered into firm transportation contracts to ensure the transport for certain of our gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts as of June 30, 2019 are summarized in the table below.

Period	Dekatherms per day		Demand Charges
Jul 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 June 30, 2019, the remaining commitment related to the firm transportation contracts assumed in the EXCO Acquisition in 2016 and OIE Membership Acquisition is $16.7 million and reflected in the Company's unaudited condensed 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 expiring in 2022. We have an option to extend the term of the agreement by another five years. The related demand charges for volume commitments over the remaining term of the agreement are approximately $1.8 million per year. We will pay a processing fee of $2.50 per Mcf for the term of the agreement, with a minimum annual volume commitment of 720,000 Mcf.

Capital Commitments

As of June 30, 2019, we had no capital commitments.

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Supplemental Cash Flow Disclosure

6 Months Ended

Jun. 30, 2019

Supplemental Cash Flow Elements [Abstract]

SUPPLEMENTAL CASH FLOW DISCLOSURE

NOTE 16 – SUPPLEMENTAL CASH FLOW DISCLOSURE

Supplemental cash flow disclosures for the six months ended June 30, 2019 and 2018 are presented below:

	Six Months Ended June 30,
(in thousands)	2019		2018
Cash paid during the period for:
Interest	$	4,536	$	909
Non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	39	$	(161	)
Adjustments to OIE Membership Acquisition purchase price	$	1,317	$	-
Increase in asset retirement obligations	$	-	$	3,560
Non-cash acquisition of Carbon California interests	$	-	$	(18,906	)
Carbon California Acquisition on February 1, 2018	$	-	$	17,114
Obligations assumed with Seneca asset purchase	$	-	$	330
Accrued dividend for convertible preferred stock	$	-	$	71
Beneficial conversion feature for convertible preferred stock	$	-	$	1,125
Exercise of warrant derivative	$	-	$	(1,792	)

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2019

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC") and in accordance with U.S. generally accepted accounting principles ("GAAP") applicable to interim financial statements. These unaudited condensed consolidated financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary for a fair presentation of the results of the interim period. Operating results for the interim periods presented require management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes and are not necessarily indicative of the results that may be expected for the full year. The condensed consolidated balance sheet data as of December 31, 2018 was derived from audited financial statements but does not include all disclosures required by GAAP. These unaudited condensed consolidated financial statements 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. The Company follows the same accounting policies for preparing quarterly and annual reports.

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 98.11% 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 condensed 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 condensed 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 stockholders' 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 final settlement payment from our insurance provider related to the damage caused by the California wildfires. As of June 30, 2019, we were in receipt of all funds associated with the claims.

Revenue

Revenue

Upon completion of the OIE Membership Acquisition, our revenue recognition policy was amended to account for the additional revenue we receive for transportation and handling and marketing gas sales, as described below.

Transportation and handling

We generally purchase natural gas from producers at the wellhead or other receipt points, gather the wellhead natural gas through our gathering systems, and then sell the natural gas based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of natural gas or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, regardless of the actual amount of the sales proceeds we receive. Our revenues under percent-of-proceeds/index arrangements generally correlate to the price of natural gas. Under fee-based arrangements, we receive a fee for storing natural gas. The storage revenues earned are directly related to the volume of natural gas that flows through our systems and are not directly dependent on commodity prices.

Marketing Gas Sales

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

Recently Adopted Accounting Pronouncements and New Accounting Pronouncements Not Yet Adopted

Recently Adopted Accounting Pronouncement

On January 1, 2019, we adopted Accounting Standards Update No. 2016-02, Leases ("Topic 842") (ASU 2016-02), as amended, which supersedes the lease accounting guidance under Topic 840, and generally requires lessees to recognize operating and financing lease liabilities and corresponding right-of-use assets on the balance sheet and to provide enhanced disclosures surrounding the amount, timing and uncertainty of cash flows arising from leasing arrangements. We adopted the new guidance using the modified retrospective transition approach by applying the new standard to all leases existing at the date of initial application and not restating comparative periods. The most significant impact was the recognition of right-of-use assets and lease liabilities for operating leases. See Note 8 for further information on our implementation of this standard. 

Recently Issued Accounting Pronouncements

In August 2018, the Financial Accounting Standard Board issued ASU 2018-13 - Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement. The objective of this update is to improve the effectiveness of fair value measurement disclosures. This update is effective for annual periods beginning after December 15, 2019, and interim periods within those annual periods. The standard will only impact the Company's disclosures.

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Acquisitions (Tables)

6 Months Ended

Jun. 30, 2019

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		25,030
Fair value of previously held equity interest		14,158
Fair value of business acquired	$	72,188

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		108,816
Unproved		1,869
Other property, plant and equipment, net		15,626
Other non-current assets		514
Accounts payable and accrued liabilities		(20,466	)
Due to related parties		(458	)
Firm transportation contract obligations		(18,724	)
Asset retirement obligations		(5,626	)
Notes payable		(37,975	)
Total net assets acquired	$	72,188

Schedule of unaudited pro-forma consolidated results

	Three Months Ended June 30,			Six Months Ended June 30,
(in thousands, except per share amounts)	2018			2018
Revenue	$	23,682		$	54,841
Net (loss) income before non-controlling interests	$	(2,758	)	$	3,046
Net loss attributable to non-controlling interests	$	(3,619	)	$	(2,505	)
Net income attributable to controlling interests before preferred shares	$	861		$	5,551
Net income per share, basic	$	0.11		$	0.76
Net income per share, diluted	$	(0.04	)	$	0.54

Carbon California [Member]

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

Schedule of unaudited pro-forma consolidated results

	Three Months Ended June 30,			Six Months Ended June 30,
(in thousands, except per share amounts)	2018			2018
Revenue	$	8,180		$	20,283
Net (loss) income before non-controlling interests	$	(3,013	)	$	4,256
Net loss attributable to non-controlling interests	$	(3,619	)	$	(2,504	)
Net income attributable to controlling interests before preferred shares	$	607		$	7,739
Net income per share, basic	$	0.27		$	1.01
Net income per share, diluted	$	0.09		$	0.84

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Property and Equipment (Tables)

6 Months Ended

Jun. 30, 2019

Property, Plant and Equipment [Abstract]

Schedule of net property and equipment

(in thousands)	June 30, 2019			December 31, 2018
Oil and gas properties:
Proved oil and gas properties	$	346,654		$	343,736
Unproved properties not subject to depletion		5,471			5,416
Accumulated depreciation, depletion, amortization and impairment		(102,273	)		(95,281	)
Net oil and gas properties		249,852			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		6,721			6,649
Accumulated depreciation and amortization		(4,791	)		(3,922	)
Net other property and equipment		16,766			17,563
Property and equipment, net	$	266,618		$	271,434

