UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended ~~March~~June 3130, 2020

☐ 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 ~~May~~August 7, 2020, ~~there~~ there were 78,~~949~~304,~~128~~781 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	2217
Item 3. Quantitative and Qualitative Disclosures About Market Risk	3231
Item 4. Controls and Procedures	3231
Part II – OTHER INFORMATION
Item 1. Legal Proceedings	3332
Item 1A. Risk Factors	3332
Item 6. Exhibits	4037
Signatures	4138

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

CARBON ENERGY CORPORATION

Condensed Consolidated Balance Sheets

(in thousands, except share amounts)

	March 31, 2020			December 31, 2019
	June 30, 2020			December 31, 2019
ASSETS
Current assets:
Cash and cash equivalents	$	1,~~740~~311		$	904
Restricted cash (Note 3)		4,612			-
Accounts receivable:
Revenue		101,~~331~~846			12,886
Joint interest billings and other		~~1,583~~415			1,552
Commodity derivative asset (Note 12)		18,078			5,915
Commodity derivative asset (Note 13)		6,129			5,915
Prepaid expenses, deposits, and other current assets		21,~~352~~403			2,500
Inventory		~~1,943~~491			2,512
Total current assets		3616,~~027~~207			26,269
Non-current assets:
Property and equipment (Note 3)
Property and equipment (Note 4)
Oil and gas properties, full cost method of accounting:
Proved, net		~~239~~114,~~842~~095			242,144
Unproved		41,~~906~~616			4,872
Other property and equipment, net		151,~~768~~189			15,984
Total property and equipment, net		~~260~~116,~~516~~900			263,000
Investments in affiliates		67			625
Commodity derivative asset – non-current (Note 12)		5,107			1,164
Commodity derivative asset – non-current (Note 13)		2,871			1,164
Right-of-use assets		51,~~689~~949			6,104
Other non-current assets		~~980~~2,276			1,092
Total non-current assets		~~272~~124,~~359~~063			271,985
Total assets	$	~~308~~140,~~386~~270		$	298,254
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities (Note 4)	$	30,280		$	35,157
Accounts payable and accrued liabilities (Note 5)	$	12,500		$	35,157
Firm transportation contract obligations (Note 13)		5,571			5,679
Firm transportation contract obligations (Note 14)		-			5,679
Lease liability – current		~~1,638~~696			1,625
Commodity derivative liability (Note 12)		-			469
Commodity derivative liability (Note 13)		-			469
Credit facilities and notes payable (Note 6)		3,311			5,788
Credit facilities and notes payable (Note 7)		1,339			5,788
Total current liabilities		4014,~~800~~535			48,718
Non-current liabilities:
Firm transportation contract obligations (Note 13)		8,049			8,905
Firm transportation contract obligations (Note 14)		-			8,905
Lease liability – non-current		31,~~966~~179			4,383
Commodity derivative liability – non-current (Note 12)		25			87
Commodity derivative liability – non-current (Note 13)		-			87
Production and property taxes payable		~~3,173~~-			2,815
Asset retirement obligations (Note 5)		17,456			17,514
Asset retirement obligations (Note 6)		5,908			17,514
Credit facilities and notes payable (Note 6)		96,520			94,870
Credit facilities and notes payable (Note 7)		15,862			94,870
Notes payable – related party (Note 6)		46,517			44,741
Notes payable – related party (Note 7)		49,484			44,741
Total non-current liabilities		~~175~~72,~~706~~433			173,315
Commitments and contingencies (Note 13)
Commitments and contingencies (Note 14)
Stockholders’ equity:
Preferred stock, $0.01 par value; liquidation preference of $599 and $524 at March 31, 2020 and December 31, 2019, respectively; authorized 1,000,000 shares, 50,000 shares issued and outstanding at March 31, 2020 and December 31, 2019		1			1
Preferred stock, $0.01 par value; liquidation preference of $674 and $524 at June 30, 2020 and December 31, 2019, respectively; authorized 1,000,000 shares, 50,000 shares issued and outstanding at June 30, 2020 and December 31, 2019		1			1
Common stock, $0.01 par value; authorized 35,000,000 shares, 7,899,020 and 7,796,085 shares issued and outstanding at March 31, 2020 and December 31, 2019, respectively		79			78
Common stock, $0.01 par value; authorized 35,000,000 shares, 8,304,781 and 7,796,085 shares issued and outstanding at June 30, 2020 and December 31, 2019, respectively		83			78
Additional paid-in capital		8689,~~037~~148			85,834
Accumulated deficit		(2663,~~043~~559	)		(35,842	)
Total Carbon stockholders’ equity		6025,~~074~~673			50,071
Non-controlling interests		3127,~~806~~629			26,150
Total stockholders’ equity		9153,~~880~~302			76,221
Total liabilities and stockholders’ equity	$	~~308~~140,~~386~~270		$	298,254

See accompanying notes to Condensed Consolidated Financial Statements.

CARBON ENERGY CORPORATION

Condensed Consolidated Statements of Operations

(Unaudited)

	Three Months Ended March 31,
	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands, except per share amounts)	2020			2019			2020			2019
Revenue:
Natural gas sales	$	84,~~434~~138		$	1914,~~316~~216		$	12,572		$	33,532
Natural gas liquids		~~152~~49			~~247~~195			201			441
Oil sales		73,~~216~~767			89,~~989~~902			10,982			18,891
Transportation and handling		~~633~~274			~~734~~322			908			1,056
Marketing gas sales		62,~~318~~380			43,~~944~~221			8,698			8,165
Commodity derivative gain (loss)		19,714			(9,306	)
Commodity derivative (loss) gain		(5,647	)		8,680			14,067			(627	)
Other (loss) income		(2	)		26
Other income		2			305			-			697
Total revenue		424,~~465~~963			2436,~~950~~841			47,428			62,155
Expenses:
Lease operating expenses		75,~~372~~086			67,~~616~~480			12,458			14,095
Pipeline operating expenses		21,~~692~~432			32,~~085~~950			4,125			6,035
Transportation and gathering costs		21,~~576~~475			1,~~669~~130			4,052			2,799
Production and property taxes		101,136			21,~~010~~666			1,146			3,676
Marketing gas purchases		31,~~472~~329			64,~~302~~795			4,801			11,097
General and administrative		35,~~303~~402			43,~~689~~947			8,702			8,636
Depreciation, depletion and amortization		32,~~811~~149			3,~~980~~881			5,960			7,860
Accretion of asset retirement obligations		~~478~~299			~~394~~405			777			799
Total expenses		23,714			28,745
Loss on Appalachia Divestiture		34,463			-			34,463			-
Operating income (loss)		18,751			(3,795	)
Total expenses		52,771			26,254			76,484			54,997
Other income (expense):
Operating (loss) income		(47,808	)		10,587			(29,056	)		7,158
Interest expense		(2,872	)		(2,914	)
Other income (expense):
Investments in affiliates		(421	)		19
Interest expense, net		(2,774	)		(3,445	)		(5,647	)		(6,725	)
Total other expense		(3,293	)		(2,895	)
Investments in affiliates		-			21			(421	)		40
Income (loss) before income taxes		15,458			(6,690	)
Other income		104			-			104			-
Provision for income taxes		-			-
Total expense		(2,670	)		(3,424	)		(5,964	)		(6,685	)
Net income (loss) before non-controlling interests and preferred shares		15,458			(6,690	)
(Loss) income before income taxes		(50,478	)		7,163			(35,020	)		473
Net income (loss) attributable to non-controlling interests		5,659			(2,590	)
Provision for income taxes		-			-			-			-
Net income (loss) attributable to controlling interests before preferred shares		9,799			(4,100	)
Net (loss) income before non-controlling interests and preferred shares		(50,478	)		7,163			(35,020	)		473
Net income attributable to preferred shares – preferred return		75			75
Net (loss) income attributable to non-controlling interests		(2,542	)		934			3,117			(1,656	)
Net income (loss) attributable to common shares	$	9,724		$	(4,175	)
Net (loss) income attributable to controlling interests before preferred shares		(47,936	)		6,229			(38,137	)		2,129
Net income (loss) per common share:
Net income attributable to preferred shares – preferred return		75			75			150			150
Basic	$	1.25		$	(0.54	)
Net (loss) income attributable to common shares	$	(48,011	)	$	6,154		$	(38,287	)	$	1,979
Diluted	$	1.20		$	(0.54	)
Net (loss) income per common share:
Weighted average common shares outstanding:
Basic	$	(5.91	)	$	0.79		$	(4.81	)	$	0.26
Basic		7,809			7,663
Diluted	$	(5.91	)	$	0.75		$	(4.81	)	$	0.24
Diluted		8,090			7,663
Weighted average common shares outstanding:
Basic		8,118			7,815			7,964			7,739
Diluted		8,118			8,157			7,964			8,081

See accompanying notes to Condensed Consolidated Financial Statements.

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, 2019		7,796		$	78			50	$	1	$	85,834		$	26,150		$	(35,842	)	$	76,221
Stock-based compensation		-			-			-		-		204			-			-			204
Restricted stock vested		20			-			-		-		-			-			-			-
Performance units vested		83			1			-		-		(1	)		-			-			-
Non-controlling interests’ distributions, net		-			-			-		-		-			(3	)		-			(3	)
Net income		-			-			-		-		-			5,659			9,799			15,458
Balance as of March 31, 2020		7,899		$	79			50	$	1	$	86,037		$	31,806		$	(26,043	)	$	91,880
Stock-based compensation		-			-			-		-		3,151			-			-			3,151
Restricted stock vested		380			4			-		-		(4	)		-			-			-
Performance units vested		169			2			-		-		(2	)		-			-			-
Restricted stock and performance units exchanged for tax withholding		(143	)		(2	)		-		-		(34	)		-			-			(36	)
Impact of Appalachia Divestiture		-			-			-		-		-			(1,635	)		10,420			8,785
Net loss		-			-			-		-		-			(2,542	)		(47,936	)		(50,478	)
Balance as of June 30, 2020		8,305		$	83			50	$	1	$	89,148		$	27,629		$	(63,559	)	$	53,302

									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.

CARBON ENERGY CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Three Months Ended
	Six Months Ended
	March 31,
	June 30,
(in thousands)	2020			2019
Cash flows from operating activities:
Net income (loss)	$	15,458		$	(6,690	)
Net (loss) income	$	(35,020	)	$	473
Items not involving cash:
Depreciation, depletion and amortization		35,~~811~~960			37,~~980~~860
Accretion of asset retirement obligations		~~478~~777			~~394~~799
Unrealized commodity derivative (gain) loss		(165,~~636~~626	)		~~8,850~~396
Stock-based compensation expense		~~204~~3,355			~~222~~446
Net loss on Appalachia Divestiture		25,527			-
Loss on sale of affiliate investment		419			-
Investments in affiliates		9			(1940	)
Amortization of debt costs		~~212~~857			~~277~~405
Interest expense paid-in-kind		~~662~~1,052			~~594~~1,244
Other		(74	)		-
Net change in:
Accounts receivable		2,~~524~~525			67,~~091~~525
Prepaid expenses, deposits and other current assets		~~148~~204			(375	)
Accounts payable, accrued liabilities and firm transportation contract obligations		(69,~~589~~009	)		(68,~~079~~611	)
Inventory and other non-current items		~~577~~452			~~316~~(327	)
Net cash provided by operating activities		1,277			8,311
Net cash (used in) provided by operating activities		(8,592	)		9,795
Cash flows from investing activities:
Development and acquisition of properties and equipment		(13,~~013~~460	)		(~~500~~1,863	)
Proceeds received – disposition of oil and gas properties and other property and equipment		256			164
Distribution from affiliate		-			50
Proceeds from Appalachia Divestiture		98,121			-
Proceeds from disposition of oil and gas properties and other property and equipment		922			176
Proceeds from sale of affiliate investment		131			-
Net cash used in investing activities		(626	)		(336	)
Net cash provided by (used in) investing activities		95,714			(1,637	)
Cash flows from financing activities:
Proceeds from credit facilities and notes payable		58,~~000~~839			34,~~000~~029
Payments on credit facilities and notes payable		(488,~~812~~803	)		(513,~~676~~185	)
Payments of debt issuance costs		-			(4193	)
(Distributions to) contributions from non-controlling interests, net		(3	)		22
Vested restricted stock and performance units exchanged for tax withholding		(36	)		-
Net cash provided by (used in) financing activities		185			(2,695	)
(Distributions to) contributions from non-controlling interests, net		(3	)		6
Net increase in cash and cash equivalents		836			5,280
Net cash used in financing activities		(80,003	)		(9,243	)
Cash and cash equivalents, beginning of period		904			5,736
Net increase (decrease) in cash, cash equivalents and restricted cash		7,119			(1,085	)
Cash and cash equivalents, end of period	$	1,740		$	11,016
Cash, cash equivalents and restricted cash, beginning of period		904			5,736
Cash, cash equivalents and restricted cash, end of period	$	8,023		$	4,651

See accompanying notes to Condensed Consolidated Financial Statements.

CARBON ENERGY CORPORATION

Notes to Condensed Consolidated Financial Statements

(Unaudited)

NOTE 1 – ORGANIZATION

Carbon Energy Corporation is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil, natural gas and natural gas liquids properties ~~located in the United States~~. The terms “we”, “us”, “our”, the “Company” or “Carbon” refer to Carbon Energy Corporation and our consolidated subsidiaries ~~(described below)~~. ~~The following is an organization chart of the key subsidiaries discussed in this report as of March 31, 2020:~~

5On May 26, 2020 Carbon Energy Corporation completed its sale of all of the issued and outstanding membership interests of Carbon Appalachia Company, LLC and Nytis Exploration Company LLC. See Note 3 – Divestiture for more information. Following the sale, Carbon’s operations are substantially limited to those in the Ventura Basin through Carbon California Company, LLC, a Delaware limited liability company (“Carbon California”), its majority-owned subsidiary.

Appalachian and Illinois Basin Operations

In the Appalachian and Illinois Basins, operations are conducted by Nytis Exploration Company, LLC (“Nytis LLC”). The following organizational chart illustrates this relationship as of March 31, 2020:

We hold all of the Class A Units of Carbon Appalachian Company, LLC, a Delaware limited liability company (“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, a Delaware limited liability company (“Carbon California”)~~. 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. The following organizational chart illustrates this ~~relationship~~ relationship as of ~~March~~June 3130, 2020:

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, 2019 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, 2019. 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 the Company and its consolidated subsidiaries. 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.

~~Recently~~Cash ~~Issued~~and ~~Accounting~~Cash ~~Pronouncements~~Equivalents and Restricted Cash

InThe ~~March~~following ~~2020,~~table ~~the~~provides ~~Financial~~a ~~Accounting~~reconciliation ~~Standards Board issued ASU 2020-04 as an update to provide optional guidance to ease the potential burden in accounting for (or recognizing the effects~~ of) ~~reference rate reform (ASC Topic 848) on financial reporting. The amendments in ASU 2020-04 are elective and apply to all entities~~cash, ~~subject~~cash toequivalents ~~meeting certain criteria, that have contracts, hedging relationships,~~ and ~~other~~restricted ~~transactions that~~cash ~~reference~~reported in the ~~London~~unaudited ~~interbank~~condensed ~~offered~~consolidated ~~rate~~balance ~~(“LIBOR”)~~sheet ~~or another reference rate expected~~ to ~~be discontinued~~amounts ~~because of reference rate reform. ASU 2020-04 provides optional expedients and exceptions for applying GAAP to contracts,~~shown ~~hedging~~in ~~relationships, and other transactions affected by reference rate reform if certain criteria are met. This guidance is effective beginning on March 12, 2020, and~~ the ~~Company~~unaudited ~~may~~condensed ~~elect to apply the amendments prospectively through December 31, 2022. The Company is currently evaluating the impact this guidance may have on its~~ consolidated ~~financial~~statement ~~statements~~of ~~and~~cash ~~related~~flows ~~disclosures.~~in thousands:

NOTE 3 – PROPERTY AND EQUIPMENT

	June 30, 2020
Cash and cash equivalents	$	1,311
Restricted cash		4,612
Other non-current assets		2,100
Total cash, cash equivalents and restricted cash	$	8,023

NOTE 3 – DIVESTITURE

On April 7, 2020, Carbon Energy Corporation, together with Nytis Exploration (USA) Inc. (the “Sellers”), and certain of the Company’s other direct and indirect wholly owned subsidiaries, entered into a Membership Interest Purchase Agreement (“MIPA”) to sell all of the issued and outstanding membership interests of Carbon Appalachia Company, LLC (“Carbon Appalachia”) and Nytis Exploration Company LLC (“Nytis LLC”) to Diversified Gas & Oil Corporation (“DGOC”) for $110.0 million, subject to customary purchase price adjustments, and a contingent payment of up to $15.0 million (the “Appalachia Divestiture”). The assets sold in the Appalachia Divestiture comprised substantially all of the Company’s assets in the Appalachian and Illinois basin. The transaction closed on May 26, 2020 for net proceeds of $98.1 million based on preliminary estimates of closing adjustments, resulting in a loss of approximately $34.5 million. The contingent payment of up to $15.0 million in the aggregate represents a contingent receivable that is not recorded in our unaudited condensed consolidated balance sheet. The contingent payment will be calculated based on fixed volumes and the average settled natural gas pricing for 2020, 2021, and 2022 as compared to established benchmark pricing. Any payments due will be paid yearly by January 5 of each of 2021, 2022 and 2023 based on the contingent payment calculation for the respective calendar years.

