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 September 30, 2019

or

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

For the transition period from ___________ to ____________

Commission File Number: 000-02040

CARBON ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

YES ☒               NO ☐

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

YES ☒               NO ☐

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

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

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

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

YES ☐               NO ☒

At November 8, 2019, there were 7,856,864 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	22
Item 3. Quantitative and Qualitative Disclosures About Market Risk	33
Item 4. Controls and Procedures	33
Part II – OTHER INFORMATION
Item 1. Legal Proceedings	34
Item 1A. Risk Factors	34
Item 6. Exhibits	34
Signatures	35

i

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

CARBON ENERGY CORPORATION

Condensed Consolidated Balance Sheets

	September 30,			December 31,
(in thousands, except share amounts)	2019			2018
ASSETS	(Unaudited)
Current assets:
Cash and cash equivalents	$	3,514		$	5,736
Accounts receivable:
Revenue		11,632			19,671
Joint interest billings and other		1,361			1,770
Insurance receivable (Note 2)		-			522
Commodity derivative asset (Note 14)		6,722			3,517
Prepaid expense, deposits and other current assets		2,537			1,645
Inventory		2,522			1,149
Total current assets		28,288			34,010
Non-current assets:
Property and equipment (Note 4)
Oil and gas properties, full cost method of accounting:
Proved, net		243,593			248,455
Unproved		5,004			5,416
Other property and equipment, net		16,253			17,563
Total property and equipment, net		264,850			271,434
Investments in affiliates		605			598
Commodity derivative asset – non-current (Note 14)		3,072			3,505
Right-of-use assets (Note 8)		6,523			-
Other non-current assets		1,166			1,344
Total non-current assets		276,216			276,881
Total assets	$	304,504		$	310,891
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities (Note 5)	$	30,786		$	34,816
Firm transportation contract obligations (Note 15)		5,824			6,129
Lease liability – current (Note 8)		1,620			-
Credit facilities and notes payable – current (Note 7)		8,266			11,910
Total current liabilities		46,496			52,855
Non-current liabilities:
Firm transportation contract obligations (Note 15)		9,795			12,729
Lease liability – non-current (Note 8)		4,793			-
Production and property taxes payable		2,654			2,914
Asset retirement obligations (Note 6)		18,788			19,211
Credit facilities and notes payable (Note 7)		96,034			97,228
Notes payable – related party (Note 7)		44,465			49,919
Total non-current liabilities		176,529			182,001
Commitments and contingencies (Note 15)
Stockholders’ equity:
Preferred stock, $0.01 par value; liquidation preference of $449 at September 30, 2019 and $224 at December 31, 2018; authorized 1,000,000 shares, 50,000 shares issued and outstanding at September 30, 2019 and December 31, 2018		1			1
Common stock, $0.01 par value; authorized 35,000,000 shares, 7,856,030 and 7,655,759 shares issued and outstanding at September 30, 2019 and December 31, 2018, respectively		79			77
Additional paid-in capital		85,261			84,612
Accumulated deficit		(31,628	)		(36,939	)
Total Carbon stockholders’ equity		53,713			47,751
Non-controlling interests		27,766			28,284
Total stockholders’ equity		81,479			76,035
Total liabilities and stockholders’ equity	$	304,504		$	310,891

See accompanying notes to Condensed Consolidated Financial Statements.

1

CARBON ENERGY CORPORATION

Condensed Consolidated Statements of Operations

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands, except per share amounts)	2019			2018			2019			2018
Revenue:
Natural gas sales	$	11,963		$	4,372		$	45,495		$	11,835
Natural gas liquids		10			406			451			1,119
Oil sales		9,049			11,850			27,940			22,924
Transportation and handling		304			-			1,361			-
Marketing gas sales		3,491			-			11,656			-
Commodity derivative gain (loss)		5,595			(3,902	)		4,969			(10,550	)
Other income		123			16			820			35
Total revenue		30,535			12,742			92,692			25,363
Expenses:
Lease operating expenses		7,689			4,767			21,784			10,824
Pipeline operating expenses		2,614			-			8,650			-
Transportation and gathering costs		1,593			1,433			4,392			3,786
Production and property taxes		16			743			3,692			1,792
Marketing gas purchases		3,872			-			14,969			-
General and administrative		2,852			3,517			11,489			9,007
General and administrative – related party reimbursement		-			(1,170	)		-			(3,383	)
Depreciation, depletion and amortization		4,112			2,731			11,973			6,202
Accretion of asset retirement obligations		420			206			1,219			510
Total expenses		23,168			12,227			78,168			28,738
Operating income (loss)		7,367			515			14,524			(3,375	)
Other income (expense):
Interest expense, net		(3,047	)		(1,127	)		(9,772	)		(3,331	)
Warrant derivative gain		-			-			-			225
Gain on derecognized equity investment in affiliate – Carbon California		-			-			-			5,390
Investments in affiliates		32			157			73			1,121
Total other (expense) income		(3,015	)		(970	)		(9,699	)		3,405
Income (loss) before income taxes		4,352			(455	)		4,825			30
Provision for income taxes		-			-			-			-
Net income (loss) before non-controlling interests and preferred shares		4,352			(455	)		4,825			30
Net income (loss) attributable to non-controlling interests		1,170			270			(486	)		(2,234	)
Net income (loss) attributable to controlling interests before preferred shares		3,182			(725	)		5,311			2,264
Net income attributable to preferred shares – preferred return		75			-			225			-
Net income (loss) attributable to common shares	$	3,107		$	(725	)	$	5,086		$	2,264
Net income (loss) per common share:
Basic	$	0.40		$	(0.09	)	$	0.65		$	0.30
Diluted	$	0.38		$	(0.10	)	$	0.63		$	0.10
Weighted average common shares outstanding:
Basic		7,839			7,701			7,780			7,466
Diluted		8,141			7,701			8,082			7,781

See accompanying notes to Condensed Consolidated Financial Statements.