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Accounts Payable and Accrued Liabilities (Tables)

6 Months Ended

Jun. 30, 2019

Payables and Accruals [Abstract]

Schedule of accounts payable and accrued liabilities

(in thousands)	June 30, 2019		December 31, 2018
Accounts payable	$	4,982	$	7,670
Oil and gas revenue suspense		3,123		2,675
Gathering and transportation payables		1,788		1,774
Production taxes payable		2,520		1,860
Accrued operating costs		875		3,155
Accrued ad valorem taxes – current		6,104		3,474
Accrued general and administrative expenses		1,750		3,111
Accrued asset retirement obligation – current		3,708		3,099
Accrued interest		1,513		955
Accrued gas purchases		2,912		5,440
Other liabilities		1,222		1,603
Total accounts payable and accrued liabilities	$	30,497	$	34,816

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Asset Retirement Obligation (Tables)

6 Months Ended

Jun. 30, 2019

Asset Retirement Obligation [Abstract]

Schedule of reconciliation of the ARO

(in thousands)	Six Months Ended June 30,
	2019			2018
Balance at beginning of period	$	22,310		$	7,737
Accretion expense		799			303
Additions during period		-			3,560
Balance at end of period	$	23,109		$	11,600
Less:  Current portion		(3,708	)		(769	)
Non-current portion	$	19,401		$	10,831

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Credit Facilities and Notes Payable (Tables)

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

Schedule of outstanding credit facilities and notes payable

(in thousands)	June 30, 2019			December 31, 2018
2018 Credit Facility – revolver	$	71,150		$	69,150
2018 Credit Facility – term note		10,833			15,000
Old Ironsides Notes		24,232			25,065
Other debt		69			57
Total debt		106,284			109,272
Less:  unamortized debt discount		(90	)		(134	)
Total credit facilities and notes payable		106,194			109,138
Current portion of credit facilities and notes payable		(9,910	)		(11,910	)
Non-current debt, net of current portion and unamortized debt discount	$	96,284		$	97,228

Schedule of outstanding notes payable - related party

(in thousands)	June 30, 2019			December 31, 2018
Senior Revolving Notes, related party, due February 15, 2022	$	33,500		$	38,500
Subordinated Notes, related party, due February 15, 2024		13,000			13,000
Total principal		46,500			51,500
Less: Deferred notes costs		(196	)		(235	)
Less: unamortized debt discount		(1,215	)		(1,346	)
Total notes payable – related party	$	45,089		$	49,919

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Leases (Tables)

6 Months Ended

Jun. 30, 2019

Leases [Abstract]

Schedule of operating leases related to the asset classes

(in thousands)	Right-of-Use Assets		Lease Liability
Compressors	$	3,644	$	3,644
Corporate leases		2,378		2,388
Vehicles		924		791
Total	$	6,946	$	6,823

Schedule of gross operating lease costs

(in thousands)	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
Operating lease cost	$	7		$	538
Short-term lease cost		(5	)		156
Total lease cost	$	2		$	694

Schedule of weighted-average lease term and discount rate

	June 30, 2019
Weighted-average lease term (years)		4.0
Weighted-average discount rate		6.36	%

Schedule of supplemental cash flow information related to leases

Cash paid for amounts included in measurement of lease liabilities (in thousands)	Six Months Ended June 30, 2019
Operating cash flows for operating leases	$	1,191

Schedule of undiscounted values and discounted present value

(in thousands)	Amount
Remainder of 2019	$	1,021
2020		1,960
2021		1,902
2022		1,704
2023		1,157
Thereafter		11
Total future minimum lease payments	$	7,755
Less: imputed interest		(932	)
Total lease liabilities	$	6,823

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Revenue (Tables)

6 Months Ended

Jun. 30, 2019

Revenue Recognition and Deferred Revenue [Abstract]

Schedule of disaggregation of revenue

	Appalachian and Illinois Basins				Ventura Basin				Total
	Three Months Ended June 30,				Three Months Ended June 30,				Three Months Ended June 30,
	2019		2018		2019		2018		2019		2018
Natural gas sales	$	13,879	$	3,114	$	337	$	409	$	14,216	$	3,523
Natural gas liquids sales		-		-		195		550		195		550
Oil sales		1,558		2,377		8,344		5,714		9,902		8,091
Transportation and handling		322		-		-		-		322		-
Marketing gas sales		3,221		-		-		-		3,221		-
Total	$	18,980	$	5,491	$	8,876	$	6,673	$	27,856	$	12,164

	Appalachian and Illinois Basins				Ventura Basin				Total
	Six Months Ended June 30,				Six Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018		2019		2018
Natural gas sales	$	32,671	$	6,919	$	861	$	543	$	33,532	$	7,462
Natural gas liquids sales		-		-		441		713		441		713
Oil sales		3,095		2,624		15,796		8,450		18,891		11,074
Transportation and handling		1,056		-		-		-		1,056		-
Marketing gas sales		8,165		-		-		-		8,165		-
Total	$	44,987	$	9,543	$	17,098	$	9,706	$	62,085	$	19,249

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Earnings (Loss) Per Common Share (Tables)

6 Months Ended

Jun. 30, 2019

Earnings Per Share [Abstract]

Schedule of basic and diluted (loss) income per share

	Three months ended June 30,					Six months ended June 30,
(in thousands, except per share amounts)	2019		2018			2019		2018
Net income (loss) attributable to controlling interests before preferred shares	$	6,229	$	(579	)	$	2,129	$	2,989
Less: net income attributable to preferred shares – preferred return		75		-			150		-
Net income (loss) attributable to common stockholders, basic		6,154		(579	)		1,979		2,989
Less: warrant derivative gain		-		-			-		(225	)
Less: beneficial conversion feature		-		(1,125	)		-		(1,125	)
Less: deemed dividend for convertible preferred shares		-		(71	)		-		(71	)
Net income (loss) attributable to common stockholders, diluted		6,154		(1,775	)		1,979		1,568
Weighted-average number of common shares outstanding, basic		7,815		7,693			7,739		7,346
Add dilutive effects of non-vested shares of restricted stock		342		-			342		316
Weighted-average number of common shares outstanding, diluted		8,157		7,693			8,081		7,662
Net income (loss) per common share, basic	$	0.79	$	(0.08	)	$	0.26	$	0.41
Net income (loss) per common share, diluted	$	0.75	$	(0.23	)	$	0.24	$	0.20