Proceeds from the closing were used to settle all outstanding amounts associated with the 2018 Credit Facility (as defined below) and repay a portion of the Old Ironsides Notes. See Note 7 – Credit Facilities and Notes Payable for more information. We incurred exit costs in conjunction with the divestiture of one-time severance and termination benefits for the affected employees.

The assets, liabilities and equity disposed of are set out in the table below:

	Amount (in thousands)
Assets:
Accounts receivable	$	9,651
Prepaid expenses		892
Derivative assets		3,159
Inventory		1,409
Oil and gas properties		128,993
Other property and equipment		14,035
Right-of-use assets		3,406
Other non-current assets		436
Liabilities and Equity:
Accounts payable and accrued liabilities		(13,355	)
Firm transportation contract obligations		(12,981	)
Lease liabilities		(3,406	)
Derivative liabilities		(11	)
Production and property taxes payable		(3,342	)
Asset retirement obligations		(14,027	)
Equity in subsidiaries		8,785
Net assets disposed		123,644
Cash received		98,121
Transaction costs		(8,940	)
Loss on Appalachia Divestiture	$	34,463

At June 30, 2020, restricted cash on the condensed consolidated balance sheet of approximately $6.7 million represents amounts held in escrow from the purchase price. The escrow amount will be released to the Company upon satisfaction of certain indemnification obligations and will be released upon the fulfillment of associated release requirements over the 36 months following the closing of the Appalachia Divestiture.

Carbon and DGOC entered into a transition services agreement to provide, on an interim basis, certain services associated with the sold assets. The services commenced on May 26, 2020 and are expected to terminate in November 2020. Billings of approximately $269,000 are recorded as a reduction of general and administrative expenses during the three months ended June 30, 2020.

The following table presents net income before non-controlling interests and net income attributable to controlling interests for the subsidiaries sold for the three and six months ended June 30, 2020 and 2019:

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2020		2019		2020		2019
Net (loss) income before non-controlling interests	$	(3,000)	$	5,003	$	1,645	$	3,923
Net (loss) income attributable to controlling interests	$	(2,737)	$	5,309	$	1,541	$	3,719

NOTE 4 – PROPERTY AND EQUIPMENT

Property and equipment, net consists of the following:

(in thousands)	~~March~~June 3130, 2020			December 31, 2019
Oil and gas properties:
Proved oil and gas properties	$~~352,561~~	125,006		$~~351,488~~	351,488
Unproved properties		41,~~906~~616			4,872
Accumulated depreciation, depletion, amortization and impairment		(~~112~~10,~~719~~911	)		(109,344	)
Oil and gas properties, net		~~244~~115,~~748~~711			247,016
Pipeline facilities and equipment		~~12,820~~-			12,814
Base gas		~~1,937~~-			1,937
Furniture and fixtures, computer hardware and software, and other equipment		62,~~967~~614			6,762
Accumulated depreciation and amortization		(51,~~956~~425	)		(5,529	)
Other property and equipment, net		151,~~768~~189			15,984
Total property and equipment, net	$	~~260~~116,~~516~~900		$	263,000

Unproved oil and gas properties not subject to depletion 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 ~~March~~June 3130, 2020 and 2019, there were no expiring or impaired leasehold costs that were reclassified into proved property.

We capitalized overhead applicable to acquisition, development and exploration activities of approximately $~~238~~134,000 and $68372,000 for the three and six months ended June ~~March 31~~30, 2020, respectively. For the three and six months ended June 30, 2019, we capitalized overhead applicable to acquisition, development and exploration activities of approximately $305,000 and $373,000, respectively.

Depletion expense related to oil and gas properties for the three and six months ended ~~March~~June 3130, 2020 was approximately $1.9 million and $5.3 million, respectively. Depletion expense related to oil and gas properties for the three and six months ended June 30, 2019 was approximately $3.45 million and $37.50 million, respectively.

For the three and six months ended ~~March 31~~June 30, 2020 and 2019, we did not recognize any ceiling test impairments as our full cost pool did not exceed the ceiling limitations. ~~Future~~ Future declines in oil and natural gas prices, increases in future operating expenses and future development costs could result in impairments of our oil and gas properties in future periods. Impairment changes are a non-cash charge and accordingly would not affect cash flows but would adversely affect our net income and stockholders’ equity.

8NOTE 5 – ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

NOTE 4 – ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Accounts payable and accrued liabilities consist of the following:

(in thousands)	~~March~~June 3130, 2020		December 31, 2019
Accounts payable	$	43,~~631~~717	$	9,875
Oil and gas revenue suspense		~~3,517~~135		3,620
Gathering and transportation payables		~~2,014~~906		1,877
Production taxes payable		~~2,768~~31		3,212
Accrued lease operating costs		~~734~~-		664
Accrued ad valorem taxes-current		~~4,114~~562		4,407
Accrued general and administrative expenses		32,~~186~~521		3,260
Asset retirement obligations-current		53,~~564~~384		5,021
Accrued interest		~~1,180~~791		1,335
Accrued gas purchases		~~1,220~~-		1,392
Other liabilities		~~1,352~~453		494
Total accounts payable and accrued liabilities	$	3012,~~280~~500	$	35,157

NOTE 56 – ASSET RETIREMENT OBLIGATIONS

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

The ARO liability is based on estimated economic lives, estimates of 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 adjusted as a result of a reassessment of expected cash flows and assumptions inherent in the estimation of the liability. 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.

The following table is a reconciliation of ARO:

	Three Months Ended March 31,
	Six Months Ended June 30,
(in thousands)	2020			2019
Balance at beginning of period	$	22,535		$	22,310
Accretion expense		~~478~~777			~~394~~799
Obligations discharged with Appalachia Divestiture		(14,027	)		-
Additions		7			-
Balance at end of period	$	239,~~020~~292		$	2223,~~704~~109
Less: Current portion		(53,~~564~~384	)		(3,~~392~~708	)
Non-current portion	$	175,~~456~~908		$	19,~~312~~401

9NOTE 7 – CREDIT FACILITIES AND NOTES PAYABLE

NOTE 6 – CREDIT FACILITIES AND NOTES PAYABLE

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

(in thousands)	~~March~~June 3130, 2020			December 31, 2019
2018 Credit Facility – revolver	$	~~70,150~~-		$	69,150
2018 Credit Facility – term note		~~3,333~~-			5,833
Old Ironsides Notes		2615,~~336~~836			25,675
Other debt		34			45
Paycheck Protection Program Loan		1,339			-
Total debt		99,853			100,703
Other debt		26			45
Less: unamortized debt discount		(22	)		(45	)
Total debt		17,201			100,703
Total credit facilities and notes payable		99,831			100,658
Less: unamortized debt discount		-			(45	)
Current portion of credit facilities and notes payable		(3,311	)		(5,788	)
Total credit facilities and notes payable		17,201			100,658
Non-current debt, net of current portion and unamortized debt discount	$	96,520		$	94,870
Current portion of credit facilities and notes payable		(1,339	)		(5,788	)
Non-current debt, net of current portion and unamortized debt discount	$	15,862		$	94,870

Paycheck Protection Program Loan

Reclass of non-current portion is open.

In May 2020, the Company received loan proceeds of approximately $1.3 million (“PPP Loan”) under the Paycheck Protection Program (“PPP”). The PPP, established as part of the Coronavirus Aid, Relief and Economic Security Act (“CARES Act”), provides for loans to qualifying businesses for amounts up to 2.5 times the average monthly payroll expenses of the qualifying business. The PPP Loan and accrued interest are forgivable after 24 weeks as long as the borrower uses the loan proceeds for eligible purposes, including payroll, benefits, rent and utilities, and maintains its payroll levels. For purposes of the PPP Loan, payroll costs exclude cash compensation of an individual employee in excess of $100,000, prorated annually. Not more than 40% of the forgiven amount may be for non-payroll costs. The amount of loan forgiveness will be reduced if the borrower terminates full-time employees or reduces salaries and wages for employees with salaries of $100,000 or less annually by more than 25% during the 24-week period.

The PPP Loan is evidenced by a promissory note, dated as of May 13, 2020 (the “PPP Note”), which contains customary events of default relating to, among other things, payment defaults and breaches of representations and warranties, and bears interest at 1.0% per annum. No payments of principal or interest are due during the six-month period beginning on the date of the PPP Note (the “Deferral Period”).

The Company intends to use the proceeds for purposes consistent with the PPP. In order to obtain full or partial forgiveness of the PPP Loan, the Company must request forgiveness and must provide satisfactory documentation in accordance with applicable Small Business Administration (“SBA”) guidelines. Interest payable on the PPP Note may be forgiven only if the SBA agrees to pay such interest on the forgiven principal amount of the PPP Note. The Company will be obligated to repay any portion of the principal amount of the PPP Note that is not forgiven, together with interest accrued and accruing thereon at the rate set forth above, until such unforgiven portion is paid in full. We intend to apply for forgiveness of the PPP Note as soon as we are eligible.

Beginning one month following expiration of the Deferral Period, and continuing monthly until 24 months from the date of the PPP Note (the “Maturity Date”), the Company is obligated to make monthly payments of principal and interest to the Lender with respect to any unforgiven portion of the PPP Note, in such equal amounts required to fully amortize the principal amount outstanding on the PPP Note as of the last day of the Deferral Period by the Maturity Date. The Company is permitted to prepay the PPP Note at any time without payment of any prepayment premium or penalty.

Carbon Appalachia

2018 Credit Facility

In 2018, the Company and its subsidiaries amended and restated its prior credit facilities and entered into a $500.0 million senior secured asset-based revolving credit facility maturing December 31, 2022 and a $15.0 million term loan maturing in 2020 (the “2018 Credit Facility”). The ~~2018 Credit Facility includes a sublimit of $1.5 million for letters of credit. The~~ borrowers under the 2018 Credit Facility ~~are~~ were Carbon Appalachia Enterprises, LLC (“CAE”) and various other subsidiaries of the Company (including Nytis Exploration (USA) Inc., a direct wholly owned subsidiary of the Company (“Nytis USA”), together with CAE, the “Borrowers”). Under the 2018 Credit Facility, the Company was is neither a borrower nor a guarantor. The initial borrowing base under the 2018 Credit Facility was $75.0 million. ~~and~~Loans ~~was~~under the ~~$71.0~~2018 ~~million~~Credit asFacility ofmay ~~March~~be ~~31,~~prepaid ~~2020~~without premium or penalty.

~~The~~Using ~~2018~~proceeds ~~Credit~~from ~~Facility~~the isAppalachia ~~guaranteed~~Divestiture, bywe ~~each~~repaid ~~existing~~the ~~and~~outstanding ~~future~~principal ~~direct~~balance orand ~~indirect~~accrued ~~subsidiary~~interest ofunder the ~~Borrowers~~2018 ~~and~~Credit ~~certain~~Facility, ~~other~~including ~~subsidiaries~~the ofterm ~~the~~loan, ~~Company~~of ~~(subject~~$72.3 tomillion, ~~various exceptions)~~ and ~~the~~terminated ~~obligations under~~ the 2018 Credit Facility ~~are~~on ~~secured~~May ~~by essentially all tangible~~26, ~~intangible and real property (subject to certain exclusions)~~2020.

Interest accrues on borrowings under the 2018 Credit Facility at a rate per annum equal to either (i) the base rate plus a margin equal to 0.25% - 0.75% depending on the utilization percentage or (ii) the Adjusted LIBOR plus a 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 with 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 Borrowers’ 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.

In August 2019, we amended the 2018 Credit Facility, effective October 1, 2019, to restrict the aging of our accounts payable to 90 days or less, maintain minimum liquidity of $3.0 million and require the sale of certain non-core assets by December 31, 2019.

In February 2020, we amended the 2018 Credit Facility to eliminate the minimum liquidity requirement and reduce the borrowing base from $75.0 million to $73.0 million, with subsequent borrowing base reductions totaling $6.0 million scheduled through May 1, 2020. Also, pursuant to this amendment, the lenders agreed to provide a limited waiver of non-compliance with the asset sale covenant included in the amendment from August 2019.

In April 2020, we amended the 2018 Credit Facility to extend the remaining borrowing base reductions totaling $4.0 million through June 1, 2020.

As of March 31, 2020, there was approximately $70.2 million in outstanding borrowings and no borrowing capacity available under the 2018 Credit Facility, after considering letters of credit outstanding. As of March 31, 2020, we were not in compliance with our current ratio financial covenant. However, we anticipate a full payoff of the 2018 Credit Facility as a result of Contemplated Transactions described in Note 15 prior to any potential event of default. The Company believes given these circumstances it is appropriate to classify the outstanding borrowings associated with the 2018 Credit Facility as non-current.

The terms of the 2018 Credit Facility require us to enter into derivative contracts at fixed pricing for a certain percentage of our production. We are party to International Swaps and Derivatives Association Master Agreements (“ISDA Master Agreements”) that establish standard terms for the derivative contracts and inter-creditor agreements with the lenders whereby any credit exposure related to the derivative contracts entered into by us 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 $824,000, of which $134,000 was associated with the term loan. The current portion of unamortized fees associated with the credit facility is included in prepaid expenses, deposits and other current assets and the non-current portion is included in other non-current assets. The unamortized portion associated with the term loan was $22,000 as of March 31, 2020 and is directly offset against the loan in current liabilities. As of March 31, 2020, we had unamortized deferred issuance costs of approximately $476,000 associated with the credit facility. During the three months ended March 31, 2020 and 2019, we amortized approximately $66,000 and $63,000, respectively, as interest expense associated with the 2018 Credit Facility.

Old Ironsides Notes

On December 31, 2018, in connection with our acquisition (the “OIE Membership Acquisition”) of all of the Class A Units of Carbon Appalachia from Old Ironside Fund II-A Portfolio Holding Company, LLC, a Delaware limited liability company, and Old Ironside Fund II-B Portfolio Holding Company, LLC, a Delaware limited liability company (collectively, “Old Ironsides”), 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.

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 ~~three~~six months ended ~~March~~June 3130, 2020, the Company elected payment-in-kind interest of approximately $662,000.

11On May 25, 2020, Carbon entered into an Agreement Regarding Payoff and Release or Amendment of Notes (the “Payoff Agreement”) with Old Ironsides. Pursuant to the terms of the Payoff Agreement, Carbon is required to apply certain net proceeds from the Appalachia Divestiture in repayment of the Old Ironsides Notes on specified repayment dates tied to milestones under the MIPA. The initial payment of $10.5 million was paid within three business days after the closing date of the Appalachia Divestiture. The second payment is due within three business days after the settlement and payment of the Final Base Purchase Price (as defined in the MIPA). If the sum of the initial payment and the second payment is at least $20.0 million, the Old Ironsides Notes will be deemed paid in full. If the sum of the initial payment and the second payment is at least $18.0 million but less than $20.0 million, the Old Ironsides Notes will be amended such that the outstanding principal balance plus all accrued and unpaid interest is equal to $21.5 million (less the amount of the initial and second payments) and the Old Ironsides Notes will remain outstanding with no other change to the existing terms. If the sum of the initial payment and the second payment is less than $18.0 million, then Carbon will have the opportunity to make a third payment.

The third payment would be due within three business days after the first Contingent Payment (as defined in the MIPA). If the sum of the initial payment, the second payment and the third payment is at least $18.0 million, the Old Ironsides Notes will be amended such that the outstanding principal balance plus all accrued and unpaid interest is equal to $23.0 million (less the amount of the initial, second and third payments) and the Old Ironsides Notes will remain outstanding with no other change to the existing terms. If the sum of the initial payment, the second payment and the third payment is less than $18.0 million, the payments made by Carbon as of such date will be considered mandatory prepayments and the Old Ironsides Notes will remain outstanding with a maturity date of December 31, 2023 and no change to the existing terms.

Carbon California

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

(in thousands)	~~March~~June 3130, 2020			December 31, 2019
Senior Revolving Notes, related party, due February 15, 2022	$	3437,~~700~~200		$	33,000
Subordinated Notes, related party, due February 15, 2024		13,~~000~~390			13,000
Total principal		4750,~~700~~590			46,000
Less: Deferred notes costs		(~~164~~154	)		(175	)
Less: unamortized debt discount		(~~1,019~~952	)		(1,084	)
Total notes payable – related party	$	4649,~~517~~484		$	44,741

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”). The Company 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. AsOn ofApril ~~March 31~~1, 2020, the borrowing base was ~~$45.0~~redetermined ~~million,~~and ofreduced ~~which~~to $3440.70 million ~~was outstanding~~. Effective OnJune ~~April 1~~30, 2020, ~~the~~and ~~borrowing~~through ~~base~~December ~~was~~31, ~~redetermined~~2020, ~~and~~Prudential ~~reduced~~is no longer obligated to ~~$40.0~~make ~~million~~advances under the Senior Revolving Notes.

Carbon California may elect to incur interest at either (i) 5.50% plus LIBOR or (ii) 4.50% plus the Prime Rate (which is defined as the interest rate published daily by JPMorgan Chase Bank, N.A.). As of December 31, 2019, the effective borrowing rate for the Senior Revolving Notes was 7.10%. In addition, the Senior Revolving Notes include a commitment fee for any unused amounts at 0.50% as well as an annual administrative fee of $75,000, payable on February 15 each year.

The Senior Revolving Notes are secured by all the assets of Carbon California. The Senior Revolving Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated proved developed production 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 expenses and deposits and the long-term portion is included in other non-current assets for a combined value of approximately $~~528~~458,000. For the three and six months ended ~~March~~June 3130, 2020 ~~and 2019~~, Carbon ~~California~~ California amortized fees of $70,000 and $74141,000, 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”). The Company is not a guarantor of the Subordinated Notes. The closing of the Securities Purchase Agreement on February 15, 2017 resulted in the sale and issuance by Carbon California of Subordinated Notes in the original principal amount of $10.0 million, all of which remains outstanding as of ~~March~~June 3130, 2020.