2

CARBON ENERGY CORPORATION

Condensed Consolidated Statements of Stockholders’ Equity

(Unaudited)

(in thousands)

									Additional			Non-						Total
	Common Stock				Preferred Stock				Paid-in			Controlling			Accumulated			Stockholders’
	Shares		Amount		Shares		Amount		Capital			Interests			Deficit			Equity
Balance as of December 31, 2017		6,006	$	60		-	$	-	$	58,813		$	1,841		$	(44,218	)	$	16,496
Stock-based compensation		-		-		-		-		292			-			-			292
Restricted stock vested		38		1		-		-		-			-			-			1
CCC warrant exercise – share issuance		1,528		15		-		-		8,311			16,466			-			24,792
CCC warrant exercise – liability extinguishment		-		-		-		-		1,792			-			-			1,792
Non-controlling interests’ distributions, net		-		-		-		-		-			(24	)		-			(24	)
Net income		-		-		-		-		-			1,115			3,569			4,684
Balance as of March 31, 2018		7,572	$	76		-	$	-	$	69,208		$	19,398		$	(40,649	)	$	48,033
Stock-based compensation		-		-		-		-		192			-			-			192
Restricted stock vested		21		-		-		-		-			-			-			-
Performance units vested		108		1		-		-		(1	)		-			-			-
Preferred share issuance (Note 11)		-		-		50		1		4,999			-			-			5,000
Beneficial conversion feature		-		-		-		-		1,125			-			(1,125	)		-
Deemed dividend		-		-		-		-		71			-			(71	)		-
Non-controlling interests’ contributions, net		-		-		-		-		-			5,498			-			5,498
Net loss		-		-		-		-		-			(3,619	)		(579	)		(4,198	)
Balance as of June 30, 2018		7,701	$	77		50	$	1	$	75,594		$	21,277		$	(42,424	)	$	54,525
Stock-based compensation		-		-		-		-		187			-			-			187
Deemed dividend		-		-		-		-		77			-			(77	)		-
Non-controlling interests’ contributions, net		-		-		-		-		-			4			-			4
Net loss		-		-		-		-		-			270			(725	)		(455	)
Balance as of September 30, 2018		7,701	$	77		50	$	1	$	75,858		$	21,551		$	(43,226	)	$	54,261

									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
Stock-based compensation		-		-		-		-		204			-			-			204
Restricted stock vested		40		-		-		-		-			-			-			-
Non-controlling interests’ distributions, net		-		-		-		-		-			(38	)		-			(38	)
Net income		-		-		-		-		-			1,170			3,182			4,352
Balance as of September 30, 2019		7,856	$	79		50	$	1	$	85,261		$	27,766		$	(31,628	)	$	81,479

See accompanying notes to Condensed Consolidated Financial Statements.

3

CARBON ENERGY CORPORATION

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended
	September 30,
(in thousands)	2019			2018
Cash flows from operating activities:
Net income	$	4,825		$	30
Items not involving cash:
Depreciation, depletion and amortization		11,973			6,202
Accretion of asset retirement obligations		1,219			510
Unrealized commodity derivative (gain) loss		(2,771	)		8,381
Warrant derivative gain		-			(225	)
Stock-based compensation expense		650			672
Investments in affiliates		(57	)		(1,121	)
Gain on derecognized equity investment in affiliate – Carbon California		-			(5,390	)
Amortization of debt costs		644			468
Interest expense paid-in-kind		1,819			-
Other		(56	)		-
Net change in:
Accounts receivable		8,971			(2,975	)
Prepaid expenses, deposits and other current assets		(982	)		456
Accounts payable, accrued liabilities and firm transportation contract obligations		(11,718	)		(1,945	)
Other non-current items		(395	)		(1,751	)
Net cash provided by operating activities		14,122			3,312
Cash flows from investing activities:
Development and acquisition of properties and equipment		(4,226	)		(44,681	)
Proceeds received – Carbon California Acquisition		-			275
Distribution from affiliate		50			-
Proceeds received – disposition of oil and gas properties and other property and equipment		314			-
Net cash used in investing activities		(3,862	)		(44,406	)
Cash flows from financing activities:
Proceeds from credit facilities and notes payable		4,000			34,529
Proceeds from preferred shares		-			5,000
Payments on credit facilities and notes payable		(16,396	)		(14	)
Payments of debt issuance costs		(54	)		(586	)
(Distributions to) contributions from non-controlling interests, net		(32	)		4,992
Net cash (used in) provided by financing activities		(12,482	)		43,921
Net (decrease) increase in cash and cash equivalents		(2,222	)		2,827
Cash and cash equivalents, beginning of period		5,736			1,650
Cash and cash equivalents, end of period	$	3,514		$	4,477

See accompanying notes to Condensed Consolidated Financial Statements.

4

CARBON ENERGY CORPORATION

Notes to Condensed Consolidated Financial Statements

(Unaudited)

NOTE 1 – ORGANIZATION

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

Appalachian and Illinois Basin Operations

In the Appalachian and Illinois Basins, operations are conducted by Nytis Exploration Company, LLC (“Nytis LLC”). The following organizational chart illustrates this relationship as of September 30, 2019:

 

5

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

Ventura Basin Operations

In California, Carbon California Operating Company, LLC conducts operations on behalf of Carbon California Company, LLC, a Delaware limited liability company (“Carbon California”). On February 1, 2018, Yorktown Energy Partners XI, L.P. (“Yorktown”) exercised a warrant, collectively resulting in our aggregate sharing percentage in Carbon California increasing from 17.81% to 56.40%. On May 1, 2018, Carbon California closed the acquisition with Seneca Resources Corporation (the “Seneca Acquisition”). Following the exercise of the warrant by Yorktown and the Seneca Acquisition, we own 53.92% of the voting and profits interests and Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America or its affiliates (collectively, “Prudential”) owns 46.08% of the voting and profits interest in Carbon California. As of February 1, 2018, we consolidate Carbon California for financial reporting purposes. The following organizational chart illustrates this relationship as of September 30, 2019:

6

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and in accordance with U.S. generally accepted accounting principles (“GAAP”) applicable to interim financial statements. These unaudited condensed consolidated financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary for a fair presentation of the results of the interim period. Operating results for the interim periods presented require management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes and are not necessarily indicative of the results that may be expected for the full year. The condensed consolidated balance sheet data as of December 31, 2018 was derived from audited financial statements but does not include all disclosures required by GAAP. These unaudited condensed consolidated financial statements should be read in conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2018. The Company follows the same accounting policies for preparing quarterly and annual reports.

Principles of Consolidation

The unaudited condensed consolidated financial statements include the accounts of our consolidated subsidiaries. Upon the closing of the OIE Membership Acquisition on December 31, 2018, we own 100% of Carbon Appalachia. In addition, we own 100% of Nytis USA, which owns approximately 98.11% of Nytis LLC. Nytis LLC holds interests in various oil and gas partnerships.

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

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

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

Reclassifications

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

Insurance Receivable

Insurance receivable is comprised of insurance claims for the loss of property as a result of wildfires that impacted Carbon California in December 2017. The Company filed claims with its insurance provider. In January 2019, we reached a settlement agreement and received an $800,000 final settlement payment from our insurance provider related to the damage caused by the California wildfires. As of September 30, 2019, we were in receipt of all funds associated with the claims.