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 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
June 30, 2019
Assets:
Commodity derivatives	$	-	$	6,728	$	-	$	6,728
Liabilities:
Commodity derivatives	$	-	$	102	$	-	$	102
December 31, 2018
Asset:
Commodity derivatives	$	-	$	7,022	$	-	$	7,022

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Commodity Derivatives (Tables)

6 Months Ended

Jun. 30, 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		5,925,000	$	2.82		1,129,500	$	2.60 – $3.03
2020		6,433,000	$	2.81		4,128,0000	$	2.40 – $2.75
2021		960,000	$	2.79		2,809,000	$	2.40 – $2.75

	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		125,178	$	53.39		81,493	$	67.01		1,200	$	47.50 - $56.60		21,800	$	47.00 - $75.00
2020		121,147	$	55.37		151,982	$	66.03		23,700	$	47.00 - $60.15		37,400	$	47.00 - $75.00
2021		-	$	-		86,341	$	67.12		33,000	$	47.00 - $60.15		98,000	$	47.00 - $75.00

*	Includes 100% of Carbon California's outstanding derivative hedges at June 30, 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)	June 30, 2019		December 31, 2018
Commodity derivative contracts:
Commodity derivative asset	$	5,146	$	3,517
Commodity derivative asset – non-current	$	1,582	$	3,505
Commodity derivative liability	$	102	$	-

Schedule of realized and unrealized gains and losses

	Three Months Ended June 30,					Six Months Ended June 30,
(in thousands)	2019		2018			2019			2018
Commodity derivative contracts:
Settlement gains (losses)	$	225	$	(674	)	$	(231	)	$	(1,060	)
Unrealized gains (losses)		8,455		(5,348	)		(396	)		(5,587	)
Total settlement and unrealized gains (losses), net	$	8,680	$	(6,022	)	$	(627	)	$	(6,647	)

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

						Net
	Gross					Recognized
	Recognized		Gross			Fair Value
	Assets/		Amounts			Assets/
Balance Sheet Classification (in thousands)	Liabilities		Offset			Liabilities
Commodity derivative assets:
Commodity derivative asset	$	6,176	$	(1,030	)	$	5,146
Commodity derivative asset – non-current		2,792		(1,210	)		1,582
Total derivative assets	$	8,968	$	(2,240	)	$	6,728
Commodity derivative liabilities:
Commodity derivative liability	$	1,132	$	(1,030	)	$	(102	)
Commodity derivative liability – non-current		1,210		(1,210	)		-
Total derivative liabilities	$	2,342	$	(2,240	)	$	(102	)

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Commitments and Contingencies (Tables)

6 Months Ended

Jun. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

Schedule of firm transportation volumes and related demand charges

Period	Dekatherms per day		Demand Charges
Jul 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)

6 Months Ended

Jun. 30, 2019

Supplemental Cash Flow Elements [Abstract]

Schedule of supplemental cash flow disclosures

	Six Months Ended June 30,
(in thousands)	2019		2018
Cash paid during the period for:
Interest	$	4,536	$	909
Non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	39	$	(161	)
Adjustments to OIE Membership Acquisition purchase price	$	1,317	$	-
Increase in asset retirement obligations	$	-	$	3,560
Non-cash acquisition of Carbon California interests	$	-	$	(18,906	)
Carbon California Acquisition on February 1, 2018	$	-	$	17,114
Obligations assumed with Seneca asset purchase	$	-	$	330
Accrued dividend for convertible preferred stock	$	-	$	71
Beneficial conversion feature for convertible preferred stock	$	-	$	1,125
Exercise of warrant derivative	$	-	$	(1,792	)

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Organization (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	May 01, 2018	Feb. 01, 2018	Jan. 31, 2018
Carbon California [Member]
Ownership percentage		53.92%	56.40%	17.81%
OIE Membership [Member]
Business acquisition purchase price	$ 58,100
Prudential [Member] | Carbon California [Member]
Ownership percentage		46.08%

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Summary of Significant Accounting Policies (Details) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2019 USD ($) Partnerships	Dec. 31, 2018
Accounting Policies [Abstract]
Insurance settlement received | $	$ 800
Number of consolidated partnerships | Partnerships	46
Carbon Appalachia [Member]
Accounting Policies [Abstract]
Percentage of ownership interest in the subsidiary		100.00%
Nytis LLC [Member] | Nytis USA [Member]
Accounting Policies [Abstract]
Percentage of ownership interest in the subsidiary		98.10%
Nytis USA [Member]
Accounting Policies [Abstract]
Percentage of ownership interest in the subsidiary		100.00%

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Acquisitions (Details) $ in Thousands	1 Months Ended
	Dec. 31, 2018 USD ($)
Business Acquisition [Line Items]
Old Ironsides Notes	$ 25,100
Old Ironsides [Member]
Business Acquisition [Line Items]
Cash consideration	33,000
Old Ironsides Notes	25,030
Fair value of previously held equity interest	14,158
Fair value of business acquired	$ 72,188

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Acquisitions (Details 1) - OIE Membership Acquisition [Member] $ in Thousands	Jun. 30, 2019 USD ($)
Business Acquisition [Line Items]
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	108,816
Unproved	1,869
Other property, plant and equipment, net	15,626
Other non-current assets	514
Accounts payable and accrued liabilities	(20,466)
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	$ 72,188

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Acquisitions (Details 2) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018
Carbon California [Member]
Business Acquisition [Line Items]
Revenue	$ 8,180	$ 20,283
Net (loss) income before non-controlling interests	(3,013)	4,256
Net loss attributable to non-controlling interests	(3,619)	(2,504)
Net income attributable to controlling interests before preferred shares	$ 607	$ 7,739
Net income per share, basic	$ 0.27	$ 1.01
Net income per share, diluted	$ 0.09	$ 0.84
OIE Membership Acquisition [Member]
Business Acquisition [Line Items]
Revenue	$ 23,682	$ 54,841
Net (loss) income before non-controlling interests	(2,758)	3,046
Net loss attributable to non-controlling interests	(3,619)	(2,505)
Net income attributable to controlling interests before preferred shares	$ 1,687	$ 5,551
Net income per share, basic	$ 0.11	$ 0.76
Net income per share, diluted	$ 0.04	$ 0.54