12Prudential 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, 2020, Carbon California had an outstanding discount of approximately $646,000, 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, 2020, Carbon California amortized $45,000 and $89,000, respectively, associated with the Subordinated Notes.

Prudential received an additional 1,425 Class A Units, representing 5.0% of the total sharing percentage, for the issuance of the Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding Subordinated Notes of $10.0 million. The Company then allocated the non-cash value of the units of approximately $1.3 million, which was recorded as a discount to the Subordinated Notes. As of March 31, 2020, Carbon California had an outstanding discount of approximately $691,000, which is presented net of the Subordinated Notes within Notes payable-related party on the unaudited condensed consolidated balance sheets. During the three months ended March 31, 2020, Carbon California amortized $45,000 and $45,000, 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 ~~March~~June 3130, 2020.

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 ~~March~~June 3130, 2020, Carbon California had an outstanding discount of $~~328~~307,000 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 ~~March~~June 3130, 2020 ~~and 2019~~, Carbon California amortized $2142,000 and $21,000, 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.

In December 2019, Carbon California amended the Senior Revolving Notes, the Subordinated Notes and the 2018 Subordinated Notes to amend the total leverage ratio and senior leverage ratio, effective September 30, 2019. The Senior Revolving Notes were also amended to provide a mechanism to determine a successor reference rate to LIBOR.

13In July 2020, Carbon California amended the Senior Revolving Notes, the Subordinated Notes and the 2018 Subordinated Notes to restrict additional withdrawals under the Senior Revolving Notes through December 31, 2020, amend the total leverage ratio, senior leverage ratio and interest coverage ratio and provide a waiver for non-compliance with its Senior Revolving Notes/EBITDA ratio at March 31, 2020. Also, the interest payable under the Subordinated Notes and the 2018 Subordinated Notes beginning May 15, 2020 would be paid in kind and added to the outstanding principal amount of each note. For the three months ended June 30, 2020, paid in kind interest was approximately $390,000.

The affirmative and negative covenants are subject to various exceptions, including basket amounts and acceptable transaction levels. In addition, (i) the Senior Revolving Notes require at ~~December~~June 3130, ~~2019~~2020 Carbon California’s compliance with (A) a maximum Debt/EBITDA ratio of 46.50 to 1.0 (B) a maximum Senior Revolving Notes/EBITDA ratio of 34.5 to 1.0 and (C) a minimum interest coverage ratio of 21.065 to 1 and (ii) the ~~Subordinated~~ Subordinated Notes require at ~~December~~June 3130, ~~2019~~2020 Carbon California’s compliance with (A) a maximum Debt/EBITDA ratio of 56.18 90 to 1.0, (B) a maximum Senior Revolving Notes/EBITDA ratio of 45.0318 to 1.0, (C) a minimum interest coverage ratio of 1.64 to 1.0, (D) an asset coverage test whereby indebtedness may not exceed the product of 0.65 times Adjusted PV-10 of proved developed reserves set forth in the most recent reserve report, (E) maintenance of a minimum borrowing base of $30.0 million under the Senior Revolving ~~Notes~~ Notes and (F) a minimum current ratio of 0.85 to 1.00.

As of ~~March~~June 3130, 2020, Carbon California was ~~not~~ in compliance with its ~~Senior~~financial ~~Revolving Notes/EBITDA ratio. We are currently negotiating an amendment to the covenant requirements with Prudential and are confident we will be successful in amending the~~ covenants. ~~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.~~

NOTE 78 – REVENUE

The following tables present our disaggregated revenue by primary region within the United States and major product line ~~for the three months ended March 31, 2020 and 2019 (in thousands)~~:

	Appalachian and Illinois Basins				Ventura Basin				Total
	Three Months Ended March 31,				Three Months Ended March 31,				Three Months Ended March 31,
	2020		2019		2020		2019		2020		2019
Natural gas sales	$	8,019	$	18,792	$	415	$	524	$	8,434	$	19,316
Natural gas liquids sales		-		-		152		247		152		247
Oil sales		1,147		1,537		6,069		7,452		7,216		8,989
Transportation and handling		633		734		-		-		633		734
Marketing gas sales		6,318		4,944		-		-		6,318		4,944
Total	$	16,117	$	26,007	$	6,636	$	8,223	$	22,753	$	34,230

For the three months ended June 30, 2020 and 2019 (in thousands):

	Appalachian and Illinois Basins				Ventura Basin				Total
	Three Months Ended June 30,				Three Months Ended June 30,				Three Months Ended June 30,
	2020		2019		2020		2019		2020		2019

Natural gas sales	$	4,011	$	13,879	$	127	$	337	$	4,138	$	14,216
Natural gas liquids sales		-		-		49		195		49		195
Oil sales		194		1,558		3,573		8,344		3,767		9,902
Transportation and handling		274		322		-		-		274		322
Marketing gas sales		2,380		3,221		-		-		2,380		3,221
Total	$	6,859	$	18,980	$	3,749	$	8,876	$	10,608	$	27,856

For the six months ended June 30, 2020 and 2019 (in thousands):

	Appalachian and Illinois Basins				Ventura Basin				Total
	Six Months Ended June 30,				Six Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019		2020		2019

Natural gas sales	$	12,030	$	32,671	$	542	$	861	$	12,572	$	33,532
Natural gas liquids sales		-		-		201		441		201		441
Oil sales		1,339		3,095		9,643		15,796		10,982		18,891
Transportation and handling		908		1,056		-		-		908		1,056
Marketing gas sales		8,698		8,165		-		-		8,698		8,165
Total	$	22,975	$	44,987	$	10,386	$	17,098	$	33,361	$	62,085

We record revenue in the month production is delivered to the purchaser, but settlement statements may not be received until 30 to 90 days after the month of production. As such, we estimate the production delivered and the related pricing. The estimated revenue is recorded within Accounts receivable – Revenue on the consolidated balance sheets. Any differences between our initial estimates and actuals are recorded in the month payment is received from the customer. These differences have not historically been material.

~~NOTE 8 – STOCK-BASED COMPENSATION PLANS~~11

WeNOTE ~~have~~9 ~~three~~– ~~stock~~STOCK-BASED ~~plans, the Carbon~~COMPENSATION 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.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. As of June 30, 2020, there were approximately 254,000 shares of common stock available to be granted 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.

14The Appalachia Divestiture was a change in control event; therefore, we accelerated the vesting of substantially all outstanding unvested restricted stock and unvested restricted performance units. Any remaining unvested restricted performance units were forfeited due to certain performance measures not achieved.

Restricted Stock

As of ~~March~~June 3130, 2020, approximately ~~748~~847,000 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 as defined in the agreement. During the ~~three~~six months ended ~~March~~June 3130, 2020, approximately 20400,000 restricted stock units vested.

Compensation costs recognized for restricted stock grants were approximately $~~204,000~~1.7 million and $~~179,000~~1.9 million for the three and six months ended ~~March~~June 3130, 2020 ~~and 2019~~, respectively~~. As of March 31~~, and ~~2020, there was~~ approximately $~~1.3~~224,000 ~~million~~and ~~unrecognized~~$403,000 ~~compensation~~for ~~costs~~the ~~related~~three toand ~~these~~six ~~restricted~~months ~~stock~~ended ~~grants~~June ~~which~~30, ~~we expect~~2019, ~~to be recognized over the next 6~~respectively.~~0 years.~~

Restricted Performance Units

As of ~~March~~June 3130, 2020, approximately ~~699~~804,000 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 three months ended March 31, 2020, approximately 83,000 performance units vested.~~

We account for the performance units granted during 2018 and 2019 at their fair value determined at the date of grant, which were $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. AtDuring ~~March~~the ~~31,~~six ~~2020,~~months weended ~~estimated~~June ~~that none of the performance units granted in 2019 and 2018 would vest~~30, ~~and~~2020, ~~accordingly~~approximately 251,000 ~~no compensation cost has been recorded for these~~ performance units. Asvested ~~of March 31, 2020, if a change in control~~ and ~~other~~we ~~performance~~recognized ~~provisions~~$1.4 ~~pursuant to~~million ~~the terms and conditions~~ of ~~these award agreements as defined in the agreement were met in full, the estimated unrecognized~~ compensation ~~cost related to unvested performance units would be approximately $3~~costs.~~2 million.~~

NOTE 910 – EARNINGS (LOSS) ~~PER~~ PER COMMON SHARE

Basic earnings (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders for the period by the basic weighted average number of common shares outstanding during the period. Diluted earnings (loss) per common share includes potentially issuable shares consisting primarily of non-vested restricted stock and contingent restricted performance units, using the treasury stock method. In periods when we report a net loss, all common stock equivalents are excluded from the calculation of diluted weighted average shares outstanding because they would have an anti-dilutive effect, meaning the loss per share would be reduced.

For the three ~~months ended March 31, 2019, approximately 269,000 shares of restricted stock, respectively, were considered anti-dilutive~~ and ~~were~~six ~~excluded from the computation of diluted earnings per share. For the three~~ months ended ~~March 31~~June 30, ~~2020 and~~ 2019, approximately ~~193~~276,000 ~~and 200,000~~ shares of restricted performance units, ~~respectively,~~ subject to future contingencies were excluded from the computation of basic and diluted earnings per share.

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

	Three Months Ended March 31,
	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands, except per share amounts)	2020			2019			2020			2019
Net income (loss) attributable to common stockholders, basic and diluted		9,724			(4,175	)
Net (loss) income attributable to common stockholders, basic and diluted		(48,011	)		6,154			(38,287	)		1,979
Weighted-average number of common shares outstanding, basic		78,~~809~~118			7,~~663~~815			7,964			7,739
Add dilutive effects of non-vested shares of restricted stock and restricted performance units		~~281~~-			-342			-			342
Weighted-average number of common shares outstanding, diluted		8,~~090~~118			78,~~663~~157			7,964			8,081
Net income (loss) per common share, basic	$	1.25		$	(0.54	)
Net (loss) income per common share, basic	$	(5.91	)	$	0.79		$	(4.81	)	$	0.26
Net income (loss) per common share, diluted	$	1.20		$	(0.54	)
Net (loss) income per common share, diluted	$	(5.91	)	$	0.75		$	(4.81	)	$	0.24

1512

Series B Convertible Preferred Stock - Related Party

In May 2018, we raised $5.0 million through the issuance of 50,000 shares of Series B Convertible Preferred Stock, par value $0.01 per share (“Preferred Stock”) 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 $~~599~~674,000 as of ~~March~~June 3130, 2020 and increased by $75150,000 during the ~~three~~six months ended ~~March~~June 3130, 2020.

~~NOTE~~Yorktown 10waived –its ~~INCOME~~right ~~TAXES~~to be paid a liquidating distribution of approximately $5.6 million in connection with the Appalachia Divestiture until the restricted payment covenant in the Old Ironsides Notes is waived by Old Ironsides or until the payment in full of the Old Ironsides Notes or the earlier termination or cancellation of the Old Ironsides Notes, at which point the liquidating distribution will become immediately due and payable by Carbon out of Carbon’s assets legally available for distribution to its stockholders.

NOTE 11 – 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 from net operating loss carryforwards are recognized to the extent that realization of these benefits is considered more likely than not. To the extent that available evidence raises doubt about the realization of a deferred income tax asset, a valuation allowance is established.

At ~~March~~June 3130, 2020, the Company has established a full valuation allowance against the balance of net deferred tax assets.

16NOTE 12 – FAIR VALUE MEASUREMENTS

NOTE 11 – 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
March 31, 2020
June 30, 2020
Assets:
Commodity derivatives	$	-	$	239,~~185~~000	$	-	$	239,~~185~~000
Liabilities:
Commodity derivatives	$	-	$	25	$	-	$	25
December 31, 2019
Assets:
Commodity derivatives	$	-	$	7,079	$	-	$	7,079
Liabilities:
Commodity derivatives	$	-	$	556	$	-	$	556

Commodity Derivative

As of ~~March~~June 3130, 2020, 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 marketplace participant’s view. All significant inputs are observable, either directly or indirectly; therefore, our derivative instruments are included within the Level 2 fair value hierarchy.

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

Certain assets and liabilities are measured at fair value on a non-recurring basis. These assets and liabilities are not measured at fair value on an ongoing basis; however, they are subject to fair value adjustments in certain circumstances. The fair value of the following assets and liabilities are based on unobservable pricing inputs and therefore, are included within the Level 3 fair value hierarchy.

Firm transportation contracts. 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.13

Firm transportation contracts. 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. Subsequent to the Appalachia Divestiture, we no longer have any firm transportation contracts.

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 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 Obligations. 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.

NOTE 1213 – 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.

17We have entered into swap and costless collar derivative agreements to hedge a portion of our oil production through December 2022. Subsequent to the Appalachia Divestiture, our remaining derivative contracts relate to Carbon California production. As of June 30, 2020, these derivative agreements consisted of the following:

We have entered into swap and costless collar derivative agreements to hedge a portion of our oil and natural gas production through December 2022. As of March 31, 2020, these derivative agreements consisted of the following:

	Oil Swaps*								Oil Collars*
Year	WTI Bbl		Weighted Average Price (a)		Brent Bbl		Weighted Average Price (b)		Brent Bbl		Weighted Average Price (b)
2020		41,867	$	50.12		123,630	$	64.22		30,400	$ 47.00 - $75.00
2021		-	$	-		86,341	$	67.12		190,000	$ 47.00 - $75.00
2022		-	$	-		-	$	-		199,900	$ 50.00 - $61.00

	Natural Gas Swaps				Natural Gas Collars
			Weighted Average				Weighted Average Price
Year	MMBtu		Price (a)		MMBtu		Range (a)
2020		9,262,000	$	2.70		2,541,000	$	2.10 – $2.75
2021		6,448,000	$	2.58		6,395,000	$	2.00 – $2.75

Includes 100% of Carbon California’s outstanding derivative hedges at June 30, 2020, and not our proportionate share.

	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)
2020		98,844	$	55.37		172,403	$	64.58		20,600	$	47.00 - $60.15		46,700	$	47.00 - $75.00
2021		-	$	-		86,341	$	67.12		66,200	$	47.00 - $60.15		190,000	$	47.00 - $75.00
2022		-	$	-		-	$	-		-	$	-		199,900	$	50.00 - $61.00

(a)

NYMEX Light Sweet Crude West Texas Intermediate futures contracts for the respective period.

*	Includes 100% of Carbon California’s outstanding derivative hedges at March 31, 2020, and not our proportionate share.
(a)	NYMEX Henry Hub Natural Gas futures contracts for the respective period.
(b)	NYMEX Light Sweet Crude West Texas Intermediate futures contracts for the respective period.
(c)	Brent future contracts for the respective period.

(b)

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)	~~March~~June 3130, 2020		December 31, 2019
Commodity derivative contracts:
Commodity derivative asset	$	186,~~078~~129	$	5,915
Commodity derivative asset – non-current	$	52,~~107~~871	$	1,164
Commodity derivative liability	$	-	$	469
Commodity derivative liability – non-current	$	25-	$	87

The table below summarizes the commodity settlements and unrealized gains and losses related to the Company’s derivative instruments for the three months ended March 31, 2020 and 2019. Changes in the fair value of commodity derivative contracts are recognized in revenues in the unaudited condensed consolidated statements of operations and gains and losses are included within the cash flows from operating activities in the unaudited condensed consolidated statements of cash flows. 14

	Three Months Ended March 31,
(in thousands)	2020		2019
Commodity derivative contracts:
Settlement gain (loss)	$	3,078	$	(456	)
Unrealized gain (loss)		16,636		(8,850	)
Total commodity derivative gain (loss)	$	19,714	$	(9,306	)

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, 2020 and 2019. Changes in the fair value of commodity derivative contracts are recognized in revenues in the unaudited condensed consolidated statements of operations and gains and losses are included within the cash flows from operating activities in the unaudited condensed consolidated statements of cash flows.

	Three Months Ended June 30,					Six Months Ended June 30,
(in thousands)	2020			2019		2020		2019

Commodity derivative contracts:
Settlement gain (loss)	$	5,363		$	225	$	8,441	$	(231	)
Unrealized gain (loss)		(11,010	)		8,455		5,626		(396	)

Total commodity derivative gain (loss)	$	(5,647	)	$	8,680	$	14,067	$	(627	)

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

We net our derivative instrument fair value amounts pursuant to ISDA Master Agreements, which provide for the net settlement over the term of the contracts and in the event of default or termination of the contracts. The following table summarizes the effect of netting arrangements for recognized derivative assets and liabilities that are subject to master netting arrangements or similar arrangements in the unaudited condensed consolidated balance sheet as of ~~March~~June 3130, 2020:

Net

Gross

Recognized

Gross

Fair Value

Assets/

Amounts

Assets/

Balance Sheet Classification (in thousands)

Liabilities

Offset

Liabilities

Commodity derivative assets:

Commodity derivative asset

186,~~441~~196

(~~363~~67

)

186,~~078~~129

Commodity derivative asset – non-current

73,~~144~~674

(~~2,037~~803

)

52,~~107~~871

Total derivative assets

259,~~585~~870

(~~2,400~~870

)

239,~~185~~000

Commodity derivative liabilities:

Commodity derivative liability

(~~363~~67

)

~~363~~67

Commodity derivative liability – non-current

(~~2,062~~803

)

~~2,037~~803

~~(25~~-

)

Total derivative liabilities

(~~2,425~~870

)

~~24,00~~870

~~(25~~-

)

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

NOTE 1314 – COMMITMENTS AND CONTINGENCIES

Delivery Commitments

We ~~have~~had ~~entered into~~ firm transportation contracts to ensure the transport for certain of our gas production to purchasers. ~~Firm~~These ~~transportation~~contracts ~~volumes~~were assumed in the EXCO Acquisition in October 2016 and the ~~related~~OIE Membership Acquisition in December 2018 and were reflected in the Company’s unaudited condensed consolidated balance sheet. The remaining volumes and related demand charges for the remaining term of these contracts aswere ofassumed by ~~March~~DGOC ~~31,~~as ~~2020~~of ~~are~~the ~~summarized~~closing inof the ~~table~~Appalachia ~~below~~Divestiture.