Revenue

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

Transportation and Handling

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

7

Marketing Gas Sales

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

Recently Adopted Accounting Pronouncement

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

NOTE 3 – ACQUISITIONS

Majority Control of Carbon Appalachia

On December 31, 2018, we acquired all of Old Ironsides’ Class A Units of Carbon Appalachia for approximately $58.1 million. We paid $33.0 million in cash and delivered promissory notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides (the “Old Ironsides Notes”). See Note 7 for additional information.

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

The OIE Membership Acquisition was accounted for as a business combination in accordance with ASC 805, Business Combinations. For assets and liabilities accounted for as business combinations, including the OIE Membership Acquisition, we utilized the assistance of third-party valuation specialists to determine the fair value of the assets and liabilities acquired. We primarily used the income approach and made market assumptions as to projections of estimated quantities of oil and natural gas reserves, future production rates, future commodity prices including price differentials as of the date of closing, future operating and development costs, a market participant weighted average cost of capital, and the condition of vehicles and equipment. We used the income approach and made market assumptions as to projections of utilization, future operating costs and a market participant weighted average cost of capital to determine the fair value of the firm transportation obligations as well as the plant facilities. The determination of the fair value of accounts payable and accrued liabilities assumed required significant judgement, including estimates relating to production assets.

The following summarizes the estimated fair values of the identifiable assets acquired and liabilities assumed in the acquisition based on their relative fair values at the acquisition date. These estimates of fair value of identifiable assets acquired and liabilities assumed are preliminary, pending final evaluation of certain assets and liabilities, and therefore are subject to revisions that may result in adjustments to the values presented below:

	Amount  (in thousands)
Cash consideration	$	33,000
Old Ironsides Notes		25,030
Fair value of previously held equity interest		14,158
Fair value of business acquired	$	72,188

8

Assets acquired and liabilities assumed are as follows:

	Amount (in thousands)
Cash	$	12,283
Accounts receivable:
Revenue		12,834
Trade receivable		1,941
Commodity derivative asset		198
Inventory		2,022
Prepaid expenses, deposits, and other current assets		456
Oil and gas properties:
Proved		107,879
Unproved		1,869
Other property, plant and equipment, net		15,441
Other non-current assets		514
Accounts payable and accrued liabilities		(20,466	)
Due to related parties		(458	)
Firm transportation contract obligations		(18,724	)
Asset retirement obligations		(5,626	)
Notes payable		(37,975	)
Total net assets acquired	$	72,188

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

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

Below are unaudited pro forma consolidated results of operations for the three and nine months ended September 30, 2018 as though the OIE Membership Acquisition had been completed as of January 1, 2018. Results for the three and nine months ended September 30, 2019 are reflected in the unaudited condensed consolidated statements of operations.

	Three Months Ended September 30,		Nine Months Ended September 30,
(in thousands, except per share amounts)	2018		2018
Revenue	$	27,681	$	82,521
Net income before non-controlling interests	$	1,729	$	4,495
Net income (loss) attributable to non-controlling interests	$	270	$	(2,234	)
Net income attributable to controlling interests before preferred shares	$	1,459	$	6,729
Net income per share, basic	$	0.19	$	0.90
Net income per share, diluted	$	0.18	$	0.70

Consolidation of Carbon California Unaudited Pro Forma Results of Operations

Below are unaudited pro forma consolidated results of operations for the three and nine months ended September 30, 2018 as though the Carbon California Acquisition occurred on January 1, 2018. Results for the three and nine months ended September 30, 2019 are reflected in the unaudited condensed consolidated statements of operations.

	Three Months Ended September 30,			Nine Months Ended September 30,
(in thousands, except per share amounts)	2018			2018
Revenue	$	12,742		$	33,256
Net (loss) income before non-controlling interests	$	(455	)	$	5,232
Net income (loss) attributable to non-controlling interests	$	270		$	(2,334	)
Net (loss) income attributable to controlling interests before preferred shares	$	(725	)	$	7,566
Net (loss) income per share, basic	$	(0.09	)	$	1.00
Net (loss) income per share, diluted	$	(0.10	)	$	0.96

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NOTE 4 – PROPERTY AND EQUIPMENT

Property and equipment, net consists of the following:

(in thousands)	September 30, 2019			December 31, 2018
Oil and gas properties:
Proved oil and gas properties	$	349,550		$	343,736
Unproved properties not subject to depletion		5,004			5,416
Accumulated depreciation, depletion, amortization and impairment		(105,957	)		(95,281	)
Net oil and gas properties		248,597			253,871
Pipeline facilities and equipment		12,714			12,714
Base gas		1,937			2,122
Furniture and fixtures, computer hardware and software, and other equipment		6,733			6,649
Accumulated depreciation and amortization		(5,131	)		(3,922	)
Net other property and equipment		16,253			17,563
Property and equipment, net	$	264,850		$	271,434

As of September 30, 2019, and December 31, 2018, the Company had approximately $5.0 million and $5.4 million, respectively, of unproved oil and gas properties not subject to depletion. Such costs are excluded from the full cost pool until it is determined if reserves can be assigned to the related properties. Subject to industry conditions, evaluation of most of these properties and the inclusion of their costs in the full cost pool is expected to be completed within five years. Unproved properties are assessed for impairment at least annually. During the three and nine months ended September 30, 2019, approximately $513,000 and $719,000 of expiring leasehold costs were reclassified into proved property. There were no expiring leasehold costs during the three and nine months ended September 30, 2018.

We capitalized overhead applicable to acquisition, development and exploration activities of approximately $167,000 and $540,000 for the three and nine months ended September 30, 2019, respectively. For the three and nine months ended September 30, 2018, we capitalized overhead applicable to acquisition, development, and exploration activities of approximately $106,000 and $306,000, respectively.

Depletion expense related to oil and gas properties for the three and nine months ended September 30, 2019 was approximately $3.7 million and $10.7 million, respectively. Depletion expense related to oil and gas properties for the three and nine months ended September 30, 2018 was approximately $2.4 million and $5.6 million, respectively.