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Acquisitions (Details Textual) - USD ($) $ in Thousands						1 Months Ended		6 Months Ended		12 Months Ended
	Feb. 01, 2019	Feb. 01, 2018	Nov. 01, 2017	Aug. 15, 2017	Apr. 03, 2017	Dec. 31, 2018	Sep. 29, 2017	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Business Acquisition [Line Items]
Consisting cash paid amount						$ 25,100
Borrowing revolver increased				$ 8,000				$ 4,029	$ 31,502
Old Ironsides [Member]
Business Acquisition [Line Items]
Cash paid to acquired business						33,000
Consisting cash paid amount						25,030
Aggregate cash consideration						14,158
Principal amount	$ 2,000
Bearing interest of per annum								10.00%
Percentage of aggregate share ownership								72.76%
OIE Membership Acquisition [Member]
Business Acquisition [Line Items]
Principal amount								$ 25,100
Class A Units [Member] | Yorktown Energy Partners [Member]
Business Acquisition [Line Items]
Units received			2,940
Carbon California [Member]
Business Acquisition [Line Items]
Percentage of aggregate share ownership		56.40%
Carbon California [Member] | Yorktown [Member] | Class C Units [Member]
Business Acquisition [Line Items]
Profits interest		38.59%
Percentage of aggregate share ownership		46.96%
Issuance shares of our common stock		1,527,778
Carbon Appalachia [Member]
Business Acquisition [Line Items]
Recognized gain based on fair value								1,300
Cash paid to acquired business								33,000
Acquired Old Ironsides Class A Units								$ 58,100
Equity commitment					$ 100,000	$ 37,000				$ 37,000
Aggregate cash consideration				14,000
Borrowing base, revolver				$ 22,000
Carbon Appalachia [Member] | Yorktown Energy Partners [Member]
Business Acquisition [Line Items]
Class of warrants					408,000
Carbon Appalachia [Member] | Class C Units [Member]
Business Acquisition [Line Items]
Acquisitions issuance shares							121
Percentage of aggregate share ownership							27.24%
Carbon Appalachia [Member] | Class A Units [Member]
Business Acquisition [Line Items]
Cash paid to acquired business										33,000
Aggregate cash consideration					$ 12,000		$ 11,000
Senior secured asset-based revolving credit facility					$ 100,000
Term of senior secured asset-based revolving credit facility					4 years
Initial borrowing base amount					$ 10,000
Acquisitions issuance shares							27,195
Acquired of Class A Units										$ 58,100
Percentage of aggregate share ownership							72.76%
Carbon Appalachia [Member] | Class A Units [Member]
Business Acquisition [Line Items]
Acquisitions issuance shares							9,805
Percentage of aggregate share ownership							27.24%
Carbon Appalachia [Member] | Class B Units [Member]
Business Acquisition [Line Items]
Warrant to purchase shares of common stock					1,000
Acquisitions issuance shares							1,000
Percentage of aggregate share ownership							27.24%

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Property and Equipment (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Oil and gas properties:
Proved oil and gas properties	$ 346,654	$ 343,736
Unproved properties not subject to depletion	5,471	5,416
Accumulated depreciation, depletion, amortization and impairment	(102,273)	(95,281)
Net oil and gas properties	249,852	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	6,721	6,649
Accumulated depreciation and amortization	(4,791)	(3,922)
Net other property and equipment	16,766	17,563
Property and equipment, net	$ 266,618	$ 271,434

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Property and Equipment (Details Textual) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Capitalized overhead	$ 305	$ 119	$ 373	$ 190
Depletion expense related to oil and gas properties	3,500	$ 1,800	7,000	$ 3,100
Leasehold costs reclassified into proved property	206		206
Unproved oil and gas properties not subject to depletion	$ 5,471		$ 5,471		$ 5,416

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Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018	Jun. 30, 2018
Payables and Accruals [Abstract]
Accounts payable	$ 4,982	$ 7,670
Oil and gas revenue suspense	3,123	2,675
Gathering and transportation payables	1,788	1,774
Production taxes payable	2,520	1,860
Accrued operating costs	875	3,155
Accrued ad valorem taxes - current	6,104	3,474
Accrued general and administrative expenses	1,750	3,111
Accrued asset retirement obligation - current	3,708	3,099	$ 769
Accrued interest	1,513	955
Accrued gas purchases	2,912	5,440
Other liabilities	1,222	1,603
Total accounts payable and accrued liabilities	$ 30,497	$ 34,816

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Asset Retirement Obligation (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Asset Retirement Obligation [Abstract]
Balance at beginning of period			$ 22,310	$ 7,737
Accretion expense	$ 405	$ 162	799	303
Additions during period				3,560
Balance at end of period	23,109	11,600	23,109	11,600
Less: Current portion	(3,708)	(769)	(3,708)	(769)	$ (3,099)
Non-current portion	$ 19,401	$ 10,831	$ 19,401	$ 10,831	$ 19,211

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Credit Facilities and Notes Payable (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Credit Facility Term Note [Member]
Debt Instrument [Line Items]
Total debt	$ 10,833	$ 15,000
Old Ironsides Note [Member]
Debt Instrument [Line Items]
Total debt	24,232	25,065
2018 Credit Facility-revolver [Member]
Debt Instrument [Line Items]
Total debt	71,150	69,150
Credit Facilities [Member]
Debt Instrument [Line Items]
Other debt	69	57
Total debt	106,284	109,272
Less: unamortized debt discount	(90)	(134)
Total credit facilities and notes payable	106,194	109,138
Current portion of credit facilities and notes payable	(9,910)	(11,910)
Non-current debt, net of current portion and unamortized debt discount	$ 96,284	$ 97,228

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Credit Facilities and Notes Payable (Details 1) - Prudential [Member] - Carbon California [Member] - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Total principal	$ 46,500	$ 51,500
Less: Deferred notes costs	(196)	(235)
Less: unamortized debt discount	(1,215)	(1,346)
Total notes payable - related party	45,089	49,919
Senior Revolving Notes [Member]
Debt Instrument [Line Items]
Total principal	33,500	38,500
Subordinated Notes [Member]
Debt Instrument [Line Items]
Total principal	$ 13,000	$ 13,000