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

As of March 31, 2020, the remaining commitment related to the firm transportation contracts assumed in the EXCO Acquisition in October 2016 and the OIE Membership Acquisition in December 2018 is $13.6 million and reflected in the Company’s unaudited condensed consolidated balance sheet. These contractual obligations are reduced monthly as the Company pays these firm transportation obligations.

Natural gas processing agreement

We ~~have~~ entered into an initial five-year ~~gas~~ gas processing agreement expiring in 2022. Wewith ~~have~~ an option to extend the term of the agreement by another five years. The related ~~demand~~ demand charges for volume commitments over the remaining term of the agreement ~~are~~were approximately $1.8 million per year. We ~~will pay~~paid a processing fee of $2.50 per Mcf for the term of the agreement, with a minimum annual volume commitment of 720,000 Mcf.

Effective June 1, 2020 we entered into a revised gas processing agreement expiring July 31, 2022. We will pay a processing fee based on actual midstream expenditures and processed gas volumes for the prior calendar year. The base fee for calendar year 2020 is $3.50 per Mcf delivered to the processor. An additional fee, ranging from 5% to 15% of the processing fee, is attributable to the price of the residue gas sold by the processor. We will receive 100% of the allocated proceeds for the processor’s sale of our residue gas and natural gas liquids.

Capital Commitments

As of ~~March~~June 3130, 2020, we had no capital commitments.

Litigation

The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the anticipated results of any pending litigation and claims are not expected to have a material effect on the results of operations, the financial position, or the cash flows of the Company.

NOTE 1415 – SUPPLEMENTAL CASH FLOW DISCLOSURE

Supplemental cash flow disclosures for the ~~three~~six months ended ~~March~~June 3130, 2020 and 2019 are presented below:

	Three Months Ended March 31,
	Six Months Ended June 30,
(in thousands)	2020			2019
Cash paid for interest	$	13,~~794~~445		$	14,~~875~~536
Non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	(~~564~~269	)	$	(8239	)
Increase in asset retirement obligations	$	7		$	-
Adjustments to OIE Membership Acquisition purchase price	$	-		$	1,317

NOTE 1516 – SUBSEQUENT EVENTS

~~Contemplated~~On ~~Transactions~~August 7, 2020, we obtained the necessary consent that allowed for the conveyance of certain assets associated with the Appalachia Divestiture that were initially excluded pending receipt of such consent. As a result, approximately $400,000 in escrowed funds were released to Carbon, and pursuant to the MIPA, within 10 business days DGOC is to deliver to Carbon approximately $1.6 million in additional funds that were allocated to the properties as part of the MIPA.

On April 7, 2020, Carbon Energy Corporation, together with Nytis USA (the “Sellers”), and certain of the Company’s other direct and indirect wholly owned subsidiaries, entered into a Membership Interest Purchase Agreement (“MIPA”) to sell all of the issued and outstanding membership interests of Carbon Appalachia and Nytis LLC to Diversified Gas & Oil Corporation for $110.0 million, subject to customary purchase price adjustments, and a contingent payment of up to $15.0 million (“Contemplated Transactions”). The assets contained in the Contemplated Transactions comprise all of the Company’s assets in the Appalachian and Illinois basin. If the Sellers terminate the MIPA under certain circumstances, the Sellers may be required to pay a termination fee of $3.8 million. The transaction is expected to close during the second quarter of 2020.16

Upon closing of the Contemplated Transactions, the Company’s remaining assets will be located solely in the Ventura Basin of California. Proceeds from the Contemplated Transactions will be used to settle all outstanding amounts associated with the 2018 Credit Facility and a portion of the Old Ironsides Notes.

COVID-19

We cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, cash flows, liquidity, financial condition and results of operations at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate geographic spread of the virus, the consequences of governmental and other measures designed to prevent the spread of the virus, the development of effective treatments, the duration of the outbreak, actions taken by governmental authorities, customers, suppliers and other third parties, workforce availability, and the timing and extent to which normal economic and operating conditions resume.

Oil Pricing Environment

In the midst of the ongoing COVID-19 pandemic, oil prices declined significantly due to potential increases in supply emanating from the disagreement on production cuts among members of OPEC and certain non-OPEC, oil-producing countries. The resulting supply and demand imbalance is having disruptive impacts on the oil and natural gas exploration and production industry and on other industries that serve exploration and production companies. These industry conditions, coupled with those resulting from the COVID-19 pandemic, could lead to significant global economic contraction generally and in our industry in particular. Although OPEC agreed in April to cut production, the responses of oil and gas producers to the lower demand for, and price of, oil, natural gas and NGLs are constantly evolving and remain uncertain. In addition, the dramatic decrease in oil and gas prices could have substantial negative implications for our revenue sources that are related to or underpinned by commodity prices. As a result, these factors could have a material adverse effect on our business, future results of operations, financial position or cash flows.

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 Annual Report on Form 10-K for the fiscal year ended December 31, 2019 (the “2019 Annual Report on Form 10-K”).

General Overview

Carbon Energy Corporation, a Delaware corporation formed in 2007, is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil, natural gas and natural gas liquids (“NGLs”) 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 ~~wholly-owned and~~ majority-owned ~~subsidiaries.~~subsidiary, ~~We own 100% of the outstanding interests of~~ Carbon ~~Appalachia, and Nytis Exploration (USA) Inc~~California., a Delaware corporation (“Nytis USA”), which in turn owns 98.11% of Nytis Exploration Company LLC, a Delaware limited liability company (“Nytis LLC”). Nytis LLC holds interests in our operating subsidiaries. We own 53.92% of Carbon California which we consolidate for financial reporting purposes as a majority-owned subsidiary. ~~We focus on conventional and unconventional reservoirs, including shale, tight sands and coalbed methane.~~

At ~~March~~June 3130, 2020, our proved developed reserves were comprised of 1484% oil and NGLs and 8616% 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.

22Reverse Stock Split

As more fully described in proxy materials filed with the SEC, the Board of Directors is proposing to amend the Company’s amended and restated certificate of incorporation to effect a reverse stock split at a ratio of 4-for-1 (the “Reverse Stock Split”). If the Reverse Stock Split is approved, the Company will file with the Delaware Secretary of State a certificate of amendment to its Amended and Restated Certificate of Incorporation, at which date (the “effective time”) a stockholder owning fewer than four shares immediately prior to the effective time would only be entitled to a fraction of a share of common stock and will be paid cash in lieu of such fraction of a share, on the basis of $1.00 (the “Cash Payment”), for each share of common stock held by the stockholder (the “Cashed Out Stockholder”) immediately prior to effective time and the Cashed Out Stockholders will no longer be a stockholder of the Company. As of July 16, 2020, 90 shareholders that collectively owned 191 shares of the Company’s common stock owned less than four shares of common stock. If the Reverse Stock Split is approved, the Company would pay $191.00 to these Cashed Out Shareholders. The Company will use its own funds to pay the Cashed Out Stockholders.

The purpose of the Reverse Stock Split is to enable the Company to reduce the number of record holders of its common stock below 300, which is the level below which the Company can suspend its duty to file periodic and current reports and other information with the SEC under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The Board of Directors has determined that the costs of being a public reporting company outweigh the benefits of being a public company. After giving effect to the Reverse Stock Split and other actions required to suspend reporting obligations under the Exchange Act, the Company will no longer be subject to the reporting requirements under the Exchange Act or other requirements applicable to a public company, including requirements under the Sarbanes-Oxley Act of 2002 (the “Sarbanes Oxley Act”).

The Company anticipates that after the Reverse Stock Split its common stock will trade on the Pink Non-Current platform of the OTC Markets Group.

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.

~~Like other oil and gas companies, our business is being adversely affected by the~~ COVID-19 pandemic and measures being taken to mitigate its impact. The pandemic has resulted in widespread adverse impacts on the global economy and on our employees, customers, suppliers and other parties with whom we have business relations. As the coronavirus pandemic and government responses are rapidly evolving, the extent of the impact on domestic exploration and production companies remains unknown. Further, the impact of the pandemic, including the resulting significant reduction in global demand for oil and gas, coupled with the sharp decline in oil prices following the announcement of price reductions and production increases in March 2020 by members of the Organization of the Petroleum Exporting Countries (“OPEC”) and other foreign, oil-exporting countries is expected to lead to significant global economic contraction generally and in our industry in particular. We anticipate that our business, financial condition and results of operations may be materially and adversely impacted as a result of these developments.

Like other oil and gas companies, our business is being adversely affected by the COVID-19 pandemic and measures being taken to mitigate its impact. The pandemic has resulted in widespread adverse impacts on the global economy and on our employees, customers, suppliers and other parties with whom we have business relations. As the coronavirus pandemic and government responses are rapidly evolving, the extent of the impact on domestic exploration and production companies remains unknown. Further, the impact of the pandemic, including the resulting significant reduction in global demand for oil and gas, coupled with the sharp decline in oil prices following the announcement of price reductions and production increases in March 2020 by members of the Organization of the Petroleum Exporting Countries (“OPEC”) and other foreign, oil-exporting countries is expected to continue to lead to significant global economic contraction generally and in our industry in particular. We have modified certain business and workforce practices (including those related to employee travel, employee work locations, and cancellation of physical participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by governmental and regulatory authorities. However, the quarantine of personnel or the inability to access our facilities or customer sites could adversely affect our operations. Additionally, currently many of our employees are working remotely. We ~~cannot~~anticipate ~~predict the full impact~~ that ~~COVID-19 or~~ ~~the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on~~ our business, ~~cash flows, liquidity,~~ financial condition and results of operations atmay ~~this~~be ~~time,~~materially ~~due~~and toadversely ~~numerous~~impacted ~~uncertainties~~as a result of these developments.

InGiven the ~~midst~~dynamic nature of the ~~ongoing~~ COVID-19 ~~pandemic,~~ ~~oil~~pandemic ~~prices~~and ~~declined~~related ~~significantly~~market ~~due~~conditions, towe ~~potential~~cannot ~~increases~~reasonably inestimate ~~supply~~the ~~emanating~~period ~~from~~of ~~the~~time ~~disagreement~~these onevents ~~production~~will ~~cuts~~persist ~~among members~~or ofthe ~~OPEC~~full impact ~~and~~that ~~certain non~~COVID-~~OPEC,~~19 or ~~oil-producing~~the ~~countries.~~significant ~~The~~disruption ~~resulting supply~~ and ~~demand~~volatility ~~imbalance~~currently isbeing ~~having~~experienced ~~disruptive impacts~~in on the oil and natural gas markets ~~exploration~~will ~~and~~have ~~production industry and~~ on ~~other~~our ~~industries~~business, ~~that~~cash ~~serve~~flows, ~~exploration and production companies. These industry conditions~~liquidity, ~~coupled~~financial ~~with~~condition ~~those~~and ~~resulting~~results ~~from~~of ~~the~~operations ~~COVID-19~~at ~~pandemic~~this time, ~~could~~due ~~lead~~ to ~~significant global~~numerous ~~economic contraction generally and in our industry in particular~~uncertainties. ~~Although~~The ~~OPEC~~ultimate ~~agreed~~impacts inwill ~~April~~depend toon ~~cut~~future ~~production~~developments, ~~the~~including, ~~responses of~~among ~~oil~~others, ~~and gas producers to~~ the ~~lower~~consequences ~~demand~~of ~~for,~~countermeasures taken ~~and~~by ~~price of~~governments, ~~oil,~~businesses ~~natural gas~~ and ~~NGLs~~individuals ~~are~~to ~~constantly~~slow ~~evolving~~the ~~and~~spread ~~remain~~of ~~uncertain. In~~the ~~addition~~pandemic, the ~~dramatic~~ability ~~decrease~~of inpharmaceutical ~~oil~~companies ~~and~~to develop ~~gas~~effective ~~prices~~and ~~could~~safe ~~have~~vaccines ~~substantial~~and ~~negative~~therapeutic ~~implications~~drugs, ~~for~~the ~~our~~duration ~~revenue~~of ~~sources that~~the ~~are~~outbreak, ~~related~~actions totaken ~~or underpinned~~ by ~~commodity~~customers, ~~prices.~~suppliers and Asother athird ~~result~~parties, ~~these~~workforce ~~factors~~availability, ~~could~~and ~~have~~the atiming ~~material~~and ~~adverse~~extent ~~effect~~to onwhich ~~our business,~~normal ~~future~~economic ~~results~~and ofoperating ~~operations,~~conditions ~~financial position or cash flows~~resume.

2318

~~For~~Oil ~~example,~~Pricing in March 2020, the OPEC price war, together with the decline in demand due to slowed economic conditions attributable to COVID-19, contributed to a decline in the price of crude oil from $61.14 per barrel on December 31, 2019 to $20.48 per Bbl on March 31, 2020. The following table highlights the quarterly average of NYMEX oil and natural gas prices for the last five calendar quarters: Environment

	2020		2019
	Q1		Q1		Q2		Q3		Q4
Oil (Bbl)	$	45.78	$	54.90	$	59.96	$	56.43	$	56.87
Natural Gas (MMBtu)	$	1.90	$	3.00	$	2.57	$	2.38	$	2.40

In the midst of the ongoing COVID-19 pandemic, oil prices declined significantly due to potential increases in supply emanating from the disagreement on production cuts among members of OPEC and certain non-OPEC, oil-producing countries. The resulting supply and demand imbalance is having disruptive impacts on the oil and natural gas exploration and production industry and on other industries that serve exploration and production companies. These industry conditions, coupled with those resulting from the COVID-19 pandemic, could lead to significant global economic contraction generally and in our industry in particular. Although OPEC agreed in April to cut production, there is no assurance that the agreement will continue to be observed by its parties and the responses of oil and gas producers to the lower demand for, and price of, oil, natural gas and NGLs are constantly evolving and remain uncertain. In addition, the dramatic decrease in oil and gas prices could have substantial negative implications for our revenue sources that are related to or underpinned by commodity prices. As a result, these factors could have a material adverse effect on our business, future results of operations, financial position or cash flows.

For example, in March 2020, the OPEC price war, together with the decline in demand due to slowed economic conditions attributable to COVID-19, contributed to a decline in the price of crude oil from $61.14 per barrel on December 31, 2019 to $20.48 per Bbl on March 31, 2020. The price of crude oil has since partially recovered to $41.70 on August 4, 2020. The following table highlights the quarterly average of NYMEX oil and natural gas prices for the last six calendar quarters:

	2020				2019
	Q1		Q2		Q1		Q2		Q3		Q4

Oil (Bbl)	$	45.78	$	28.00	$	54.90	$	59.96	$	56.43	$	56.87
Natural Gas (MMBtu)	$	1.90	$	1.89	$	3.00	$	2.57	$	2.38	$	2.40

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 months ended March 31, 2020 and 2019.19

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

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

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

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

Operational Highlights

During ~~2019~~2020, we concentrated our efforts on the acquisition and development of producing properties through the prior acquisitions consummated by Carbon California ~~and Carbon Appalachia in 2018~~. Our field development activities have consisted principally of oil-related drilling, remediation and return to production and recompletion projects in California. We have focused on operating efficiencies and reduction of operating expenses, optimization of natural gas gathering and compression facilities, greater flexibility in transporting our production to markets with more favorable pricing, and the identification of development project opportunities to provide more efficient and lower-cost operations. During the second half of 2019, we executed a two-well drilling program in California, and as a result of such drilling program, one well was completed in the fourth quarter of 2019 and the other was completed during the first quarter of 2020. AsWe also completed one well in June 2020. As a result of the recent volatility and historically low oil prices, our remaining 2020 drilling program in California is under review.

24As of June 30, 2020, we owned working interests in approximately 570 gross wells (520 net), royalty interests located in California and held leasehold positions in approximately 5,200 net developed acres and approximately 11,500 net undeveloped acres. 100% of the undeveloped acreage is held by production or fee owned.

As of March 31, 2020, we owned working interests in approximately 7,200 gross wells (6,600 net), royalty interests located primarily in California, Illinois, Indiana, Kentucky, Ohio, Tennessee, Virginia, and West Virginia and held leasehold positions in approximately 313,500 net developed acres and approximately 1,254,000 net undeveloped acres. Approximately 70% of the undeveloped acreage is held by production and of the remaining undeveloped acreage, approximately 88% 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.

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.

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 natural gas processing facility, or in case of oil, into a tank battery or pipeline from which sales of oil are made.

●

Production and property taxes. Production and property taxes consist of severance, property and ad valorem taxes. Production and severance taxes 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. 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.

●

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

●

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

●

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, marketing, development and acquisition operations, franchise taxes, audit, tax, legal and other professional fees and legal compliance.

●

Interest expense. We finance a portion of our working capital requirements for drilling and completion activities and acquisitions with borrowings under our bank credit facilities. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. 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 until 2023 tangible drilling costs 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.