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

NOTE 5 – ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

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

(in thousands)	September 30, 2019		December 31, 2018
Accounts payable	$	5,787	$	7,670
Oil and gas revenue suspense		3,044		2,675
Gathering and transportation payables		1,239		1,774
Production taxes payable		2,838		1,860
Accrued operating costs		681		3,155
Accrued ad valorem taxes – current		5,501		3,474
Accrued general and administrative expenses		2,285		3,111
Accrued asset retirement obligation – current		5,035		3,099
Accrued interest		1,455		955
Accrued gas purchases		2,035		5,440
Other liabilities		886		1,603
Total accounts payable and accrued liabilities	$	30,786	$	34,816

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NOTE 6 – ASSET RETIREMENT OBLIGATION

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

	Nine Months Ended September 30,
(in thousands)	2019			2018
Balance at beginning of period	$	22,310		$	7,737
Accretion expense		1,219			510
Additions and revisions		294			3,590
Balance at end of period	$	23,823		$	11,837
Less:  Current portion		(5,035	)		(902	)
Non-current portion	$	18,788		$	10,935

NOTE 7 – CREDIT FACILITIES AND NOTES PAYABLE

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

(in thousands)	September 30, 2019			December 31, 2018
2018 Credit Facility – revolver	$	71,150		$	69,150
2018 Credit Facility – term note		8,333			15,000
Old Ironsides Notes		24,826			25,065
Other debt		58			57
Total debt		104,367			109,272
Less:  unamortized debt discount		(67	)		(134	)
Total credit facilities and notes payable		104,300			109,138
Current portion of credit facilities and notes payable		(8,266	)		(11,910	)
Non-current debt, net of current portion and unamortized debt discount	$	96,034		$	97,228

Carbon Appalachia

2018 Credit Facility

In connection with and concurrently with the closing of the OIE Membership Acquisition, the Company and its subsidiaries amended and restated our prior credit facilities and entered into a $500.0 million senior secured asset-based revolving credit facility maturing December 31, 2022 and a $15.0 million term loan maturing in 2020 (the “2018 Credit Facility”). The 2018 Credit Facility includes a sublimit of $1.5 million for letters of credit. The borrowers under the 2018 Credit Facility are Carbon Appalachia Enterprises, LLC (“CAE”) and various other subsidiaries of the Company (including Nytis USA, together with CAE, the “Borrowers”). Under the 2018 Credit Facility, Carbon Energy Corporation is neither a borrower nor a guarantor. The initial borrowing base under the 2018 Credit Facility was $75.0 million and remained so as of September 30, 2019.

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

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

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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, commencing with the quarter ending March 31, 2019.

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

As of September 30, 2019, there was approximately $71.2 million in outstanding borrowings and $3.8 million of additional borrowing capacity under the 2018 Credit Facility. As of September 30, 2019, we were in compliance with our financial covenants.

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

Fees paid in connection with the 2018 Credit Facility totaled approximately $779,000, of which $134,000 was associated with the term loan. The current portion of unamortized fees associated with the credit facility is included in prepaid expense, deposits and other current assets and the non-current portion is included in other non-current assets. The unamortized portion associated with the term loan was $67,000 as of September 30, 2019 and is directly offset against the loan in current liabilities. As of September 30, 2019, we had unamortized deferred issuance costs of approximately $524,000 associated with the 2018 Credit Facility. During the three and nine months ended September 30, 2019, we amortized approximately $63,000 and $188,000, respectively, as interest expense associated with the 2018 Credit Facility.

Old Ironsides Notes

On December 31, 2018, as part of the OIE Membership Acquisition, we delivered unsecured, promissory notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides (the “Old Ironsides Notes”). The Old Ironsides Notes bear interest at 10.0% per annum and have a term of five years, the first three of which require interest-only payments at the end of each calendar quarter beginning with the quarter ending March 31, 2019. At the end of the three-year interest-only period, the then current outstanding principal balance and interest is to be paid in 24 equal monthly payments. The Old Ironsides Notes also require mandatory prepayments upon the occurrence of certain subsequent liquidity events. A mandatory, one-time principal reduction payment in the aggregate amount of $2.0 million was made to Old Ironsides on February 1, 2019. Subsequent to the closing of the OIE Membership Acquisition, Old Ironsides ceased to be a related party.

The interest payable under the Old Ironsides Notes can be paid-in-kind at the election of the Company. This provision allows the Company to increase the principal balance associated with the Old Ironsides Notes. This election creates a second tranche of principal, which bears interest at 12.0% per annum. For the nine months ended September 30, 2019, the Company elected payment-in-kind interest of approximately $1.8 million.

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Carbon California

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

(in thousands)	September 30, 2019			December 31, 2018
Senior Revolving Notes, related party, due February 15, 2022	$	32,800		$	38,500
Subordinated Notes, related party, due February 15, 2024		13,000			13,000
Total principal		45,800			51,500
Less: Deferred notes costs		(185	)		(235	)
Less: unamortized debt discount		(1,150	)		(1,346	)
Total notes payable – related party	$	44,465		$	49,919

Senior Revolving Notes, Related Party

On February 15, 2017, Carbon California entered into a Note Purchase Agreement (the “Note Purchase Agreement”) for the issuance and sale of Senior Secured Revolving Notes to Prudential with an initial revolving borrowing capacity of $25.0 million which mature on February 15, 2022 (the “Senior Revolving Notes”). Carbon Energy Corporation is not a guarantor of the Senior Revolving Notes. The closing of the Note Purchase Agreement on February 15, 2017 resulted in the sale and issuance by Carbon California of Senior Revolving Notes in the principal amount of $10.0 million. The maximum principal amount available under the Senior Revolving Notes is based upon the borrowing base attributable to Carbon California’s proved oil and gas reserves which is to be determined at least semi-annually. As of September 30, 2019, the borrowing base was $45.0 million, of which $32.8 million was outstanding.  

Carbon California may elect to incur interest at either (i) 5.50% plus LIBOR or (ii) 4.50% plus the Prime Rate (which is defined as the interest rate published daily by JPMorgan Chase Bank, N.A.). As of September 30, 2019, the effective borrowing rate for the Senior Revolving Notes was 7.60%. In addition, the Senior Revolving Notes include a commitment fee for any unused amounts at 0.50% as well as an annual administrative fee of $75,000, payable on February 15 each year.

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

Carbon California incurred fees directly associated with the issuance of the Senior Revolving Notes and amortizes these fees over the life of the Senior Revolving Notes. The current portion of these fees are included in prepaid expense and deposits and the long-term portion is included in other non-current assets for a combined value of approximately $669,000. For the three and nine months ended September 30, 2019, Carbon California amortized fees of $70,000 and $202,000, respectively.

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

Subordinated Notes, Related Party

On February 15, 2017, Carbon California entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”) with Prudential Capital Energy Partners, L.P. for the issuance and sale of Subordinated Notes due February 15, 2024, bearing interest of 12.0% per annum (the “Subordinated Notes”). Carbon Energy Corporation is not a guarantor of the Subordinated Notes. The closing of the Securities Purchase Agreement on February 15, 2017 resulted in the sale and issuance by Carbon California of Subordinated Notes in the original principal amount of $10.0 million, all of which remains outstanding as of September 30, 2019.

Prudential received an additional 1,425 Class A Units, representing 5.0% of the total sharing percentage, for the issuance of the Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding Subordinated Notes of $10.0 million. The Company then allocated the non-cash value of the units of approximately $1.3 million, which was recorded as a discount to the Subordinated Notes. As of September 30, 2019, Carbon California has an outstanding discount of approximately $780,000, which is presented net of the Subordinated Notes within Notes payable-related party on the unaudited condensed consolidated balance sheets. During the three and nine months ended September 30, 2019, Carbon California amortized $45,000 and $134,000, 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. 