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Credit Facilities and Notes Payable (Details Textual) $ in Thousands				3 Months Ended	6 Months Ended
	Feb. 01, 2019 USD ($)	Dec. 31, 2018 USD ($)	Aug. 15, 2017 USD ($)	Jun. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)	Jun. 30, 2018 USD ($)
Credit Facilities and Notes Payable (Textual)
Senior secured asset-based revolving credit facility			$ 8,000		$ 4,029	$ 31,502
Amortization of deferred issuance costs					405	247
Paid in kind interest					1,244
One-time principal reduction payment					$ 13,185	$ 14
Carbon Appalachia [Member]
Credit Facilities and Notes Payable (Textual)
Credit facility			$ 22,000
Old Ironsides Note [Member] | Carbon Appalachia [Member]
Credit Facilities and Notes Payable (Textual)
Bank credit facility, terms		5 years
Amount of unsecured notes issuance		$ 25,100
Interest rate (as a percent)		10.00%
Number of monthly installments					24
One-time principal reduction payment	$ 2,000
Old Ironsides Note [Member] | Carbon Appalachia [Member] | Payment in Kind (PIK) Note [Member]
Credit Facilities and Notes Payable (Textual)
Interest rate (as a percent)				12.00%	12.00%
Paid in kind interest					$ 1,200
2018 Credit Facility [Member] | Carbon Appalachia [Member]
Credit Facilities and Notes Payable (Textual)
Unamortized deferred issuance costs				$ 564	564
Unamortized debt discount, term note				90	90
Senior secured asset-based revolving credit facility					$ 500
Commitment fee (as a percent)					0.50%
Origination fee (as a percent)					0.50%
Credit facility				75,000	$ 75,000
Additional borrowing capacity available				3,800	$ 3,800
Debt Instrument, covenant, ratio of debt to EBITDAX					3.5
Debt Instrument, covenant, current ratio					1.0
Credit facility-revolver outstanding				71,200	$ 71,200
Amortization of deferred issuance costs				$ 63	125
Revolving credit facility maturing date				Dec. 31, 2022
Cash and cash equivalents of borrowers not to exceed				$ 3,000	3,000
Debt issuance costs paid, revolver and term loan				779	779
Debt issuance costs paid, term loan				134	134
Term loan				$ 15,000	$ 15,000
Interest rate (as a percent)				6.25%	6.25%
Number of monthly installments					18
2018 Credit Facility [Member] | Carbon Appalachia [Member] | Minimum [Member] | Base rate [Member]
Credit Facilities and Notes Payable (Textual)
Spread on variable base rate (as a percent)					0.25%
2018 Credit Facility [Member] | Carbon Appalachia [Member] | Minimum [Member] | London interbank offered rate [Member]
Credit Facilities and Notes Payable (Textual)
Spread on variable base rate (as a percent)					2.75%
2018 Credit Facility [Member] | Carbon Appalachia [Member] | Maximum [Member] | Base rate [Member]
Credit Facilities and Notes Payable (Textual)
Spread on variable base rate (as a percent)					0.75%
2018 Credit Facility [Member] | Carbon Appalachia [Member] | Maximum [Member] | London interbank offered rate [Member]
Credit Facilities and Notes Payable (Textual)
Spread on variable base rate (as a percent)					3.75%

XML

Credit Facilities and Notes Payable (Details Textual 1) $ in Thousands			1 Months Ended	3 Months Ended		6 Months Ended
	May 01, 2018 USD ($) shares	Feb. 15, 2017 USD ($) shares	Feb. 15, 2017 USD ($) shares	Jun. 30, 2019 USD ($)	Jun. 30, 2018	Jun. 30, 2019 USD ($)	Jun. 30, 2018 USD ($)
Credit Facilities and Notes Payable (Textual)
Amortization of deferred issuance costs						$ 405	$ 247
Prudential [Member] | Carbon California [Member] | Senior Revolving Notes [Member]
Credit Facilities and Notes Payable (Textual)
Initial revolving borrowing capacity		$ 25,000	$ 25,000
Notes maturity date			Feb. 15, 2022
Borrowing base amount				$ 45,000		45,000
Outstanding borrowings						$ 33,500
Effective borrowing rate				7.60%		7.60%
Commitment fee (as a percent)			0.50%
Annual administrative fee payable		75	$ 75
Percentage of production hedged by commodity derivatives, year one			75.00%
Percentage of production hedged by commodity derivatives, year two			65.00%
Percentage of production hedged by commodity derivatives, year three			50.00%
Principal payments in minimum installments			$ 500
Current portion of fees		$ 935	935
Amortization of deferred issuance costs				$ 79		$ 153
Proceeds from debt			$ 10,000
Debt instrument, covenant, debt to EBITDA ratio				1.6	4.0	3.0
Debt instrument, covenant, senior revolving notes to EBITDA ratio		2.5
Debt instrument, covenant, interest coverage ratio		1.0		1.0	1.0	1.0
Prudential [Member] | Carbon California [Member] | Senior Revolving Notes [Member] | LIBOR [Member]
Credit Facilities and Notes Payable (Textual)
Effective borrowing rate		5.50%	5.50%
Prudential [Member] | Carbon California [Member] | Senior Revolving Notes [Member] | Prime Rate [Member]
Credit Facilities and Notes Payable (Textual)
Effective borrowing rate		4.50%	4.50%
Prudential [Member] | Carbon California [Member] | Subordinated Notes [Member]
Credit Facilities and Notes Payable (Textual)
Notes maturity date			Feb. 15, 2024
Principal outstanding		$ 10,000	$ 10,000
Percentage of production hedged by commodity derivatives, year one			67.50%
Percentage of production hedged by commodity derivatives, year two			58.50%
Percentage of production hedged by commodity derivatives, year three			45.00%
Amortization of debt discount				$ 45		$ 89
Interest rate (as a percent)		12.00%	12.00%
Number of common units issued | shares		1,425	1,425
Increase in sharing percentage by noncontroling interest		5.00%	5.00%
Fair value per Class A unit		$ 1,000	$ 1,000
Fair value of debt discount			$ 1,300
Outstanding discount amount of notes				824		824
Principal prepayment allowed (as a percent)			100.00%
Prepayment fee (as a percent)			3.00%
Debt instrument, covenant, debt to EBITDA ratio		4.5			4.0
Debt instrument, covenant, subordinated notes to EBITDA ratio		3.0
Debt instrument, covenant, interest coverage ratio		2.5
Debt instrument, covenant, current ratio		0.85
Percentage of adjusted PV-10 not to exceed indebtedness		65.00%
Prudential [Member] | Carbon California [Member] | 2018 Subordinated Notes [Member]
Credit Facilities and Notes Payable (Textual)
Notes maturity date	Feb. 17, 2024
Principal outstanding				3,000		3,000
Percentage of production hedged by commodity derivatives, year one	67.50%
Percentage of production hedged by commodity derivatives, year two	58.50%
Percentage of production hedged by commodity derivatives, year three	45.00%
Amortization of debt discount				21		42
Interest rate (as a percent)	12.00%
Number of common units issued | shares	585
Increase in sharing percentage by noncontroling interest	2.00%
Fair value per Class A unit	$ 1,000
Fair value of debt discount	490
Outstanding discount amount of notes				$ 391		$ 391
Proceeds from debt	$ 3,000
Principal prepayment allowed (as a percent)	100.00%
Prepayment fee (as a percent)	3.00%