Results of Operations

~~Three~~The ~~Months~~results ~~Ended~~of ~~March~~operations ~~31,~~are ~~2020 Compared~~inclusive toof ~~Three~~the ~~Months~~Appalachia ~~Ended March 31, 2019~~Divestiture.

The following discussion and analysis relates to items that have affected our results of operations for the three months ended March 31, 2020 and 2019. 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.21

	Three Months Ended
	March 31,						Percent
(in thousands, except production and per unit data)	2020			2019			Change
Revenue:
Natural gas sales	$	8,434		$	19,316			(56	%)
Natural gas liquids sales		152			247			(38	%)
Oil sales		7,216			8,989			(20	%)
Transportation and handling		633			734			(14	%)
Marketing gas sales		6,318			4,944			28	%
Commodity derivative gain (loss)		19,714			(9,306	)		*
Other income		(2	)		26			*
Total revenues		42,465			24,950			70	%
Expenses:
Lease operating expenses		7,372			6,616			11	%
Pipeline operating expenses		2,692			3,085			(13	%)
Transportation costs		2,576			1,669			54	%
Production and property taxes		10			2,010			(100	%)
Marketing gas purchases		3,472			6,302			(45	%)
General and administrative		3,303			4,689			(30	%)
Depreciation, depletion and amortization		3,811			3,980			(4	%)
Accretion of asset retirement obligations		478			394			21	%
Total expenses		23,714			28,745			(18	%)
Operating income (loss)	$	18,751		$	(3,795	)		*
Other income and (expense):
Interest expense		(2,872	)		(2,914	)		*
Equity investment income		(421	)		19			*
Total other expense	$	(3,293	)	$	(2,895	)		*
Production data:
Natural gas (Mcf)		5,240,381			5,544,052			(5	%)
Oil (Bbl)		146,525			147,492			(1	%)
Natural gas liquids (Bbl)		12,363			13,210			(6	%)
Combined (Mcfe)		6,193,709			6,508,264			(5	%)
Average prices before effects of hedges:
Natural gas (per Mcf)	$	1.61		$	3.48			(54	%)
Oil (per Bbl)	$	49.24		$	60.95			(19	%)
Natural gas liquids (per Bbl)	$	12.30		$	18.67			(34	%)
Combined (per Mcfe)	$	2.55		$	4.39			(42	%)
Average prices after effects of hedges**:
Natural gas (per Mcf)	$	2.18		$	3.34			(35	%)
Oil (per Bbl)	$	49.85		$	63.29			(21	%)
Natural gas liquids (per Bbl)	$	12.30		$	18.67			(34	%)
Combined (per Mcfe)	$	3.04		$	4.32			(30	%)
Average costs (per Mcfe):
Lease operating expenses	$	1.19		$	1.02			17	%
Transportation costs	$	0.42		$	0.26			62	%
Production and property taxes	$	0.00		$	0.31			(100	%)
Cash-based general and administrative expenses	$	0.50		$	0.69			(27	%)
Depreciation, depletion and amortization	$	0.61		$	0.61			0	%

The following discussion and analysis relates to items that have affected our results of operations for the three and six months ended June 30, 2020 and 2019. The following tables set 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, 2020 Compared to the Three Months Ended June 30, 2019

	Three Months Ended
	June 30,						Percent
(in thousands, except production and per unit data)	2020			2019			Change
Revenue:
Natural gas sales	$	4,138		$	14,216			(71	%)
Natural gas liquids sales		49			195			(75	%)
Oil sales		3,767			9,902			(62	%)
Transportation and handling		274			322			(15	%)
Marketing gas sales		2,380			3,221			(26	%)
Commodity derivative gain (loss)		(5,647	)		8,680			*
Other income		2			305			*
Total revenues		4,963			36,841			(87	%)

Expenses:
Lease operating expenses		5,086			7,480			(32	%)
Pipeline operating expenses		1,432			2,950			(51	%)
Transportation costs		1,475			1,130			31	%
Production and property taxes		1,136			1,666			(32	%)
Marketing gas purchases		1,329			4,795			(72	%)
General and administrative		5,402			3,947			37	%
Depreciation, depletion and amortization		2,149			3,881			(45	%)
Accretion of asset retirement obligations		299			405			(26	%)
Loss on Appalachia Divestiture		34,463			-			*
Total expenses		52,771			26,254			101	%

Operating income	$	(47,808	)	$	10,587			*

Other income and (expense):
Interest expense		(2,774	)		(3,445	)		*
Investments in affiliates		-			21			*
Other expense		104			-			*
Total other expense	$	(2,670	)	$	(3,424	)		*

Production data:
Natural gas (Mcf)		2,927,911			5,299,644			(45	%)
Oil (Bbl)		128,647			150,274			(14	%)
Natural gas liquids (Bbl)		11,671			11,780			(1	%)
Combined (Mcfe)		3,769,817			6,271,968			(40	%)

Average prices before effects of hedges:
Natural gas (per Mcf)	$	1.41		$	2.68			(47	%)
Oil (per Bbl)	$	29.28		$	65.89			(56	%)
Natural gas liquids (per Bbl)	$	4.22		$	16.53			(74	%)
Combined (per Mcfe)	$	2.11		$	3.88			(46	%)

Average prices after effects of hedges**:
Natural gas (per Mcf)	$	2.25		$	2.72			(17	%)
Oil (per Bbl)	$	51.86		$	60.01			(14	%)
Natural gas liquids (per Bbl)	$	4.22		$	16.53			(74	%)
Combined (per Mcfe)	$	3.53		$	3.77			(6	%)

Average costs (per Mcfe):
Lease operating expenses	$	1.35		$	1.19			13	%
Transportation costs	$	0.39		$	0.18			117	%
Production and property taxes	$	0.30		$	0.27			11	%
Cash-based general and administrative expenses	$	0.60		$	0.59			0	%
Depreciation, depletion and amortization	$	0.57		$	0.62			(8	%)

*	Not meaningful or applicable
**	Includes effect of settled commodity derivative gains and losses

2622

Natural gas sales, natural gas liquids, sales, and oil sales – Sales of natural gas, natural gas liquids and oil decreased approximately $1016.94 million for the three months ended ~~March~~June 3130, 2020 compared to the same period in 2019, primarily due to a 4246% decrease in combined product pricing ~~and~~, a 540% decrease in natural gas, natural gas liquids and oil sales volumes and the impact from the Appalachia Divestiture.

Transportation and handling – Revenue from transportation and handling correlates to the price of natural gas, which decreased 5415% compared to the same period in 2019.

Marketing gas sales – Sales from marketing gas ~~increased~~decreased $~~1.4~~842,000 ~~million~~ primarily due to the ansale ~~additional~~of storage ~~facility~~facilities and related contracts to DGOC with the Appalachia Divestiture.

Commodity derivative gain (loss) – We do not designate our commodity derivatives as cash flow hedges; therefore, they do not receive hedge accounting treatment and all mark-to-market gains or losses, as well as settlement gains or losses on the derivative instruments, are currently recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these contracts as oil and natural gas futures prices fluctuate relative to the fixed price we will receive from these contracts. For the three months ended ~~March~~June 3130, 2020 and 2019, we had hedging ~~gains~~losses of approximately $195.76 million and hedging ~~losses~~gains of approximately $98.3 7 million, respectively. Our derivative gain or loss is primarily due to fair market value adjustments caused by market prices ~~being~~ being lower or higher than our contracted hedged prices.

Lease operating expenses and pipeline operating expenses – Lease operating expenses ~~increased~~and pipeline operating expenses decreased $~~756,000~~2.4 million and $1.5 million for the three months ended ~~March~~June 3130, 2020, respectively, primarily due to ~~increasing~~the ~~insurance costs~~impact ~~and~~from ~~employee benefits, as well as~~ the ~~timing~~Appalachia ~~of non-operated property expenses in 2020 versus 2019~~Divestiture.

~~Pipeline~~Transportation ~~operating~~costs ~~expenses~~ – Transportation ~~Pipeline~~costs ~~operating~~increased ~~expenses decreased~~ $~~393~~345,000 for the three months ended ~~March~~June 3130, 2020 asprimarily due to a ~~result~~one-time ofbenefit ~~operational~~in ~~focus~~2019 associated onwith ~~efficiency~~revisions ~~and~~to ~~expense~~prior ~~reduction measures~~estimates.

27Production and property taxes – Production and property taxes decreased $530,000 for the three months ended June 30, 2020 due to decreased ad valorem estimated tax rates and decreases in commodity prices. The decrease was also attributable to a reduction in production tax rates in West Virginia in 2020. Production taxes averaged approximately 7.8% and 3.9% of product sales for the three months ended June 30, 2020 and 2019, respectively. Production taxes associated with oil production are generally lower on a per Mcfe basis versus gas production. Oil production accounted for approximately 20% and 14% of our production mix for the three months ended June 30, 2020 and 2019, respectively.

~~Transportation~~Marketing ~~costs~~gas –purchases ~~Transportation~~– ~~costs~~Marketing ~~increased~~gas ~~$907,000~~purchases ~~for~~decreased ~~the~~$3.5 ~~three~~million ~~months ended March 31, 2020~~ primarily due to athe ~~one-time~~decrease ~~benefit~~in ~~associated with~~natural ~~revisions~~gas topricing ~~prior~~and ~~estimates~~the Appalachia Divestiture.

~~Production~~Depreciation, depletion and ~~property taxes~~amortization (“DD&A”) – ~~Production~~DD&A ~~and property taxes~~ decreased $21.07 million for the three months ended ~~March~~June 3130, 2020 ~~due~~primarily due to ~~decreased ad valorem estimated tax rates and~~ decreases in ~~commodity~~our ~~prices.~~depletable ~~Production~~cost ~~taxes~~base ~~averaged~~as ~~approximately (1.2%) and 3.4% of product sales for the three months ended March 31, 2020 and 2019, respectively. Production taxes associated with oil production are generally lower on~~ a ~~per~~result ~~Mcfe basis versus gas production. Oil production accounted for approximately 14%~~ of ~~our production mix for~~ the ~~three~~ ~~months~~Appalachia ~~ended March 31, 2020 and 2019~~Divestiture.

~~Marketing~~General ~~gas~~and ~~purchases~~administrative expenses – ~~Marketing~~General ~~gas~~and ~~purchases~~administrative ~~decreased~~expenses increased $21.85 million for the three months ended June 30, 2020 primarily due to an increase in stock-based compensation of $3.2 million, offset by $1.7 million due to company-wide focus on cost reductions and efficiencies, reduced headcount and decreased reliance on consultants. Cash-based general and administrative expenses for the ~~decrease~~three months ended June 30, 2020 and 2019 are summarized in ~~natural~~the ~~gas~~following ~~pricing.~~table:

Depreciation, depletion and amortization (“DD&A”) – DD&A decreased $169,000 for the three months ended March 31, 2020 primarily due to decreases in our depletable cost base.

General and administrative expenses	Three Months Ended June 30,
(in thousands)	2020			2019

General and administrative expenses	$	5,402		$	3,947
Adjustments:
Stock-based compensation		(3,151	)		(224	)
Cash-based general and administrative expense	$	2,251		$	3,723

~~General~~Interest ~~and~~expense ~~administrative expenses~~ – Interest ~~General~~expense, ~~and~~net ~~administrative expenses~~ decreased $~~1.4~~670,000 ~~million~~ for the three months ended ~~March~~June 3130, 2020, primarily due to alower ~~company-wide~~outstanding ~~focus~~debt ~~on cost reductions and efficiencies, including decreased reliance on consultants. Cash-based~~balances ~~general~~ and ~~administrative expenses for~~ the ~~three~~repayment ~~months~~of ~~ended~~debt ~~March~~with ~~31,~~proceeds ~~2020~~from ~~and 2019 are summarized in~~ the ~~following~~Appalachia ~~table:~~Divestiture.

General and administrative expenses	Three Months Ended March 31,
(in thousands)	2020		2019
General and administrative expenses	$	3,303	$	4,689
Adjustments:
Stock-based compensation		204		222
Cash-based general and administrative expense	$	3,099	$	4,467

~~Interest~~Six ~~expense~~Months –Ended ~~Interest expense,~~June ~~net decreased $42~~30,~~000~~ ~~for~~2020 ~~the~~Compared to ~~three~~Six ~~months~~Months ~~ended~~Ended ~~March~~June 3130, ~~2020, primarily due to lower outstanding debt balances.~~2019

	Six Months Ended
	June 30,						Percent
(in thousands, except production and per unit data)	2020			2019			Change
Revenue:
Natural gas sales	$	12,572		$	33,532			(63	%)
Natural gas liquids sales		201			441			(54	%)
Oil sales		10,982			18,891			(42	%)
Transportation and handling		908			1,056			(14	%)
Marketing gas sales		8,698			8,165			7	%
Commodity derivative gain (loss)		14,067			(627	)		*
Other income		-			697			*
Total revenues		47,428			62,155			(24	%)

Expenses:
Lease operating expenses		12,458			14,095			(12	%)
Pipeline operating expenses		4,125			6,035			(32	%)
Transportation costs		4,052			2,799			45	%
Production and property taxes		1,146			3,676			(69	%)
Marketing gas purchases		4,801			11,097			(57	%)
General and administrative		8,702			8,636			(1	%)
Depreciation, depletion and amortization		5,960			7,860			(24	%)
Accretion of asset retirement obligations		777			799			(3	%)
Loss on Appalachia Divestiture		34,463			-			*
Total expenses		76,484			54,997			39	%

Operating (loss) income	$	(29,056	)	$	7,158			*

Other income and (expense):
Interest expense		(5,647	)		(6,725	)		*
Investments in affiliates		(421	)		40			*
Other income		104			-			*
Total other expense	$	(5,964	)	$	(6,685	)		*

Production data:
Natural gas (Mcf)		8,174,941			10,843,696			(25	%)
Oil (Bbl)		275,172			297,766			(8	%)
Natural gas liquids (Bbl)		24,034			24,990			(4	%)
Combined (Mcfe)		9,970,175			12,780,232			(22	%)

Average prices before effects of hedges:
Natural gas (per Mcf)	$	1.54		$	3.09			(50	%)
Oil (per Bbl)	$	39.91		$	63.44			(37	%)
Natural gas liquids (per Bbl)	$	8.38		$	17.66			(53	%)
Combined (per Mcfe)	$	2.38		$	4.14			(43	%)

Average prices after effects of hedges**:
Natural gas (per Mcf)	$	2.20		$	3.09			(29	%)
Oil (per Bbl)	$	50.79		$	62.85			(19	%)
Natural gas liquids (per Bbl)	$	8.38		$	17.66			(53	%)
Combined (per Mcfe)	$	3.23		$	4.12			(22	%)

Average costs (per Mcfe):
Lease operating expenses	$	1.25		$	1.10			14	%
Transportation costs	$	0.41		$	0.22			86	%
Production and property taxes	$	0.11		$	0.29			(62	%)
Cash-based general and administrative expenses	$	0.54		$	0.64			(16	%)
Depreciation, depletion and amortization	$	0.60		$	0.62			(3	%)

*	Not meaningful or applicable
**	Includes effect of settled commodity derivative gains and losses

Natural gas sales, natural gas liquids sales, and oil sales – Sales of natural gas, natural gas liquids and oil decreased approximately $29.1 million for the six months ended June 30, 2020 compared to the same period in 2019, primarily due to a 43% decrease in combined product pricing, a 22% decrease in natural gas, natural gas liquids and oil sales volumes and the impact from the Appalachia Divestiture.

Transportation and handling – Revenue from transportation and handling correlates to the price of natural gas, which decreased 14% compared to the same period in 2019.

Marketing gas sales – Sales from marketing gas increased $533,000 primarily due to the sale of storage facilities and related contracts to DGOC with the Appalachia Divestiture.

Commodity derivative gain (loss) – We do not designate our commodity derivatives as cash flow hedges; therefore, 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, 2020 and 2019, we had hedging gains of approximately $14.1 million and hedging losses of approximately $627,000, respectively. Our derivative gain or loss is primarily due to fair market value adjustments caused by market prices being lower or higher than our contracted hedged prices.

Lease operating expenses and pipeline operating expenses – Lease operating expenses and pipeline operating expenses decreased $1.6 million and $1.9 million for the six months ended June 30, 2020, respectively, primarily due to the impact from the Appalachia Divestiture.

Transportation costs – Transportation costs increased $1.2 million for the six months ended June 30, 2020 primarily due to a one-time benefit in 2019 associated with revisions to prior estimates.

Production and property taxes – Production and property taxes decreased $2.5 million for the six months ended June 30, 2020 due to decreased ad valorem estimated tax rates and decreases in commodity prices. The decrease was also attributable to a reduction in production tax rates in West Virginia in 2020. Production taxes averaged approximately 1.8% and 3.7% of product sales for the six months ended June 30, 2020 and 2019, respectively. Production taxes associated with oil production are generally lower on a per Mcfe basis versus gas production. Oil production accounted for approximately 17% and 14% of our production mix for the six months ended June 30, 2020 and 2019, respectively.

Marketing gas purchases – Marketing gas purchases decreased $6.3 million primarily due to the decrease in natural gas pricing and the Appalachia Divestiture.

Depreciation, depletion and amortization (“DD&A”) – DD&A decreased $1.9 million for the six months ended June 30, 2020 primarily due to decreases in our depletable cost base as a result of the Appalachia Divestiture.