13

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 September 30, 2019.

Prudential received 585 Class A Units, representing an approximate 2.0% additional sharing percentage, for the issuance of the 2018 Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding 2018 Subordinated Notes of $3.0 million. The Company then allocated the non-cash value of the units of approximately $490,000, which was recorded as a discount to the 2018 Subordinated Notes. As of September 30, 2019, Carbon California had an outstanding discount of $370,000 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 nine months ended September 30, 2019, Carbon California amortized $21,000 and $63,000, respectively, associated with the 2018 Subordinated Notes.

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

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

Restrictions and Covenants

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

The affirmative and negative covenants are subject to various exceptions, including basket amounts and acceptable transaction levels. In addition, (i) the Senior Revolving Notes require Carbon California’s compliance with (A) a maximum Debt/EBITDA ratio of 4.0 to 1.0 (B) a maximum Senior Revolving Notes/EBITDA ratio of 2.5 to 1.0, (C) a minimum interest coverage ratio of 2.0 to 1.0 and (D) a minimum current ratio of 1.0 to 1.0 and (ii) the Subordinated Notes require Carbon California’s compliance with (A) a maximum Debt/EBITDA ratio of 4.75 to 1.0, (B) a maximum Senior Revolving Notes/EBITDA ratio of 3.0 to 1.0, (C) a minimum interest coverage ratio of 1.6 to 1.0, (D) an asset coverage test whereby indebtedness may not exceed the product of 0.65 times Adjusted PV-10 set forth in the most recent reserve report, (E) maintenance of a minimum borrowing base of $10.0 million under the Senior Revolving Notes and (F) a minimum current ratio of 0.85 to 1.00.

As of September 30, 2019, Carbon California was not in compliance with its Senior Revolving Notes/EBITDA ratio. We are currently negotiating an amendment to the covenant requirements with Prudential, a 46.08% owner of Carbon California, 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 8 – LEASES

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

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

Our right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet. All leases recognized on our unaudited condensed consolidated balance sheet are classified as operating leases, which include leases related to the asset classes reflected in the table below:

(in thousands)	Right-of-Use Assets		Lease Liability
Compressors	$	3,459	$	3,459
Corporate leases		2,225		2,239
Vehicles		839		715
Total	$	6,523	$	6,413

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

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

(in thousands)	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Operating lease cost	$	530	$	1,598
Short-term lease cost		156		473
Total lease cost	$	686	$	2,071

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

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

	September 30, 2019
Weighted-average lease term (years)		3.82
Weighted-average discount rate		6.36	%

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

(in thousands)	Nine Months Ended September 30, 2019
Cash paid for operating leases	$	1,707
Right-of-use assets obtained in exchange for operating lease obligations	$	465

Minimum future commitments by year for our long-term operating leases as of September 30, 2019 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet as follows:

(in thousands)	Amount
Remainder of 2019	$	505
2020		1,960
2021		1,902
2022		1,704
2023		1,157
Thereafter		10
Total future minimum lease payments	$	7,238
Less: imputed interest		(825	)
Total lease liabilities	$	6,413

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NOTE 9 – REVENUE

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

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

	Appalachian and Illinois Basins				Ventura Basin				Total
	Three Months Ended September 30,				Three Months Ended September 30,				Three Months Ended September 30,
	2019		2018		2019		2018		2019		2018
Natural gas sales	$	11,962	$	3,856	$	1	$	516	$	11,963	$	4,372
Natural gas liquids sales		-		-		10		406		10		406
Oil sales		1,327		3,327		7,722		8,523		9,049		11,850
Transportation and handling		304		-		-		-		304		-
Marketing gas sales		3,491		-		-		-		3,491		-
Total	$	17,084	$	7,183	$	7,733	$	9,445	$	24,817	$	16,628

For the nine months ended September 30, 2019 and 2018 (in thousands):

	Appalachian and Illinois Basins				Ventura Basin				Total
	Nine Months Ended September 30,				Nine Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018		2019		2018
Natural gas sales	$	44,633	$	10,776	$	862	$	1,059	$	45,495	$	11,835
Natural gas liquids sales		-		-		451		1,119		451		1,119
Oil sales		4,422		5,952		23,518		16,972		27,940		22,924
Transportation and handling		1,361		-		-		-		1,361		-
Marketing gas sales		11,656		-		-		-		11,656		-
Total	$	62,072	$	16,728	$	24,831	$	19,150	$	86,903	$	35,878

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

NOTE 10 – STOCK-BASED COMPENSATION PLANS

We have three stock plans, the Carbon 2011 Stock Incentive Plan, the Carbon 2015 Stock Incentive Plan and the Carbon 2019 Long Term Incentive Plan (collectively the “Carbon Plans”). The Carbon 2019 Long Term Incentive Plan was approved by the Company’s stockholders in May 2019. The Carbon Plans provide for the issuance of approximately 1.6 million shares of common stock to our officers, directors, employees or consultants eligible to receive the awards under the Carbon Plans.

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

Restricted Stock

As of September 30, 2019, approximately 748,000 shares of restricted stock have been granted under the terms of the Carbon Plans. Restricted stock awards for employees vest ratably over a three-year service period or cliff vest at the end of a three-year service period. For non-employee directors, the awards vest upon the earlier of a change in control of us or the date their membership on the Board of Directors is terminated other than for cause. During the nine months ended September 30, 2019, approximately 105,000 restricted stock units vested.

Compensation costs recognized for these restricted stock grants were approximately $204,000 and $607,000 for the three and nine months ended September 30, 2019, respectively, and approximately $187,000 and $537,000 for the three and nine months ended September 30, 2018, respectively. As of September 30, 2019, there was approximately $1.5 million unrecognized compensation costs related to these restricted stock grants which we expect to be recognized over the next 6.5 years.

16

Restricted Performance Units

As of September 30, 2019, approximately 699,000 shares of performance units have been granted under the terms of the Carbon Plans. Performance units represent a contractual right to receive one share of our common stock subject to the terms and conditions of the agreements, including the achievement of certain performance measures relative to a defined peer group or the growth of certain performance measures over a defined period of time as well as, in some cases, continued service requirements. During the nine months ended September 30, 2019, approximately 95,000 performance units vested.