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Leases (Details) $ in Thousands	Jun. 30, 2019 USD ($)
Operating Leased Assets [Line Items]
Right-of-use Asset	$ 6,946
Lease Liability	6,823
Compressors [Member]
Operating Leased Assets [Line Items]
Right-of-use Asset	3,644
Lease Liability	3,644
Corporate leases [Member]
Operating Leased Assets [Line Items]
Right-of-use Asset	2,378
Lease Liability	2,388
Vehicles [Member]
Operating Leased Assets [Line Items]
Right-of-use Asset	924
Lease Liability	$ 791

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Leases (Details 1) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Leases [Abstract]
Operating lease cost	$ 7	$ 538
Short-term lease cost	(5)	156
Total lease cost	$ 2	$ 694

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Leases (Details 2)	Jun. 30, 2019
Leases [Abstract]
Weighted-average lease term (years)	4 years
Weighted-average discount rate	6.36%

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Leases (Details 3) $ in Thousands	6 Months Ended
	Jun. 30, 2019 USD ($)
Cash paid for amounts included in measurement of lease liabilities:
Operating cash flows for operating leases	$ 1,191

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Leases (Details 4) $ in Thousands	Jun. 30, 2019 USD ($)
Leases [Abstract]
Remainder of 2019	$ 1,021
2020	1,960
2021	1,902
2022	1,704
2023	1,157
Thereafter	11
Total future minimum lease payments	7,755
Less: imputed interest	(932)
Total lease liabilities	$ 6,823

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Leases (Details Textual) - USD ($) $ in Thousands	Jun. 30, 2019	Jan. 01, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right-of-use lease liabilities	$ 6,823
Right-of-use assets and liabilities discounted present value	6,946
Accounting Standards Update 2016-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right-of-use lease liabilities		$ 7,700
Right-of-use assets and liabilities discounted present value	$ 6,500	$ 7,700

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Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Disaggregation of Revenue [Line Items]
Total	$ 36,841	$ 6,148	$ 62,155	$ 12,621
Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Total	14,216	3,523	33,532	7,462
Natural gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Total	195	550	441	713
Oil sales [Member]
Disaggregation of Revenue [Line Items]
Total	9,902	8,091	18,891	11,074
Transportation and handling [Member]
Disaggregation of Revenue [Line Items]
Total	322		1,056
Marketing gas sales [Member]
Disaggregation of Revenue [Line Items]
Total	3,221		8,165
Appalachian and Illinois Basins [Member]
Disaggregation of Revenue [Line Items]
Total	18,980	5,491	44,987	9,543
Appalachian and Illinois Basins [Member] | Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Total	13,879	3,114	32,671	6,919
Appalachian and Illinois Basins [Member] | Natural gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Total
Appalachian and Illinois Basins [Member] | Oil sales [Member]
Disaggregation of Revenue [Line Items]
Total	1,558	2,377	3,095	2,624
Appalachian and Illinois Basins [Member] | Transportation and handling [Member]
Disaggregation of Revenue [Line Items]
Total	322		1,056
Appalachian and Illinois Basins [Member] | Marketing gas sales [Member]
Disaggregation of Revenue [Line Items]
Total	3,221		8,165
Ventura Basin [Member]
Disaggregation of Revenue [Line Items]
Total	8,876	6,673	17,098	9,706
Ventura Basin [Member] | Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Total	337	409	861	543
Ventura Basin [Member] | Natural gas liquids sales [Member]
Disaggregation of Revenue [Line Items]
Total	195	550	441	713
Ventura Basin [Member] | Oil sales [Member]
Disaggregation of Revenue [Line Items]
Total	8,344	5,714	15,796	8,450
Ventura Basin [Member] | Transportation and handling [Member]
Disaggregation of Revenue [Line Items]
Total
Ventura Basin [Member] | Marketing gas sales [Member]
Disaggregation of Revenue [Line Items]
Total

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Stock-Based Compensation Plans (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017
Share-based Arrangements with Employees and Nonemployees [Abstract]
Issuance of common stock shares	1,600,000		1,600,000
Restricted Stock [Member]
Share-based Arrangements with Employees and Nonemployees [Abstract]
Granted (in shares)			748,000
Vested (in shares)			65,000
Compensation costs	$ 224	$ 190	$ 403	$ 348
Unrecognized compensation costs	1,900		$ 1,900
Compensation recognized period			6 years 9 months 18 days
Restricted Performance Units [Member]
Share-based Arrangements with Employees and Nonemployees [Abstract]
Granted (in shares)			699,000
Vested (in shares)			95,000
Compensation costs			$ 43	$ 135
Performance units fair value			$ 10.00		$ 9.80	$ 7.20
Unrecognized compensation costs	$ 3,800		$ 3,800

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Earnings (Loss) Per Common Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Earnings Per Share [Abstract]
Net income (loss) attributable to controlling interests before preferred shares	$ 6,229	$ (579)	$ 2,129	$ 2,989
Less: net income attributable to preferred shares - preferred return	75		150
Net income (loss) attributable to common stockholders, basic	6,154	(579)	1,979	2,989
Less: warrant derivative gain				(225)
Less: beneficial conversion feature		(1,125)		(1,125)
Less: deemed dividend for convertible preferred shares		(71)		(71)
Net income (loss) attributable to common stockholders, diluted	$ 6,154	$ (1,775)	$ 1,979	$ 1,568
Weighted-average number of common shares outstanding, basic	7,815	7,693	7,739	7,346
Add dilutive effects of non-vested shares of restricted stock	$ 342		$ 342	$ 316
Weighted-average number of common shares outstanding, diluted	8,157	7,693	8,081	7,662
Net income (loss) per common share, basic	$ 0.79	$ (0.08)	$ 0.26	$ 0.41
Net income (loss) per common share, diluted	$ 0.75	$ (0.23)	$ 0.24	$ 0.20