General and administrative expenses – General and administrative expenses increased $67,000 for the six months ended June 30, 2020 primarily due to an increase in stock-based compensation of $3.4 million, offset by a company-wide focus on cost reductions and efficiencies, reduced headcount and decreased reliance on consultants. Cash-based general and administrative expenses for the six months ended June 30, 2020 and 2019 are summarized in the following table:

General and administrative expenses	Six Months Ended June 30,
(in thousands)	2020			2019

General and administrative expenses	$	8,702		$	8,636
Adjustments:
Stock-based compensation		(3,355	)		(446	)
Cash-based general and administrative expense	$	5,347		$	8,190

Interest expense – Interest expense, net decreased $1.1 million for the six months ended June 30, 2020, primarily due to lower outstanding debt balances and the repayment of debt with proceeds from the Appalachia Divestiture.

Liquidity and Capital Resources

Our primary sources of liquidity and capital resources are cash flows from operations, and borrowings under ~~our credit facilities and~~ Carbon California’s Senior Secured Revolving Notes ~~issued to Prudential with an initial revolving borrowing capacity of $25.0 million~~ which mature on February 15, 2022 (the “Senior Revolving Notes”), and on occasion, the sale of non-core assets. Borrowings ~~under~~ under the ~~credit facilities and~~ Senior Revolving Notes may be used to fund field development projects and to fund future complementary ~~acquisitions~~ 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 financial flexibility.

As of ~~March~~June 3130, 2020, our liquidity was $121.0 3 million, consisting of cash on hand, ofexcluding ~~$1.7~~restricted ~~million and $10~~cash.3 ~~million of available borrowing capacity on the Senior Revolving Notes.~~ On April 1, 2020, the borrowing base on the Senior Revolving Notes was redetermined and reduced to $40.0 million, and as of June 30, 2020 $37.2 million was outstanding. Effective June 30, 2020, and through December 31, 2020, Prudential is no longer obligated to make advances under the Senior Revolving Notes.

OnPaycheck ~~February~~Protection ~~14,~~Program 2020, we amended our 2018 Credit Facility, resulting in a borrowing base of $73.0 million with subsequent borrowing base reductions totaling $6.0 million scheduled through May 1, 2020. As of March 31, 2020, the 2018 Credit Facility had a borrowing base of $71.0 million.Loan

AsIn ofMay ~~March~~2020, 31the Company received the PPP Loan under the PPP. The PPP, ~~2020~~established as part of the CARES Act, ~~there~~provides ~~was~~for ~~approximately~~loans ~~$70.2~~to ~~million~~qualifying inbusinesses ~~outstanding~~for amounts ~~borrowings~~up to 2.5 times the average monthly payroll expenses of the qualifying business. The PPP Loan and noaccrued ~~borrowing~~interest ~~capacity~~are ~~available~~forgivable after ~~under~~24 weeks as long as the ~~2018~~borrower ~~Credit~~uses ~~Facility~~the loan proceeds for documented eligible purposes, ~~after~~including ~~considering~~payroll, ~~letters~~benefits, ofrent and ~~credit~~utilities, ~~outstanding~~and maintains its payroll levels. As For purposes of ~~March~~the ~~31,~~PPP ~~2020~~Loan, wepayroll ~~were~~costs ~~not~~exclude incash ~~compliance~~compensation ~~with~~of ~~our~~an ~~current~~individual employee ~~ratio~~in ~~financial~~excess ~~covenant.~~of ~~However~~$100,000, weprorated ~~anticipate~~annually. aNot ~~full~~more ~~payoff~~ than 40% of the ~~2018~~forgiven ~~Credit~~amount ~~Facility~~may asbe afor ~~result~~non-payroll costs. The amount of ~~Contemplated~~loan ~~Transactions~~forgiveness ~~described~~will inbe ~~Note~~reduced 15if ~~prior~~the toborrower ~~any~~terminates ~~potential~~full-time ~~event~~employees or reduces salaries and wages for employees with salaries of ~~default~~$100,000 or less annually by more than 25% during the 24-week period.

OnThe ~~April~~PPP ~~30,~~Loan ~~2020,~~is weevidenced ~~further~~by ~~amended our~~the ~~2018~~PPP ~~Credit Facility~~Note, which ~~extending~~contains ~~the~~customary ~~remaining~~events ~~borrowing~~of ~~base~~default ~~reductions~~relating ~~totaling~~to, ~~$4.0~~among ~~million~~other tothings, ~~June~~payment 1,defaults ~~2020~~and inbreaches ~~anticipation~~ of arepresentations ~~full~~and warranties, ~~payoff~~and ofbears ~~the~~interest ~~2018~~at ~~Credit~~1.0% ~~Facility~~per asannum. aNo ~~result~~payments of ~~the~~principal ~~pending~~or ~~Contemplated~~interest ~~Transactions~~are due during the Deferral Period.

28The Company intends to use the proceeds for purposes consistent with the PPP. In order to obtain full or partial forgiveness of the PPP Loan, the Company must request forgiveness and must provide satisfactory documentation in accordance with applicable SBA guidelines. Interest payable on the PPP Note may be forgiven only if the SBA agrees to pay such interest on the forgiven principal amount of the PPP Note. The Company will be obligated to repay any portion of the principal amount of the PPP Note that is not forgiven, together with interest accrued and accruing thereon at the rate set forth above, until such unforgiven portion is paid in full.

InBeginning ~~March~~one ~~2020,~~month following expiration of the ~~Coronavirus~~Deferral ~~Aid~~Period, ~~Relief~~ and ~~Economic~~ ~~Security~~continuing ~~Act~~monthly ~~(“CARES~~until ~~Act”)~~the ~~was~~Maturity ~~signed~~Date, ~~into~~the ~~law~~Company inis ~~the~~obligated ~~United~~to ~~States. It~~make ismonthly ~~intended~~payments of principal and interest to ~~provide~~the ~~economic~~Lender ~~relief~~with respect to ~~individuals~~any ~~and~~unforgiven ~~businesses~~portion ~~affected~~of by the ~~coronavirus~~PPP ~~pandemic.~~Note, Wein ~~are~~such inequal ~~the~~amounts ~~process~~required ofto ~~applying~~fully amortize ~~for~~the ~~potential~~principal ~~funding~~amount ~~that~~outstanding ~~may~~on bethe ~~available~~PPP toNote as of the ~~Company~~last ~~under~~day of the ~~CARES~~Deferral ~~Act~~Period orby ~~other~~the ~~recently~~Maturity ~~enacted~~Date. ~~programs;~~The ~~however,~~Company ~~there~~ is permitted noto ~~guarantee~~prepay ~~that~~the ~~such~~PPP ~~funds~~Note ~~will~~at beany ~~received~~time without payment of any prepayment premium or penalty.

On April 7, 2020, Carbon Energy Corporation, together with Nytis USA (the “Sellers”) and certain of the Company’s other direct and wholly owned subsidiaries, entered into a Membership Interest Purchase Agreement (“MIPA”) to sell all of the issued and outstanding membership interests of Carbon Appalachia and Nytis LLC to Diversified Gas & Oil Corporation (the “Purchaser”) for $110.0 million, subject to customary purchase price adjustments, and a contingent payment of up to $15.0 million (“Contemplated Transactions”). The assets contained in the Contemplated Transactions comprise all of the Company’s assets in the Appalachian and Illinois basin. If the Sellers terminate the MIPA under certain circumstances, they may be required to pay a termination fee of $3.8 million. The transaction is subject to customary conditions, including, among other things, the mailing of an information statement to the Company’s stockholders at least 20 calendar days prior to the closing date in accordance with applicable securities laws, and is expected to close during the second quarter of 2020. In accordance with Rule 14c-2 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Contemplated Transactions may not be completed until 20 calendar days after the date of mailing of an information statement to the Company’s stockholders.26

The ~~Contemplated~~CARES ~~Transactions~~Act ~~constitute~~also aprovides ~~sale~~for ~~of substantially~~deferred ~~all~~payment of the ~~Company’s~~employer ~~assets~~portion ~~under~~of ~~the~~Social ~~Delaware~~Security ~~General~~taxes ~~Corporation~~through ~~Law.~~the ~~Following~~end ~~consummation~~ of ~~the Contemplated Transactions~~2020, ~~the~~ ~~Company~~with ~~would~~50% ~~continue~~of tothe ~~own~~deferred ~~its~~amount ~~membership~~due ~~interests~~December 31, in2021 ~~Carbon California~~ and ~~continue to conduct operations in~~ the ~~Ventura Basin~~remaining in50% ~~California.~~due ~~Notwithstanding~~December ~~the foregoing~~31, ~~the Company’s Board of Directors is continuously evaluating strategic alternatives for the Company’s business in light of current market and industry conditions~~2022.

~~Upon~~Appalachia ~~consummation~~Divestiture of the Contemplated Transactions, net of expected purchase price adjustments, the Sellers expect to receive cash proceeds of $105 million, of which $3.3 million will be deposited in an escrow account to support the Sellers’ indemnification obligations and, subject to certain exceptions, released on the 18-month anniversary of the closing. The Sellers intend to use approximately $75.0 million of the proceeds to repay outstanding indebtedness, including accrued interest, under the 2018 Credit Facility, ~~approximately $10.0 million to pay estimated transaction expenses, including legal, accounting~~ and ~~severance and other employment-related costs, and approximately $12.7 million to pay indebtedness under the~~ Old Ironsides Notes. Nytis USA will retain the remaining proceeds, but to the extent these funds are in excess of those required in the operations of Nytis USA, it may distribute those funds to the Company who may use them for general corporate purposes, including the repayment of indebtedness. Yorktown, as the holder of all of the Series B convertible preferred stock, has waived its right to be paid a liquidating distribution of approximately $5.6 million in connection with the closing of the Contemplated Transactions until the payment in full of the Old Ironsides Notes or the earlier termination or cancellation of the Old Ironsides Notes, at which point the liquidating distribution will become immediately due and payable by the Company out of Company’s assets legally available for distribution to its stockholders. Ongoing general and corporate operations will be funded by management fees paid to the Company by Carbon California of approximately $1.2 million annually as well as any proceeds received from the contingent payment associated with the Contemplated Transactions. The contingent payment of up to $15.0 million in the aggregate will be calculated and paid yearly by January 5 of each of 2021, 2022 and 2023 based on the contingent payment calculation for calendar years 2020, 2021 and 2022.

On April 7, 2020, Carbon Energy Corporation, together with Nytis USA (the “Sellers”) and certain of the Company’s other direct and wholly owned subsidiaries, entered into a Membership Interest Purchase Agreement (“MIPA”) to sell all of the issued and outstanding membership interests of Carbon Appalachia and Nytis LLC to Diversified Gas & Oil Corporation (the “Purchaser” or “DGOC”) for $110.0 million, subject to customary purchase price adjustments, and a contingent payment of up to $15.0 million (the “Appalachia Divestiture”). The transaction closed on May 26, 2020. The assets comprised substantially all of the Company’s assets in the Appalachian and Illinois basin.

The Appalachia Divestiture constitutes a sale of substantially all of the Company’s assets under the Delaware General Corporation Law. The Company continues to own its membership interests in Carbon California and continues to conduct operations in the Ventura Basin in California. Notwithstanding the foregoing, the Company’s Board of Directors is continuously evaluating strategic alternatives for the Company’s business in light of current market and industry conditions.

Upon closing of the Appalachia Divestiture, we received net cash proceeds of $98.1 million. We used these proceeds to repay in full the amounts outstanding, including interest, under the 2018 Credit Facility of approximately $72.3 million and we repaid $10.5 million under the Old Ironsides Notes. The 2018 Credit Facility was terminated on May 26, 2020.

Yorktown, as the holder of all of the Series B convertible preferred stock, has waived its right to be paid a liquidating distribution of approximately $5.6 million in connection with the closing of the Appalachia Divestiture until the payment in full of the Old Ironsides Notes or the earlier termination or cancellation of the Old Ironsides Notes, at which point the liquidating distribution will become immediately due and payable by the Company out of Company’s assets legally available for distribution to its stockholders. Ongoing general and corporate operations will be funded by management fees paid to the Company by Carbon California of approximately $1.2 million annually as well as any proceeds received from the contingent payment associated with the Appalachia Divestiture. The contingent payment of up to $15.0 million in the aggregate will be calculated and paid yearly by January 5 of each of 2021, 2022 and 2023 based on the contingent payment calculation for calendar years 2020, 2021 and 2022.

Access to additional capital within the current commodity price environment is limited and the terms of any available capital may not be acceptable to the Company.

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.

29This hedge program mitigates uncertainty regarding cash flow that we will receive with respect to a portion of our expected production through 2022. 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 2019 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 13 – Commodity Derivatives in the unaudited condensed consolidated financial statements in Item 1 for more information, including our outstanding derivatives.

This hedge program mitigates uncertainty regarding cash flow that we will receive with respect to a portion of our expected production through 2022. 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 2019 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 12 – Commodity Derivatives in the unaudited condensed consolidated financial statements in Item 1 for more information, including our outstanding derivatives.27

Sources and Uses of Cash

The following table presents net cash provided by or used in operating, investing and financing activities:

	Three Months Ended
	Six Months Ended
	March 31,
	June 30,
(in thousands)	2020			2019
Net cash provided by operating activities	$	1,277		$	8,311
Net cash (used in) provided by operating activities	$	(8,592	)	$	9,795
Net cash used in investing activities	$	(626	)	$	(336	)
Net cash provided by (used in) investing activities	$	95,714		$	(1,637	)
Net cash provided by (used in) financing activities	$	185		$	(2,695	)
Net cash used in financing activities	$	(80,003	)	$	(9,243	)

Operating Activities

Net cash ~~provided~~from by operating activities is 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~~The negative operating cash flows ~~decreased approximately $7.0 million~~ for the ~~three~~six months ended ~~March~~June 3130, 2020 ~~as compared to the same period in 2019. This decrease~~ was primarily due to the ~~decreased~~impact ~~revenues~~of the Appalachia Divestiture.

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~~provided inby investing activities increased approximately $~~290,000~~97.4 million for the ~~three months~~six months ended ~~March~~June 3130, 2020 as compared to the same period in 2019 primarily due to ~~funding~~the ~~our~~cash ~~drilling~~proceeds ~~program~~received from the Appalachia Divestiture of $98.1 million and $746,000 in ~~California~~proceeds from the sale of non-core assets, offset by development costs of $1.6 million.

Financing Activities

Net cash provided by or used in financing activities is primarily comprised of activities associated with our credit facilities. During the ~~three~~six months ended ~~March~~June 3130, 2020, the Company increased borrowings under the 2018 Credit Facility by approximately $32.0 million and increased borrowings under ~~the~~ the Senior Revolving Notes by $25.05 million. ~~These~~The Company also received proceeds from a PPP loan in the amount of $1.3 million. These advances were partially offset by payments of $210.5 million in principal associated with the Old Ironsides Notes, payments of approximately $177.0 million in principal associated with the 2018 Credit Facility, and payments of approximately $1.3 million in principal associated with the Senior Revolving Notes. During the ~~three~~six months ended ~~March~~ 31June 30, 2019, the Company ~~(i)~~ paid $2.0 million in principal associated with the Old Ironsides Notes;, ~~(ii)~~ paid approximately $16.72 million in principal associated with the 2018 Credit Facility, ~~term~~and ~~note;~~paid ~~and~~approximately ~~(iii)~~$5.0 ~~increased~~million ~~net~~in principal associated with the Senior Revolving Notes. The payments were partially offset by an increase in borrowings under the 2018 Credit Facility ~~revolver~~ by approximately $14.0 million.

Capital Expenditures

Capital expenditures incurred are summarized in the following table:

	Three Months Ended March 31,
	Six Months Ended June 30,
(in thousands)	2020		2019
Drilling and development	$	~~793~~3,236	$	~~461~~1,792
Other		~~220~~224		3971
Total capital expenditures	$	13,~~013~~460	$	~~500~~1,863

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

~~Due~~Factors to low natural gas prices, the Company 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.

Credit Facilities and Notes Payable

For a discussion of our long-term debt, see Note 67 – Credit Facilities and Notes Payable in the unaudited condensed consolidated financial statements in Item 1.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of ~~March~~June 3130, 2020.

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 2019 Annual Report on Form 10-K. As of ~~March~~June 3130, 2020, there have been no significant changes to our critical accounting policies and estimates since our 2019 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 Exchange Act. 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;

effect of the COVID-19 pandemic and the OPEC price war on our business results;

●

the timing and effectiveness of the Reverse Stock Split and the deregistration of our common stock;

●

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 2019 Annual Report on Form 10-K and our Quarterly Report on Form 10-Q for the three months ended March 31, 2020 (the “First Quarter Quarterly Report”).

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

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

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

As a smaller reporting company, we are not required to provide 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 and principal executive officer, Patrick R. McDonald, and our ~~Chief~~Senior ~~Financial~~Vice ~~Officer~~President, ~~Kevin~~Finance Dand Accounting and principal financial officer, Erich W. ~~Struzeski~~Kirsch, 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 ~~March~~June 3130, 2020. Based on this evaluation, they believe that as of ~~March~~June 3130, 2020, 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 is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and is accumulated and communicated to our management, including the Chief Executive Officer and ~~Chief~~Senior ~~Financial~~Vice ~~Officer~~President, Finance and Accounting, as appropriate, to allow timely decisions regarding required disclosures.

Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting during the quarter ended ~~March~~June 3130, 2020, that materially affected, or are reasonably likely to materially affect, our internal control ~~over~~ over financial reporting.