We account for the performance units granted during 2017 through 2019 at their fair value determined at the date of grant, which were $7.20, $9.80 and $10.00 per share, respectively. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At September 30, 2019, we estimated that none of the performance units granted in 2017 through 2019 would vest, and, accordingly, no compensation cost has been recorded for these performance units. We estimated that it was probable that the performance units granted in 2015 and 2016 would vest and therefore compensation costs of approximately $43,000 and $135,000 related to these performance units were recognized for the nine months ended September 30, 2019 and 2018, respectively. As of September 30, 2019, compensation costs related to the performance units granted in 2015 and 2016 have been fully recognized. As of September 30, 2019, if change in control and other performance provisions pursuant to the terms and conditions of these award agreements are met in full, the estimated unrecognized compensation cost related to outstanding performance units would be approximately $3.8 million.

NOTE 11 – EARNINGS (LOSS) PER COMMON SHARE

Basic earnings (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders for the period by the basic weighted average number of common shares outstanding during the period. 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 September 30, 2019 and 2018, approximately 275,000 and 497,000 shares, respectively, and for the nine months ended September 30, 2019 and 2018, approximately 275,000 and 280,000 shares, respectively, were considered anti-dilutive and were excluded from the computation of diluted earnings per share.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands, except per share amounts)	2019		2018			2019		2018
Net income (loss) attributable to controlling interests before preferred shares	$	3,182	$	(725	)	$	5,311	$	2,264
Less: net income attributable to preferred shares – preferred return		75		-			225		-
Net income (loss) attributable to common stockholders, basic		3,107		(725	)		5,086		2,264
Less: warrant derivative gain		-		-			-		(225	)
Less: beneficial conversion feature		-		-			-		(1,125	)
Less: deemed dividend for convertible preferred shares		-		(77	)		-		(147	)
Net income (loss) attributable to common stockholders, diluted		3,107		(802	)		5,086		767
Weighted-average number of common shares outstanding, basic		7,839		7,701			7,780		7,466
Add dilutive effects of non-vested shares of restricted stock and restricted performance units		302		-			302		315
Weighted-average number of common shares outstanding, diluted		8,141		7,701			8,082		7,781
Net income (loss) per common share, basic	$	0.40	$	(0.09	)	$	0.65	$	0.30
Net income (loss) per common share, diluted	$	0.38	$	(0.10	)	$	0.63	$	0.10

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Series B Convertible Preferred Stock - Related Party

In connection with the closing of the Seneca Acquisition, we raised $5.0 million through the issuance of 50,000 shares of Series B Convertible Preferred Stock, par value $0.01 per share (“Preferred Stock”) 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 $449,000 as of September 30, 2019 and increased by $225,000 during the nine months ended September 30, 2019.

NOTE 12 – INCOME TAXES

We recognize deferred income tax assets and liabilities for the estimated future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. We have net operating loss carryforwards available in certain jurisdictions to reduce future taxable income. Future tax benefits 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 September 30, 2019, the Company has established a full valuation allowance against the balance of net deferred tax assets.

NOTE 13 – FAIR VALUE MEASUREMENTS

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

(in thousands)	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Total
September 30, 2019
Assets:
Commodity derivatives	$	-	$	9,794	$	-	$	9,794
December 31, 2018
Assets:
Commodity derivatives	$	-	$	7,022	$	-	$	7,022

Commodity Derivative

As of September 30, 2019, our commodity derivative financial instruments are comprised of natural gas and oil swaps and costless collars. The fair values of these agreements are determined under an income valuation technique. The valuation model requires a variety of inputs, including contractual terms, published forward prices, volatilities for options and discount rates, as appropriate. Our estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, our credit worthiness and the time value of money. The consideration of these factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. All the significant inputs are observable, either directly or indirectly; therefore, our derivative instruments are included within the Level 2 fair value hierarchy.

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

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

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

We assume, at times, certain firm transportation contracts as part of our acquisitions of oil and natural gas properties. The fair value of the firm transportation contract obligations was determined based upon the contractual obligations assumed by us and discounted based upon our effective borrowing rate.

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

Debt Discount

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

Asset Retirement Obligation

The fair value of our asset retirement obligation liability is recorded in the period in which it is incurred or assumed by taking into account the cost of abandoning oil and gas wells ranging from $20,000 to $45,000, which is based on our historical experience and industry expectations for similar work; the estimated timing of reclamation ranging from one to 75 years based on estimates from reserve engineers; an inflation rate between 1.52% to 2.79%; and a credit adjusted risk-free rate between 3.28% to 8.27%, which takes into account our credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. During the nine months ended September 30, 2019, we did not record any additions to asset retirement obligations. We use the income valuation technique to estimate the fair value of asset retirement obligations using the amounts and timing of expected future dismantlement costs, credit-adjusted risk-free rates and time value of money. 

Class B Units

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

NOTE 14 – COMMODITY DERIVATIVES

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

We have entered into swap and costless collar derivative agreements to hedge a portion of our oil and natural gas production through 2022. As of September 30, 2019, these derivative agreements consisted of the following:

	Natural Gas Swaps*				Natural Gas Collars*
			Weighted Average				Weighted Average Price
Year	MMBtu		Price (a)		MMBtu		Range (a)
2019		3,735,000	$	2.83		92,000	$	2.60 – $3.03
2020		12,433,000	$	2.73		1,128,0000	$	2.40 – $2.75
2021		6,448,000	$	2.58		65,000	$	2.40 – $2.75

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	Oil Swaps*								Oil Collars*
Year	WTI Bbl		Weighted Average Price (b)		Brent Bbl		Weighted Average Price (c)		WTI Bbl		Weighted Average Price (b)		Brent Bbl		Weighted Average Price (c)
2019		70,835	$	53.36		54,091	$	65.45		5,200	$	47.50 - $57.35		16,400	$	47.00 - $75.00
2020		121,147	$	55.37		162,482	$	65.67		28,200	$	47.00 - $60.15		57,900	$	47.00 - $75.00
2021		-	$	-		86,341	$	67.12		49,500	$	47.00 - $60.15		130,800	$	47.00 - $75.00
2022		-	$	-		-	$	-		-	$	-		90,800	$	50.00 - $61.00

*	Includes 100% of Carbon California’s outstanding derivative hedges at September 30, 2019, and not our proportionate share.
(a)	NYMEX Henry Hub Natural Gas futures contract for the respective period.
(b)	NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective period.
(c)	Brent future contracts for the respective period.

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

The following table summarizes the fair value of the derivatives recorded in the unaudited condensed consolidated balance sheets. These derivative instruments are not designated as cash flow hedging instruments for accounting purposes:

(in thousands)	September 30, 2019		December 31, 2018
Commodity derivative contracts:
Commodity derivative asset	$	6,722	$	3,517
Commodity derivative asset – non-current	$	3,072	$	3,505

The table below summarizes the commodity settlements and unrealized gains and losses related to the Company’s derivative instruments for the three and nine months ended September 30, 2019 and 2018. These commodity derivative settlements and unrealized gains and losses are recorded and included in commodity derivative income or loss in the accompanying unaudited condensed consolidated statements of operations. 