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Earnings (Loss) Per Common Share (Details Textual) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Issuance of preferred stock, value	$ 1		$ 1		$ 1
Issuance of preferred stock, shares	50,000		50,000		50,000
Preferred return	$ 374,000		$ 374,000		$ 224,000
Additional paid-in capital
Anti-dilutive excluded from computation of diluted earnings per share	276,000	598,000	276,000	282,000
Series B Convertible Preferred Stock [Member] | Yorktown [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Issuance of preferred stock, value	$ 5,000		$ 5,000
Issuance of preferred stock, shares	50,000		50,000
Conversion price, per share	$ 8.00		$ 8.00
Annual per share dividend rate			6.00%
Issue price, per share	$ 100		$ 100
Preferred return	$ 374		$ 374
Additional paid-in capital			$ 1,100
Convertible preferred stock shares issued upon conversion	12.5		12.5
Preferred stock, conversion ratio, stock price trigger			15.00%
Preferred stock, increase in liquidation preference			$ 150

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Fair Value Measurements (Details) - Fair Value Measurements [Member] - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Asset:
Commodity derivatives	$ 6,728	$ 7,022
Liabilities:
Commodity derivatives	102
Level 1 [Member]
Asset:
Commodity derivatives
Liabilities:
Commodity derivatives
Level 2 [Member]
Asset:
Commodity derivatives	6,728	7,022
Liabilities:
Commodity derivatives	102
Level 3 [Member]
Asset:
Commodity derivatives
Liabilities:
Commodity derivatives

XML

Fair Value Measurements (Details Textual) - Fair Value, Inputs, Level 3 [Member] - Non-Recurring [Member] $ in Thousands	6 Months Ended
	Jun. 30, 2019 USD ($) shares
Minimum [Member]
Fair Value Measurements (Textual)
Costs of abandonment	$ 20
Minimum [Member] | Risk-free rate [Member]
Fair Value Measurements (Textual)
Risk free Rate	3.28%
Minimum [Member] | Asset retirement obligation, measurement input [Member] | Inflation rate [Member]
Fair Value Measurements (Textual)
Inflation rate	1.52%
Minimum [Member] | Reclamation Period [Member]
Fair Value Measurements (Textual)
Estimated timing of reclamation range (in years)	1 year
Maximum [Member] | Asset retirement obligation, measurement input [Member]
Fair Value Measurements (Textual)
Costs of abandonment	$ 45
Maximum [Member] | Asset retirement obligation, measurement input [Member] | Inflation rate [Member]
Fair Value Measurements (Textual)
Estimated timing of reclamation range (in years)	75 years
Inflation rate	2.79%
Maximum [Member] | Asset retirement obligation, measurement input [Member] | Risk-free rate [Member]
Fair Value Measurements (Textual)
Risk free Rate	8.27%
Class A Units [Member] | 2018 Subordinated Notes [Member]
Fair Value Measurements (Textual)
Number of common units issued | shares	585
Fair value of debt discount	$ 490
Class A Units [Member] | Subordinated Notes [Member]
Fair Value Measurements (Textual)
Number of common units issued | shares	1,425
Fair value of debt discount	$ 1,300
Fair value per Class A unit	$ 1,000

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Commodity Derivatives (Details) - Carbon California [Member]	6 Months Ended
	Jun. 30, 2019 bbl MMBTU $ / MMBTU $ / bbl
2019 [Member] | Natural Gas Swaps [Member] | MMBtu [Member]
Derivative agreements details:
Crude oil, notional amount (in MMBtu) | MMBTU	5,925,000	[1]
Weighted Average Price | $ / MMBTU	2.82	[1]
2019 [Member] | Natural Gas Collars [Member] | MMBtu [Member]
Derivative agreements details:
Crude oil, notional amount (in MMBtu) | MMBTU	1,129,500	[1]
2019 [Member] | Natural Gas Collars [Member] | Minimum [Member] | MMBtu [Member]
Derivative agreements details:
Weighted Average Price | $ / MMBTU	2.60	[1]
2019 [Member] | Natural Gas Collars [Member] | Maximum [Member] | MMBtu [Member]
Derivative agreements details:
Weighted Average Price | $ / MMBTU	3.03	[1]
2019 [Member] | Oil Swaps [Member] | WTI Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	125,178	[2]
Weighted Average Price | $ / bbl	53.39	[2],[3]
2019 [Member] | Oil Swaps [Member] | Brent Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	81,493	[2]
Weighted Average Price | $ / bbl	67.01	[2],[4]
2019 [Member] | Oil Collars [Member] | WTI Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	1,200	[2]
2019 [Member] | Oil Collars [Member] | Brent Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	21,800	[2]
2019 [Member] | Oil Collars [Member] | Minimum [Member] | WTI Bbl [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	47.50	[2],[3]
2019 [Member] | Oil Collars [Member] | Minimum [Member] | Brent Bbl [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	47.00	[2],[4]
2019 [Member] | Oil Collars [Member] | Maximum [Member] | WTI Bbl [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	56.60	[2],[3]
2019 [Member] | Oil Collars [Member] | Maximum [Member] | Brent Bbl [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	75.00	[2],[4]
2020 [Member] | Natural Gas Swaps [Member] | MMBtu [Member]
Derivative agreements details:
Crude oil, notional amount (in MMBtu) | MMBTU	6,433,000	[1]
Weighted Average Price | $ / MMBTU	2.81	[1]
2020 [Member] | Natural Gas Collars [Member] | MMBtu [Member]
Derivative agreements details:
Crude oil, notional amount (in MMBtu) | MMBTU	4,128,000	[1]
2020 [Member] | Natural Gas Collars [Member] | Minimum [Member] | MMBtu [Member]
Derivative agreements details:
Weighted Average Price | $ / MMBTU	2.40	[1]
2020 [Member] | Natural Gas Collars [Member] | Maximum [Member] | MMBtu [Member]
Derivative agreements details:
Weighted Average Price | $ / MMBTU	2.75	[1]
2020 [Member] | Oil Swaps [Member] | WTI Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	121,147	[2]
Weighted Average Price | $ / bbl	55.37	[2],[3]
2020 [Member] | Oil Swaps [Member] | Brent Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	151,982	[2]
Weighted Average Price | $ / bbl	66.03	[2],[4]
2020 [Member] | Oil Collars [Member] | WTI Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	23,700	[2]
2020 [Member] | Oil Collars [Member] | Brent Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	37,400	[2]
2020 [Member] | Oil Collars [Member] | Minimum [Member] | WTI Bbl [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	47.00	[2],[3]
2020 [Member] | Oil Collars [Member] | Minimum [Member] | Brent Bbl [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	47.00	[2],[4]
2020 [Member] | Oil Collars [Member] | Maximum [Member] | WTI Bbl [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	60.15	[2],[3]
2020 [Member] | Oil Collars [Member] | Maximum [Member] | Brent Bbl [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	75.00	[2],[4]
2021 [Member] | Natural Gas Swaps [Member] | MMBtu [Member]
Derivative agreements details:
Crude oil, notional amount (in MMBtu) | MMBTU	960,000	[1]
Weighted Average Price | $ / MMBTU	2.79	[1]
2021 [Member] | Natural Gas Collars [Member] | MMBtu [Member]
Derivative agreements details:
Crude oil, notional amount (in MMBtu) | MMBTU	2,809,000	[1]
2021 [Member] | Natural Gas Collars [Member] | Minimum [Member] | MMBtu [Member]
Derivative agreements details:
Weighted Average Price | $ / MMBTU	2.40	[1]
2021 [Member] | Natural Gas Collars [Member] | Maximum [Member] | MMBtu [Member]
Derivative agreements details:
Weighted Average Price | $ / MMBTU	2.75	[1]
2021 [Member] | Oil Swaps [Member] | WTI Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl		[2]
Weighted Average Price | $ / bbl		[2],[3]
2021 [Member] | Oil Swaps [Member] | Brent Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	86,341	[2]
Weighted Average Price | $ / bbl	67.12	[2],[4]
2021 [Member] | Oil Collars [Member] | WTI Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	33,000	[2]
2021 [Member] | Oil Collars [Member] | Brent Bbl [Member]
Derivative agreements details:
Crude oil, notional amount (in Bbl) | bbl	98,000	[2]
2021 [Member] | Oil Collars [Member] | Minimum [Member] | WTI Bbl [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	47.00	[2],[3]
2021 [Member] | Oil Collars [Member] | Minimum [Member] | Brent Bbl [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	47.00	[2],[4]
2021 [Member] | Oil Collars [Member] | Maximum [Member] | WTI Bbl [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	60.15	[2],[3]
2021 [Member] | Oil Collars [Member] | Maximum [Member] | Brent Bbl [Member]
Derivative agreements details:
Weighted Average Price | $ / bbl	75.00	[2],[4]