3231

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

In addition to the risk factors contained in the Item 1A. Risk Factors of the 2019 Annual Report on Form 10-K, ~~investors~~and ~~should~~Item ~~carefully~~1A. ~~consider~~Risk Factors of the ~~following~~First ~~risk~~Quarter ~~factors~~Quarterly Report, ~~which~~investors ~~relate~~should tocarefully consider the ~~Contemplated~~following ~~Transaction~~risk ~~discussed above~~factors. These risk factors should be read in conjunction with the risk ~~factors~~ factors set forth in our 2019 Annual Report on Form 10-K, our First Quarter Quarterly Report and other information contained in this report and our other filings with the SEC, which are hereby incorporated by reference.

~~Risks~~Carbon’s ~~Related~~operations tohave been curtailed and Carbon has limited sources of revenue after the ~~Contemplated~~Appalachia ~~Transactions~~Divestiture, which may negatively impact the value and liquidity of Carbon’s common stock.

~~The~~Upon ~~announcement~~the closing of the Appalachia Divestiture, the size of Carbon’s business operations was significantly reduced and ~~pendency~~its sources of revenue are limited to its operations in the ~~Contemplated~~Ventura ~~Transactions,~~Basin ~~whether~~through orCarbon California. Carbon does not ~~consummated~~intend to use any portion of the proceeds from the Appalachia Divestiture to support the business operations remaining, ~~may~~and ~~adversely~~there ~~affect~~can be no assurance that Carbon’s will be successful at carrying out the operations of its remaining business or that it will be successful at generating revenue. A failure by Carbon to secure additional sources of revenue could negatively impact the value and liquidity of its common stock.

The announcement and pendency of the Contemplated Transactions, whether or not consummated, may adversely affect the trading price of Carbon’s common stock, its business or its relationships with customers and suppliers. New or existing customers and business partners may prefer to do business with our competitors because of uncertainty whether the Contemplated Transactions will be consummated.

Uncertainties associated with the Contemplated Transactions may cause a loss of management personnel and other key employees, which could adversely affect the future business and operations of Carbon.

Whether or not the Contemplated Transactions are completed, the announcement and pendency of the Contemplated Transactions could disrupt the business of Carbon. Carbon is dependent on the experience and industry knowledge of its senior management and other key employees to execute its business plan. Carbon’s success after the Contemplated Transactions will depend in part upon the ability of Carbon to retain key management personnel and other key employees. Pending the completion of the Contemplated Transactions, Carbon may be unable to attract and retain key personnel and the focus and attention of Carbon’s management and employee resources may be diverted from operational matters during the pendency of the Contemplated Transactions. In addition, Carbon might not be able to locate suitable replacements for any such key employees who leave, whether to transition to employment with the Purchaser as part of the Contemplated Transactions or otherwise, or offer employment to potential replacements on satisfactory terms.

Carbon cannot be sure if or when the Contemplated Transactions will be completed.

The closing of the Contemplated Transactions is subject to the satisfaction or waiver of various conditions. Carbon cannot guarantee that the closing conditions set forth in the MIPA, some of which are beyond the control of Carbon, will be satisfied. If the closing conditions to the MIPA are not satisfied, the Purchaser or the Sellers may not be obligated to complete the Contemplated Transactions. In the event that the Contemplated Transactions are not completed, the termination of the MIPA may adversely affect the trading price of Carbon’s common stock, its business and operations or its relationships with vendors, suppliers, customers and employees. If the Contemplated Transactions are not completed for any reason, Carbon will be subject to a number of risks, including paying its costs relating to the Contemplated Transactions, which are substantial, such as legal, accounting and printing fees, whether or not the Contemplated Transactions are completed.

If the Contemplated Transactions are not completed and the 2018 Credit Facility remains outstanding, we may have difficulty complying with our Current Ratio covenant of 1.00 to 1.00 and our Leverage Ratio covenant of 3.50 to 1.00, as such terms are defined in our 2018 Credit Facility. Our ability to comply with the Current Ratio covenant is affected by borrowing base reductions totaling $6.0 million scheduled through May 1, 2020, and may be further impacted by future borrowing base redeterminations in 2020 and might also be adversely affected if we were required to pay a $3.8 million termination fee pursuant to the MIPA. Our ability to comply with our Leverage Ratio covenant would be adversely affected if the current low level of natural gas prices persist through the remainder of 2020. Our Leverage Ratio measures our Net Debt (as defined in the 2018 Credit Facility) over our EBITDAX (as defined in the 2018 Credit Facility) and we generate less EBITDAX in a low-price environment. These potential covenant compliance issues could cause doubt about our ability to continue as a going concern. Failure to comply with these covenants, if not waived, would result in an event of default and related actions under the 2018 Credit Facility.

If the Contemplated Transactions are not completed, Carbon’s board of directors may evaluate other strategic alternatives that may be available, which such alternatives may not be as favorable to Carbon or its stockholders as the Contemplated Transactions.

The MIPA contains restrictions on the conduct of Carbon’s business prior to closing.

Under the terms of the MIPA, Carbon is subject to certain restrictions on the conduct of its business prior to the closing, which may adversely affect its ability to execute certain of its business strategies. Limitations include, among other things, the ability to approve certain capital projects, dispose of the Acquired Assets (as defined in the Purchase Agreement), create any liens on the Acquired Assets, enter into or modify any employment agreements, adopt, amend, modify or terminate any benefit plan or modify or terminate any lease or material contract, in each case, subject to certain exceptions set forth in the MIPA. Such limitations could negatively affect Carbon’s business and operations prior to the completion of the Contemplated Transactions.

The MIPA limits Carbon’s ability to pursue alternatives to the Contemplated Transactions.

The MIPA contains provisions that make it more difficult for Carbon to sell its assets or engage in another type of acquisition transaction with a party other than the Purchaser. These provisions include a provision obligating Carbon to pay the Purchaser a termination fee of $3.8 million if, among other things, (i) the Sellers materially breach the solicitation obligations under the MIPA or (ii) the MIPA is terminated in connection with a Superior Proposal (as defined in the MIPA). These provisions could discourage a third party that might have an interest in acquiring all of, or substantially all of, Carbon’s assets or its common stock from considering or proposing such an acquisition, even if that party were prepared to pay consideration with a higher value than the consideration to be paid by the Purchaser.

The holder of the Old Ironsides Notes may claim that it is entitled to receive more of the proceeds of the Contemplated Transactions than we believe we are required to apply to the payment of the Old Ironsides Notes.

Under the terms of the Old Ironsides Notes, we are required to make a mandatory prepayment on the Old Ironsides Notes no later than the first business day following the date of receipt by us of any “Net Cash Proceeds,” as defined in the Old Ironsides Notes, from the sale of our assets. The mandatory prepayment must be in an amount equal to the lesser of (i) the then-outstanding obligation under the Old Ironsides Notes and (ii) the amount of such Net Cash Proceeds received by us, after repayment of amounts due under the 2018 Credit Facility and expenses incurred in connection with the Contemplated Transactions. Old Ironsides, the holder of the Old Ironsides Notes, has asserted in writing that it believes that the Net Cash Proceeds would be sufficient for us to repay the full amount outstanding under the Old Ironsides Notes, approximately $26.3 million, while we believe that the Net Cash Proceeds available to repay the Old Ironsides Notes would be approximately $12.7 million.

We are in discussions with Old Ironsides regarding the amount owed, but if the resolution of the discussions is not satisfactory to Old Ironsides, it may file a lawsuit claiming that it is entitled to receive more than what we believe is owed, including and up to the full amount of the Old Ironsides Notes. If we were required by a court to pay such a judgment in excess of what we believe is owed, as well as costs to defend any such claims, we may not have the cash on hand or ability to raise the funds necessary to pay such amounts. Furthermore, given the scope of our operations post-transaction and the state of the industry and energy capital markets, we expect that it would be very difficult for us to raise additional capital to pay a judgment and legal costs. Therefore, a judgment against us in an amount greater than we believe we owe on the Old Ironsides Notes could make it necessary for us to seek protection from creditors under Chapter 11 of the U.S. Bankruptcy Code, or an involuntary petition for bankruptcy may be filed against us.

Carbon will incur significant expenses in connection with the Contemplated Transactions, regardless of whether the Contemplated Transactions are completed and, in certain circumstances, may be required to pay a termination fee to the Purchaser.

Carbon expects to incur significant expenses related to the Contemplated Transactions. These expenses include, but are not limited to, legal fees, accounting fees and expenses, certain employee expenses, filing fees, printing expenses and other related fees and expenses. Many of these expenses will be payable by Carbon regardless of whether the Contemplated Transactions are completed. In addition, if the MIPA is terminated in certain circumstances, Carbon will be required to pay the Purchaser a $3.8 million termination fee.

Carbon expects to record a loss at the closing of the Contemplated Transactions.

Upon the consummation of the Contemplated Transactions, Carbon expects to record a book loss of approximately $50.1 million. If the Contemplated Transactions are not completed, Carbon may be required to take an impairment charge related to the Appalachian assets. GAAP requires us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments, which may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore requires a write-down. Future write-downs of our full cost pool may be required if oil and natural gas prices decline, unproved property values decrease, estimated proved reserve volumes are revised downward or costs incurred in exploration, development, or acquisition activities in our full cost pool exceed the discounted future net cash flows from the additional reserves, if any, attributable to our cost pool. Any recorded impairment is not reversible.

In connection with the Contemplated Transactions, the Sellers will indemnify the Purchaser and the Purchaser will indemnify the Sellers for certain liabilities. There can be no assurance that the indemnities from the Sellers will be sufficient to insure the Purchaser against the full amount of such liabilities.

Pursuant to the MIPA, the Sellers agreed to indemnify the Purchaser for certain liabilities, and the Purchaser agreed to indemnify the Sellers for certain liabilities. The Sellers will indemnify the Purchaser for claims, proceedings and losses relating to retained liabilities, a breach of the MIPA by the Sellers and certain other matters set forth in the Purchase Agreement, and the Purchaser will indemnify the Sellers for claims, proceedings and losses relating to the assumed liabilities, including ownership of Nytis LLC and Carbon Appalachia on or after the closing, and a breach of the MIPA by the Purchaser. However, third parties might seek to hold the Sellers responsible for liabilities that the Purchaser agreed to assume, and there can be no assurance that the Sellers will be able to fully satisfy its indemnification obligations under the MIPA, which could be significant and could adversely affect our business.

Risks Related to Carbon’s Future Operations

Carbon’s operations will be curtailed and Carbon will have limited sources of revenue following the Contemplated Transactions, which may negatively impact the value and liquidity of Carbon’s common stock.

Upon the closing of the Contemplated Transactions, the size of Carbon’s business operations will be significantly reduced and its sources of revenue will be limited to its operations in the Ventura Basin through Carbon California. Carbon does not intend to use any portion of the proceeds from the Contemplated Transactions to support the business operations remaining following the Contemplated Transactions, and there can be no assurance that Carbon will be successful at carrying out the operations of its remaining business or that it will be successful at generating revenue. A failure by Carbon to secure additional sources of revenue following the closing of the Contemplated Transactions could negatively impact the value and liquidity of its common stock.

Carbon will continue to incur the expense of complying with public company reporting requirements following the closing of the Contemplated Transactions.

After the Contemplated Transactions, Carbon will continue to be required to comply with the applicable reporting requirements of the Exchange Act, even though compliance with such reporting requirements is economically burdensome.

Carbon’s common stock may be removed from trading on OTCQB following the consummation of the Contemplated Transactions.

Carbon’s SEC reporting obligations as a public company will not be impacted as a result of the closing of the Contemplated Transactions and, following the completion of the Contemplated Transactions, Carbon expects that its common stock will continue to be quoted on OTCQB. However, it is not possible to predict the trading price of Carbon’s common stock following the closing of the Contemplated Transactions or the impact that the Contemplated Transactions may have on Carbon’s remaining business.

In order to remain eligible for trading on OTCQB, Carbon’s common stock must comply with certain standards for continued eligibility, including:

● a minimum closing bid price of at least $0.01 per share on at least one of the prior thirty consecutive calendar days;

● at least 50 beneficial holders, each owning at least 100 shares; and

● freely traded public float of at least 10% of the total shares of common stock issued and outstanding.

Carbon believes that it will continue to meet OTCQB’s standards for continued eligibility following the completion of the Contemplated Transactions. No assurances, however, can be given that Carbon will continue to satisfy these requirements as some of these requirements are outside of Carbon’s direct control, such as the bid price of its common stock, the number of holders of its common stock and the value of its publicly held shares. If Carbon is unable to meet these requirements, OTCQB may take action to remove Carbon’s common stock from trading on OTCQB.

The removal of Carbon’s common stock from trading on OTCQB could result in a reduction in its trading price and would substantially limit the liquidity of Carbon’s common stock. In addition, removal could materially adversely impact Carbon’s ability to raise capital or pursue strategic restructuring, refinancing or other transactions. The removal of Carbon’s common stock from trading on OTCQB could also have other negative results, including the potential loss of confidence by institutional investors.

Carbon is a holding company with no oil and gas operations of its own, and Carbon depends on its subsidiaries for cash to fund certain of its operations and expenses.

Carbon’s operations are conducted entirely through its subsidiaries, and its ability to generate cash to meet its operating obligations is dependent on the earnings and the receipt of funds from its subsidiaries through distributions or intercompany loans. ~~Following the consummation of the Contemplated Transactions,~~ Carbon California ~~will~~is be Carbon’s sole operating subsidiary. Carbon California’s ability to generate adequate cash depends on a number of factors, including development of reserves, successful acquisitions of complementary properties, advantageous drilling conditions, oil and natural gas prices, compliance with all applicable laws and regulations and other factors.

We do not solely control Carbon California.

~~Following~~As ~~the consummation~~ of ~~the~~June ~~Contemplated Transactions~~30, 2020, we ~~will~~ have no significant assets other than our ownership interest in Carbon California, which owns and operates oil, natural gas, and NGLs interests. More specifically:

●

Carbon California is managed by its governing board. Our ability to influence decisions with respect to its operations varies depending on the amount of control we exercise under the governing agreement;

●

We do not control the amount of cash distributed by Carbon California. Further, debt facilities at Carbon California currently restrict distributions. We may influence the amount of cash distributed through our board seats on Carbon California’s governing board, but may not ultimately be successful in such efforts;

●

We may not have the ability to unilaterally require Carbon California to make capital expenditures, and Carbon California may require us to make additional capital contributions to fund operating and maintenance expenditures, as well as to fund expansion capital expenditures, which would reduce the amount of cash otherwise available for dividend payments by us or require us to incur additional indebtedness;

●

Carbon California may incur additional indebtedness without our consent, which debt payments would reduce the amount of cash that might otherwise be available for distributions; and

● The ~~third-party~~ operator of certain of the assets held by Carbon California and the identity of our partners could change, in some cases without our consent. Our dependence on the operators of such assets and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could have a material adverse effect on the realization of our targeted returns on capital or lead to unexpected future costs.

Due to our lack of asset and geographic diversification, adverse developments in our operating areas would reduce our ability to pay dividends on shares of our common stock.

~~Upon~~As ~~closing~~ of ~~the~~June ~~Contemplated~~30, ~~Transactions~~2020, all of our assets were ~~will be~~ located exclusively in the Ventura Basin in California. Due to our lack of diversification in asset type and location, an adverse development in the oil and gas business in the Ventura Basin, including those resulting from the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by and costs associated with governmental regulation, processing or transportation capacity constraints, market limitations, water shortages, wildfires or other weather related conditions, interruption of the processing or transportation of oil, NGLs or natural gas and changes in regional and local political regimes and regulations, would have a significantly greater impact on our results of operations and cash available for dividend payments on shares of our common stock than if we maintained more diverse assets and locations.

~~Our~~We ~~operations~~may ~~are~~not ~~currently~~be ~~conducted in~~able ~~locations~~to ~~that~~generate ~~may~~sufficient cash beto atmanage ~~risk~~our ofbusiness ~~damage~~and ~~from~~satisfy ~~fire,~~our ~~mudslides,~~obligations ~~earthquakes~~to orOld ~~other~~Ironsides ~~natural~~and ~~disasters~~Yorktown.

~~Carbon~~Following ~~California~~the ~~currently~~closing ~~conducts~~of ~~operations~~the Appalachia inDivestiture, ~~California~~we ~~near~~have ~~known~~limited ~~wildfire~~remaining ~~and~~sources ~~mudslide~~of ~~areas~~cash ~~and~~available ~~earthquake~~to ~~fault~~manage ~~zones.~~our ~~Certain~~business ofand ~~Carbon~~pay ~~California’s~~our ~~operations were~~liabilities, ~~temporarily~~including ~~halted~~the Old inIronsides ~~December~~Notes ~~2017~~and ~~due to~~ the ~~wildfires~~liquidating indistribution ~~southern~~to ~~California~~Yorktown. ~~A future natural disaster~~Yorktown, ~~such~~ as athe ~~fire, mudslide~~holder orof anall ~~earthquake,~~of ~~could~~the ~~cause~~Series ~~substantial~~B ~~delays~~convertible ~~in our operations~~preferred stock, ~~damage~~waived orits ~~destroy~~right ~~equipment, prevent or delay transport of production and cause us~~ to ~~incur~~be ~~additional~~paid ~~expenses,~~a ~~which~~liquidating ~~would~~distribution ~~adversely~~of ~~affect~~approximately ~~our~~$5.6 million ~~business,~~in ~~financial~~connection ~~condition~~with ~~and~~the ~~results~~closing of ~~operations.~~the InAppalachia ~~addition,~~Divestiture ~~our~~until ~~facilities~~the ~~would~~payment bein ~~difficult~~full toof ~~replace~~the ~~and~~Old ~~would~~Ironsides ~~require~~Notes ~~substantial~~or ~~lead~~the ~~time~~earlier totermination ~~repair~~ or ~~replace.~~ ~~The insurance we maintain against earthquakes, mudslides, fires and other natural disasters would not be adequate to~~cancellation ~~cover~~of athe ~~total~~Old ~~loss~~Ironsides ~~of our facilities~~Notes, ~~may~~at ~~not~~which bepoint ~~adequate~~the toliquidating ~~cover~~distribution ~~our~~will ~~losses~~become inimmediately ~~any~~due ~~particular case~~ and ~~may~~payable ~~not~~by ~~continue~~the ~~to be~~Company ~~available~~out toof usCompany’s onassets ~~acceptable~~legally ~~terms,~~available orfor atdistribution ~~all~~to its stockholders.