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands)	2019		2018			2019		2018
Commodity derivative contracts:
Settlement gains (losses)	$	2,429	$	(1,108	)	$	2,198	$	(2,169	)
Unrealized gains (losses)		3,166		(2,794	)		2,771		(8,381	)
Total settlement and unrealized gains (losses), net	$	5,595	$	(3,902	)	$	4,969	$	(10,550	)

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

We net our derivative instrument fair value amounts 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 September 30, 2019.

							Net
	Gross						Recognized
	Recognized			Gross			Fair Value
	Assets/			Amounts			Assets/
Balance Sheet Classification (in thousands)	Liabilities			Offset			Liabilities
Commodity derivative assets:
Commodity derivative asset	$	7,236		$	(514	)	$	6,722
Commodity derivative asset – non-current		4,275			(1,203	)		3,072
Total derivative assets	$	11,511		$	(1,717	)	$	9,794
Commodity derivative liabilities:
Commodity derivative liability	$	(514	)	$	514		$	-
Commodity derivative liability – non-current		(1,203	)		1,203			-
Total derivative liabilities	$	(1,717	)	$	1,717		$	-

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

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NOTE 15 – COMMITMENTS AND CONTINGENCIES

Delivery Commitments

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

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

As of September 30, 2019, the remaining commitment related to the firm transportation contracts assumed in the EXCO Acquisition in October 2016 and the OIE Membership Acquisition is $15.6 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 processing agreement expiring in 2022. We have an option to extend the term of the agreement by another five years. The related demand charges for volume commitments over the remaining term of the agreement are approximately $1.8 million per year. We will pay a processing fee of $2.50 per Mcf for the term of the agreement, with a minimum annual volume commitment of 720,000 Mcf.

Capital Commitments

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

NOTE 16 – SUPPLEMENTAL CASH FLOW DISCLOSURE

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

	Nine Months Ended September 30,
(in thousands)	2019			2018
Cash paid during the period for:
Interest	$	6,897		$	2,770
Non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	(1,195	)	$	(491	)
Adjustments to OIE Membership Acquisition purchase price	$	1,317		$	-
Increase in asset retirement obligations	$	-		$	3,590
Non-cash acquisition of Carbon California interests	$	-		$	(18,906	)
Carbon California Acquisition on February 1, 2018	$	-		$	17,114
Obligations assumed with Seneca asset purchase	$	-		$	330
Accrued dividend for convertible preferred stock	$	-		$	148
Beneficial conversion feature for convertible preferred stock	$	-		$	1,125
Exercise of warrant derivative	$	-		$	(1,792	)

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

The following discussion includes forward-looking statements about our business, financial condition and results of operations, including discussions about management’s expectations for our business. These statements represent projections, beliefs and expectations based on current circumstances and conditions, and you should not construe these statements either as assurances of performance or as promises of a given course of action. Instead, various known and unknown factors may cause our actual performance and management’s actions to vary, and the results of these variances may be both material and adverse. A description of material factors known to us that may cause our results to vary or may cause management to deviate from its current plans and expectations, is set forth under “Risk Factors.” The following discussion should be read in conjunction with “Forward-Looking Statements,” “Risk Factors” and our unaudited condensed consolidated financial statements, including the notes thereto appearing elsewhere in this Quarterly Report on Form 10-Q and the information included or incorporated by reference in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018 (the “2018 Annual Report on Form 10-K”).

General Overview

Carbon is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil, natural gas and natural gas liquids properties located in the United States. We currently develop and operate oil and gas properties in the Appalachian Basin in Kentucky, Ohio, Tennessee, Virginia and West Virginia, in the Illinois Basin in Illinois and Indiana, and in the Ventura Basin in California through our majority-owned subsidiaries. We own 100% of the outstanding interests of Carbon Appalachia and Nytis Exploration (USA) Inc., a Delaware corporation (“Nytis USA”), which in turn owns 98.11% of Nytis LLC. Nytis LLC holds interests in our operating subsidiaries, which include 46 consolidated partnerships and 18 non-consolidated partnerships. We own 53.92% of Carbon California, which we consolidate as a majority-owned subsidiary. We focus on conventional and unconventional reservoirs, including shale, tight sands and coalbed methane. Our executive offices are in Denver, Colorado and we maintain offices in Lexington, Kentucky, and Santa Paula, California from which we conduct our oil and gas operations.

At September 30, 2019, our proved developed reserves were comprised of 22% oil and natural gas liquids (“NGL”) and 78% natural gas. Our current capital expenditure program is focused on the acquisition and development of oil and natural gas properties in areas where we currently operate. We believe that our asset and lease position, combined with our low operating expense structure and technical expertise, provides us with a portfolio of opportunities for the development of our oil and natural gas properties. Our growth plan is centered on the following activities:

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

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

Factors That Significantly Affect Our Financial Condition and Results of Operations

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

	2017		2018								2019
	Q4		Q1		Q2		Q3		Q4		Q1		Q2		Q3
Oil (Bbl)	$	55.39	$	62.89	$	67.90	$	69.50	$	58.83	$	54.90	$	59.96	$	56.43
Natural Gas (MMBtu)	$	2.87	$	3.13	$	2.77	$	2.88	$	3.62	$	3.00	$	2.57	$	2.38

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. 

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We use the full cost method of accounting for our oil and gas properties and perform a ceiling test quarterly. The ceiling calculation utilizes a rolling 12-month average commodity price. We did not recognize an impairment for the three and nine months ended September 30, 2019 and 2018.

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

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

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

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

Operational Highlights

During 2018 and the first three quarters of 2019, we concentrated our efforts on the acquisition and development of producing properties through the acquisitions consummated by Carbon California and Carbon Appalachia. In December 2018, we completed the purchase of Old Ironsides’ interests in Carbon Appalachia, resulting in ownership of 100% of Carbon Appalachia (“OIE Membership Acquisition”). Our field development activities have consisted principally of oil-related remediation and return to production and recompletion projects in California. Since closing these acquisitions, we have focused on operating efficiencies and reduction of operating expenses, optimization of natural gas gathering and compression facilities, greater flexibility in moving our production to markets with more favorable pricing, and the identification of development project opportunities to provide more efficient and lower cost operations. During the third quarter of 2019, we commenced a three-well drilling program in California that we expect to complete by the end of 2019.

As of September 30, 2019, we owned working interests in approximately 7,800 gross wells (7,500 net), royalty interests located primarily in California, Illinois, Indiana, Kentucky, Ohio, Tennessee, Virginia, and West Virginia and held leasehold positions in approximately 336,400 net developed acres and approximately 1,274,000 net undeveloped acres. Approximately 70% of the undeveloped acreage is held by production and of the remaining undeveloped acreage, approximately 87% have lease terms of greater than five years remaining in the primary term or contractual extension periods.