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

[2] Includes 100% of Carbon California's outstanding derivative hedges at June 30, 2019, and not our proportionate share.

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

[4] Brent future contracts for the respective period.

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Commodity Derivatives (Details 1) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Commodity derivative contracts:
Commodity derivative asset	$ 5,146	$ 3,517
Commodity derivative asset - non-current	1,582	3,505
Commodity derivative liability	$ 102

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Commodity Derivatives (Details 2) - Commodity derivative contracts [Member] - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Settlement gains (losses)	$ 225	$ (674)	$ (231)	$ (1,060)
Unrealized gains (losses)	8,455	(5,348)	(396)	(5,587)
Total settlement and unrealized gains (losses), net	$ 8,680	$ (6,022)	$ (627)	$ (6,647)

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Commodity Derivatives (Details 3) $ in Thousands	Jun. 30, 2019 USD ($)
Commodity derivative asset - current [Member]
Derivatives, Fair Value [Line Items]
Gross Recognized Assets	$ 6,176
Gross Amounts Offset	(1,030)
Net Recognized Fair Value Assets	5,146
Commodity derivative asset - non-current [Member]
Derivatives, Fair Value [Line Items]
Gross Recognized Assets	2,792
Gross Amounts Offset	(1,210)
Net Recognized Fair Value Assets	1,582
Total derivative assets [Member]
Derivatives, Fair Value [Line Items]
Gross Recognized Assets	8,968
Gross Amounts Offset	(2,240)
Net Recognized Fair Value Assets	6,728
Commodity derivative liability - current [Member]
Derivatives, Fair Value [Line Items]
Gross Recognized Liabilities	1,132
Gross Amounts Offset	(1,030)
Net Recognized Fair Value Liabilities	(102)
Commodity derivative liability - non-current [Member]
Derivatives, Fair Value [Line Items]
Gross Recognized Liabilities	1,210
Gross Amounts Offset	(1,210)
Net Recognized Fair Value Liabilities
Total derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Gross Recognized Liabilities	2,342
Gross Amounts Offset	(2,240)
Net Recognized Fair Value Liabilities	$ (102)

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Commitments and Contingencies (Details) - Transportation Commitments [Member]	6 Months Ended
	Jun. 30, 2019 $ / shares Dekatherms
Jul 2019 - Mar 2020 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Dekatherms	58,871
Jul 2019 - Mar 2020 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.20
Jul 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) | Dekatherms	57,791
Apr 2020 - May 2020 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.20
Apr 2020 - May 2020 [Member] | Maximum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.56
Jun 2020 - Oct 2020 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Dekatherms	56,641
Jun 2020 - Oct 2020 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.20
Jun 2020 - Oct 2020 [Member] | Maximum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.56
Nov 2020 - Aug 2022 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Dekatherms	50,341
Nov 2020 - Aug 2022 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.20
Nov 2020 - Aug 2022 [Member] | Maximum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.56
Sep 2022 - May 2027 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Dekatherms	30,990
Sep 2022 - May 2027 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.20
Sep 2022 - May 2027 [Member] | Maximum [Member]
Other Commitments [Line Items]
Demand Charges (in dollars per dekatherm)	0.21
Jun 2027 - May 2036 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Dekatherms	1,000
Demand Charges (in dollars per dekatherm)	0.20

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Commitments and Contingencies (Details Textual)	6 Months Ended
	Jun. 30, 2019 USD ($) $ / Mcf Mcf
Commitments and Contingencies Disclosure [Abstract]
Firm transportation contract obligations, current and non-current	$ 16,700,000
Natural gas processing agreement initial term	5 years
Natural gas processing agreement extension period	5 years
Annual demand charges for volume commitments	$ 1,800,000
Minimum annual volume commitment | Mcf	720
Natural gas processing fee | $ / Mcf	2.5

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Supplemental Cash Flow Disclosure (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Cash paid during the period for:
Interest			$ 4,536	$ 909
Non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities			39	(161)
Adjustments to OIE Membership Acquisition purchase price			1,317
Increase in asset retirement obligations				3,560
Non-cash acquisition of Carbon California interests				(18,906)
Carbon California Acquisition on February 1, 2018				17,114
Obligations assumed with Seneca asset purchase				330
Accrued dividend for convertible preferred stock				71
Beneficial conversion feature for convertible preferred stock		$ 1,125		1,125
Exercise of warrant derivative				$ (1,792)