~~Our~~As ~~operations~~of ~~are~~August ~~substantially~~4, 2020, approximately $16.4 ~~dependent~~million in principal and accrued interest was outstanding under the Old Ironsides Notes. Pursuant to the terms of the Payoff Agreement, Carbon is required to apply certain net proceeds from the Appalachia Divestiture in repayment of the Old Ironsides Notes on specified repayment dates tied to milestones under the ~~availability~~Purchase Agreement. The initial payment of ~~water~~$10.5 million was paid within three business days after the closing date of the Appalachia Divestiture. The second payment is due within three business days after the settlement and ~~electricity~~payment of the Final Base Purchase Price (as defined in the purchase agreement for the Appalachia Divestiture). ~~Restrictions~~If onthe ~~our~~sum of ~~ability~~the toinitial ~~obtain~~payment ~~water~~and the second payment is at least $20.0 million, orthe ~~increasing~~Old ~~prices~~Ironsides orNotes ~~shortages~~will be deemed paid in full. If the sum of ~~electricity~~the initial payment and the second payment is at least $18.0 million but less than $20.0 million, ~~particularly~~the inOld ~~California~~Ironsides Notes will be amended such that the outstanding principal balance plus all accrued and unpaid interest is equal to $21.5 million (less the amount of the initial and second payments) and the Old Ironsides Notes will remain outstanding with no other change to the existing terms. If the sum of the initial payment and the second payment is less than $18.0 million, ~~may~~then Carbon will have the anopportunity ~~adverse~~to ~~effect~~make ona ~~our~~third ~~financial~~payment. The ~~condition~~third payment would be due within three business days after the first Contingent Payment (as defined in the purchase agreement for the Appalachia Divestiture). If the sum of the initial payment, ~~results~~the second payment and the third payment is at least $18.0 million, the Old Ironsides Notes will be amended such that the outstanding principal balance plus all accrued and unpaid interest is equal to $23.0 million (less the amount of ~~operations~~the initial, second and third payments) and ~~cash~~the ~~flows~~Old Ironsides Notes will remain outstanding with no other change to the existing terms. If the sum of the initial payment, the second payment and the third payment is less than $18.0 million, the payments made by Carbon as of such date will be considered mandatory prepayments and the Old Ironsides Notes will remain outstanding with no change to the existing terms.

Water and electricity are essential components of oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. As a result of severe drought in parts of California, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect the availability of local water supply. Additionally, in recent years, shortages of electricity have resulted in increased costs for consumers and certain interruptions in service. California has experienced rolling blackouts due to excessive demand on the electrical grid or as precautionary measures against the risk of wildfire in the past because of unexpectedly high temperatures. If we are unable to obtain water to use in our operations from local sources or we experience electricity blackouts, we may be unable to economically produce our reserves or run our operations, which could have an adverse effect on our financial condition, results of operations, and cash flows.33

Several sources of cash are not yet available to us or are only available to us on a limited basis. One source of cash available to us is our PPP Loan under the PPP, which we received in May 2020. The PPP, established as part of the CARES Act, provides for loans to qualifying businesses for amounts up to 2.5 times the average monthly payroll expenses of the qualifying business. The PPP Loan and accrued interest are forgivable after 24 weeks as long as the borrower uses the loan proceeds for documented eligible purposes, including payroll, benefits, rent and utilities, and maintains its payroll levels, and we intend to apply for forgiveness of the PPP Loan as soon as we are eligible. The SBA continues to develop and issue new and updated guidance regarding the PPP loans application process, including guidance regarding required borrower certifications and requirements for forgiveness of loans made under the program. We continue to track the guidance as it is released and assess and re-assess various aspects of its application as necessary based on the guidance. However, given the evolving nature of the guidance and based on our projected ability to use the loan proceeds for qualifying expenses, we cannot give any assurance that our PPP Loan will be forgiven in whole or in part.

Upon the closing of the Appalachia Divestiture and as more fully described in the Company’s proxy statement related to the Appalachia Divestiture, $6.7 million of the purchase price was held in escrow, a portion of which will be released to the Company on the 18-month anniversary of the closing of the Appalachia Divestiture following satisfaction of certain indemnification obligations and the remainder of which will be released to the Company over the 36-month period following the closing of the Appalachia Divestiture if certain release requirements have been met. However, a portion or all of the escrow amount could be distributed to the purchaser in satisfaction of indemnification obligations owed by the Company or if the release requirements are not met.

Further, ongoing general and corporate operations will be funded by management fees paid to the Company by Carbon California of approximately $1.2 million annually as well as any proceeds received from the contingent payment associated with the Appalachia Divestiture. The contingent payment of up to $15.0 million in the aggregate will be calculated and paid yearly by January 5 of each of 2021, 2022 and 2023 based on the contingent payment calculation for calendar years 2020, 2021 and 2022. Also, Carbon and DGOC entered into a transition services agreement to provide, on an interim basis, certain services associated with the divested assets. The services under the transition services agreement commenced on May 26, 2020 and are expected to terminate in November 2020.

Further, Carbon’s operations are conducted entirely through its subsidiaries, and its ability to generate cash to meet its operating obligations is dependent on the earnings and the receipt of funds from its subsidiaries through distributions or intercompany loans. Historically, Carbon California’s distributions have been limited and may continue to be limited and depend on a number of factors, including development of reserves, successful acquisitions of complementary properties, advantageous drilling conditions, oil and natural gas prices, compliance with all applicable laws and regulations and other factors, which are outside our control. Access to additional capital within the current commodity price environment is limited and the terms of any available capital may not be acceptable to the Company.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be sufficient.

~~Following~~Our ~~the closing of the Contemplated Transactions, our~~ sole source of revenue ~~will~~is be from Carbon California’s operations. Our ability to service our debt obligations ~~following~~ ~~the Contemplated Transactions~~ depends on the future operating performance and cash flow from Carbon California. There can be no assurance that our cash from operations will be sufficient to meet continuing debt obligations, and if we are unable to generate sufficient cash through our operations, we could face substantial liquidity problems, which could have a material adverse effect on our results of operations and financial condition. If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional capital or refinance our indebtedness. We may not be able to take any of these actions, and these actions may not be successful or permit us to meet our scheduled debt service obligations. Furthermore, these actions may not be permitted under the terms of our existing or future debt agreements.

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We intend to deregister our common stock under the Exchange Act. Deregistration may negatively affect the liquidity and trading prices of our common stock and result in less disclosure about us.

Because of the costs associated with preparing and filing our annual, quarterly and current reports under applicable securities laws, we have taken and will continue to take actions to terminate or suspend our ongoing reporting obligations under the Exchange Act. As more fully described in proxy materials filed with the SEC, the Board of Directors is proposing to amend the Company’s amended and restated certificate of incorporation to effect the Reverse Stock Split. If the Reverse Stock Split is approved, it will allow the Company to deregister its common stock and reduce ongoing expenses with respect to filings under the Exchange Act. After the filing of Form 15 to suspend the Company’s reporting obligations under Section 15(d) of the Exchange Act, the Company will no longer be subject to certain provisions of the Exchange Act. However, if we are required to continue to file annual, quarterly or current reports with the SEC, or if we again become subject to such reporting obligations, we will continue to incur the associated costs and expenses, which are substantial.

Once the deregistration is effective, the Company will no longer file annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K. Accordingly, there will be significantly less information regarding the Company available to stockholders and potential investors. In addition, the Company will no longer be subject to the provisions of the Sarbanes-Oxley Act and certain of the liability provisions of the Exchange Act, although the Company will still be subject to the antifraud provisions of the Exchange Act and any applicable state securities laws. Following deregistration, the Company’s executive officers, directors and 10% stockholders will no longer be required to file reports relating to their transactions in the common stock with the SEC. The lack of public information could make trading in our shares of common stock more difficult, which may cause the value of our common stock to decrease. The Company anticipates that after the Reverse Stock Split its common stock will trade on the Pink Non-Current platform of the OTC Markets Group.

The recent spread of COVID-19, or the novel coronavirus, and measures taken to mitigate the impact of the COVID-19 pandemic, are adversely affecting our business, operations and financial condition.

Like other oil and gas companies, our business is being adversely affected by the COVID-19 pandemic and measures being taken to mitigate its impact. The pandemic has resulted in widespread adverse impacts on the global economy and on our employees, customers, suppliers and other parties with whom we have business relations. As the coronavirus pandemic and government responses are rapidly evolving, the extent of the impact on domestic exploration and production companies remains unknown. We are experiencing a sharp and rapid decline in the demand for the oil and natural gas we produce and in the prices we receive for our products as the U.S. and global economy are being negatively impacted as economic activity is curtailed in response to the COVID-19 pandemic. Official restrictions on non-essential activities have been introduced across the U.S., which may adversely impact our production activities. For example, since mid-March, we have had to restrict access to our administrative offices. There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of the virus, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns. Restrictions of this nature have caused, and may continue to cause, us, our suppliers and other business counterparties to experience operational delays, delays in the delivery of materials and supplies that are sourced from around the globe, and have caused, and may continue to cause, milestones or deadlines relating to various projects to be missed. Further, the impact of the pandemic, including the resulting significant reduction in global demand for oil and gas, coupled with the sharp decline in oil prices following the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries is expected to lead to significant global economic contraction generally and in our industry in particular. We anticipate that our business, financial condition and results of operations may be materially and adversely impacted as a result of these developments.

We have modified certain business and workforce practices (including those related to employee travel, employee work locations, and cancellation of physical participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by governmental and regulatory authorities. However, the quarantine of personnel or the inability to access our facilities or customer sites could adversely affect our operations. Additionally, currently many of our employees are working remotely. An extended period of remote work arrangements could strain our business continuity plans, introduce operational risk, including but not limited to cybersecurity risks, and impair our ability to manage our business.

WeGiven the dynamic nature of the COVID-19 pandemic and related market conditions, we cannot ~~predict~~reasonably estimate the ~~full~~period of time these events will persist or the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, cash flows, liquidity, financial condition and results of operations at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ~~ultimate~~consequences ~~geographic spread~~ of ~~the virus,~~countermeasures ~~the~~taken ~~consequences~~by ofgovernments, ~~governmental~~businesses and ~~other~~individuals ~~measures designed~~ to ~~prevent~~slow the spread of the ~~virus~~pandemic, the ~~development~~ability of ~~effective~~pharmaceutical companies to ~~treatments~~develop effective and safe vaccines and therapeutic drugs, the duration of the outbreak, actions taken by members of OPEC and other foreign, oil-exporting countries, actions taken by ~~governmental authorities,~~ customers, suppliers and other third parties, workforce availability, and the timing and extent to which normal economic and operating conditions resume.

The impact of COVID-19 and the OPEC price war may also exacerbate other risks discussed in Item 1A of the 2019 Annual Report and Item 1A of the First Quarter Quarterly Report, any of which could have a material effect on us. This situation is changing rapidly and additional impacts may arise that we are not aware of currently.

Oil prices are highly volatile. Declines in commodity prices, especially steep declines in the price of oil, have adversely affected, and in the future will adversely affect, our financial condition and results of operations, cash flow, access to the capital markets and ability to grow.

As a result of the ~~Contemplated~~Appalachia ~~Transactions~~Divestiture, Carbon will ~~no longer produce natural gas and instead will~~ concentrate on the production of oil from its assets in the Ventura Basin. The oil market is highly volatile, and we cannot predict future oil prices. Beginning in February 2020, oil ~~and natural gas~~ prices have experienced record declines and are currently at record low levels in response to dramatic supply and demand uncertainty caused by the coronavirus pandemic and the recent announcement of planned production increases by Saudi Arabia. For example, the price of oil fell approximately 20% on March 9, 2020 due to Saudi Arabia’s decision to increase its production to record levels. As of ~~April 30~~August 5, 2020, the NYMEX WTI oil futures price ~~for June 2020~~ was $1842.8419 per Bbl ~~and the Henry Hub natural gas price was $1~~.~~949~~ ~~per MMBtu.~~ Although OPEC agreed in April to cut production, the responses of oil and gas producers to the ~~lower~~ lower demand for, and price of, oil, natural gas and NGLs are constantly evolving and remain uncertain. We cannot anticipate whether or when production will return to normalized levels, and oil and natural gas prices could remain at current levels or decline further, for an extended period of time.

Prices for oil may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, market uncertainty and a variety of additional factors that are beyond our control, such as:

●

domestic and foreign supply of and demand for oil;

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market prices of oil;

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level of consumer product demand;

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overall domestic and global political and economic conditions;

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political and economic conditions in producing countries, including those in the Middle East, Russia, South America and Africa;

●

global or national health concerns, including the outbreak of pandemic or contagious disease, such as the recent coronavirus, which may reduce demand for crude oil because of reduced global or national economic activity;

●

actions of the OPEC and other state-controlled oil companies relating to oil price and production controls;

●

weather conditions;

●

impact of the U.S. dollar exchange rates on commodity prices;

●

technological advances affecting energy consumption and energy supply;

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domestic and foreign governmental regulations and taxation;

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impact of energy conservation efforts;

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capacity, cost and availability of oil pipelines, processing, gathering and other transportation facilities and the proximity of these facilities to our wells; and

●

price and availability of alternative fuels.

Our production in the Ventura Basin received an approximate 9.7% premium to the NYMEX WTI benchmark price during 2019. A reduction in this premium would reduce the relative price advantage we receive for a substantial portion of our production in the Ventura Basin.

Our revenue, profitability and cash flow depend upon the prices and demand for oil. A drop in prices would significantly affect our financial results and impede our growth. In particular, a significant or prolonged decline in oil prices will negatively impact:

●

the value of our reserves, because declines in oil prices would reduce the amount of oil that we can produce economically;

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the amount of cash flow available for capital expenditures;

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our ability to replace our production and future rate of growth;

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our ability to borrow money or raise additional capital and our cost of such capital; and

●

our ability to meet our financial obligations.

Historically, higher oil prices generally result in increased demand and prices for drilling equipment, crews and associated supplies, equipment and services, as well as higher lease operating expenses and increased end-user conservation or conversion to alternative fuels. However, commodity price declines do not result in similarly rapid declines of costs associated with drilling. Accordingly, a high cost environment could adversely affect our ability to pursue our drilling program and our results of operations.

ITEM 6. Exhibits

Exhibit No.		Description
2.1**		Membership Interest Purchase Agreement, dated as of April 7, 2020, by and among Carbon Energy Corporation, Nytis Exploration (USA) Inc., Diversified Gas & Oil Corporation, Nytis Exploration Company LLC, Carbon Appalachian Company, LLC, and the other entities party thereto, incorporated by reference to Exhibit 2.1 to Form 8-K filed on April 8, 2020.
10.1		~~Third~~Fourth Amendment to the Amended and Restated Credit Agreement, dated ~~February~~April 1430, 2020, incorporated by reference to Exhibit 10.261 to Form 108-K filed on ~~March~~May 306, 2020.
10.2		~~Fourth~~Agreement ~~Amendment~~Regarding toPayoff ~~the~~and ~~Amended~~Release ~~and~~or ~~Restated~~Amendment ~~Credit~~of ~~Agreement~~Notes, dated ~~April~~as 30of May 25, 2020, by and among Carbon Energy Corporation, Old Ironsides Fund II-A Portfolio Holding Company, LLC and Old Ironsides Fund II-B Portfolio Holding Company, LLC, incorporated by reference to Exhibit 10.1 to Form 8-K filed on May 629, 2020.
10.3*††		Consulting Agreement between Carbon Energy Corporation and Kevin D. Struzeski, dated May 26, 2020.
10.4*††		Consulting Agreement between Carbon Energy Corporation and Mark D. Pierce, dated May 26, 2020.
10.5*		Promissory Note between Carbon Energy Corporation and UMB Bank, dated May 13, 2020.
31.1*		Certification of Chief Executive Officer Pursuant to Rule 13a-15(e) / Rule 15d-15(e).
31.2*		Certification of ~~Chief~~Principal 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~~Principal 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
**	Certain schedules have been omitted pursuant to Item 601(a)(5) of Regulation S-K. Carbon Energy Corporation agrees to furnish supplementally a copy of any such omitted schedule to the SEC upon request.
†	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.

40†† Management contract or compensatory plan or arrangement.

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

	CARBON ENERGY CORPORATION
	(Registrant)
Date: May 14, 2020	By:	/s/ Patrick R. McDonald
Date: August 14, 2020	By:	/s/ Patrick R. McDonald
		PATRICK R. MCDONALD,
		Chief Executive Officer
Date: May 14, 2020	By:	/s/ Kevin D. Struzeski
Date: August 14, 2020	By:	/s/ Erich W. Kirsch
		KEVIN D. STRUZESKI
		ERICH W. KIRSCH
		Chief Financial Officer
		Senior Vice President, Finance and Accounting (Principal Financial and Accounting Officer)

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