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

Recent Developments and Factors Affecting Comparability

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

Carbon Appalachia

OIE Membership Acquisition

In December 2018, we completed the acquisition of all of the Class A Units of Carbon Appalachia owned by Old Ironsides for a purchase price of $58.1 million, subject to customary and standard purchase price adjustments. As a result of the OIE Membership Acquisition, we now hold all of the issued and outstanding ownership interests of Carbon Appalachia, along with its direct and indirect subsidiaries (Carbon Appalachia Group, LLC, Carbon Tennessee Mining Company, LLC, Carbon Appalachia Enterprises, LLC, Carbon West Virginia Company, LLC, Cranberry Pipeline Corporation, Knox Energy, LLC, Coalfield Pipeline Company and Appalachia Gas Services Company, LLC). The OIE Membership Acquisition was funded with cash, debt and the issuance of notes to Old Ironsides. See Note 3 – Acquisitions in the unaudited condensed consolidated financial statements in Item 1 for additional information on the OIE Membership Acquisition.

Liberty Acquisition

In July 2018, we completed an acquisition of 54 operated oil and gas wells covering approximately 55,000 gross acres (22,000 net) and the associated mineral interests in the Appalachian Basin for a purchase price of $3.0 million, subject to customary and standard purchase price adjustments (the “Liberty Acquisition”).  The Liberty Acquisition increased our working interest in the acquired wells from 60% to 100%.  The Liberty Acquisition was funded through borrowings under our previous credit facility. The Liberty Acquisition was accounted for as a non-significant asset acquisition.

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Carbon California

Seneca Acquisition

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

Principal Components of Our Cost Structure

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

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

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

● Production and property taxes.  Production 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. Certain of these costs are recovered as management reimbursements in place with Carbon California and, prior to the completion of the OIE Membership Acquisition on December 31, 2018, Carbon Appalachia.

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

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

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Results of Operations

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

The following discussion and analysis relates to items that have affected our results of operations for the three months ended September 30, 2019 and 2018. The following table sets forth, for the periods presented, selected historical unaudited condensed consolidated statements of operations and production data. The information contained in the table below should be read in conjunction with the Company’s unaudited condensed consolidated financial statements and notes thereto and the information under “Forward Looking Statements” below.

	Three Months Ended
	September 30,						Percent
(in thousands, except production and per unit data)	2019			2018 (1)			Change
Revenue:
Natural gas sales	$	11,963		$	4,372			174	%
Natural gas liquids sales		10			406			(98	%)
Oil sales		9,049			11,850			(24	%)
Transportation and handling		304			-			*
Marketing gas sales		3,491			-			*
Commodity derivative loss		5,595			(3,902	)		*
Other income		123			16			663	%
Total revenues		30,535			12,742			140	%
Expenses:
Lease operating expenses		7,689			4,767			61	%
Pipeline operating expenses		2,614			-			*
Transportation costs		1,593			1,433			11	%
Production and property taxes		16			743			(98	%)
Marketing gas purchases		3,872			-			*
General and administrative		2,852			3,517			(19	%)
General and administrative – related party reimbursement		-			(1,170	)		*
Depreciation, depletion and amortization		4,112			2,731			51	%
Accretion of asset retirement obligations		420			206			104	%
Total expenses		23,168			12,227			89	%
Operating income	$	7,367		$	515			*
Other income (expense):
Interest expense, net		(3,047	)		(1,127	)		170	%
Equity investment income		32			157			*
Total other (expense)	$	(3,015	)	$	(970	)		*
Production data:
Natural gas (Mcf)		5,392,453			1,357,350			297	%
Oil (Bbl)		147,160			165,427			(11	%)
Natural gas liquids (Bbl)		2,000			11,055			(82	%)
Combined (Mcfe)		6,287,413			2,416,242			160	%
Average prices before effects of hedges:
Natural gas (per Mcf)	$	2.22		$	3.22			(31	%)
Oil (per Bbl)	$	61.49		$	71.63			(14	%)
Natural gas liquids (per Bbl)	$	4.98		$	36.70			(86	%)
Combined (per Mcfe)	$	3.34		$	6.88			(51	%)
Average prices after effects of hedges**:
Natural gas (per Mcf)	$	2.67		$	3.29			(19	%)
Oil (per Bbl)	$	61.55		$	64.29			(4	%)
Natural gas liquids (per Bbl)	$	4.98		$	36.70			(86	%)
Combined (per Mcfe)	$	3.73		$	6.42			(42	%)
Average costs (per Mcfe):
Lease operating expenses	$	1.22		$	1.97			(38	%)
Transportation costs	$	0.25		$	0.59			(58	%)
Production and property taxes	$	-		$	0.31			(100	%)
Cash-based general and administrative expense, net of related party reimbursement	$	0.42		$	0.89			(53	%)
Depreciation, depletion and amortization	$	0.65		$	1.13			(42	%)

*	Not meaningful or applicable
**	Includes effect of settled commodity derivative gains and losses
(1)	Excludes Carbon Appalachia activity during 2018 as Carbon Appalachia did not consolidate until December 31, 2018 upon the closing of the OIE Membership Acquisition. See Recent Developments and Factors Affecting Comparability.

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Natural gas, natural gas liquids, and oil sales – Sales of natural gas, natural gas liquids and oil increased approximately 26% for the three months ended September 30, 2019 compared to the same period in 2018, primarily due to a 160% increase in natural gas, natural gas liquids and oil sales volumes, partially offset by a 51% decrease in combined product pricing. The increases in production were a direct result of the acquisition of Carbon Appalachia and the resultant consolidation of the related activity for the three months ended September 30, 2019. Carbon Appalachia operating results are included in each of the three months ended September 30, 2019 whereas no Carbon Appalachia results were included in the three months ended September 30, 2018.

Commodity derivative gains and losses – To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we enter into derivative contracts including fixed price swap contracts and costless collars. Because we do not designate these derivatives as cash flow hedges, they do not receive hedge accounting treatment and all mark-to-market gains or losses, as well as settlement gains or losses on the derivative instruments, are currently recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these contracts as oil and natural gas futures prices fluctuate relative to the fixed price we will receive from these contracts. For the three months ended September 30, 2019 and 2018, we had hedging gains of approximately $5.6 million and hedging losses of approximately $3.9 million, respectively.

Lease operating expenses – Lease operating expenses for the three months ended September 30, 2019 increased primarily due to the OIE Membership Acquisition and the resultant increased production volumes. On a per Mcfe basis, lease operating expenses decreased to $1.22 per Mcfe for the three months ended September 30, 2019 from $1.97 per Mcfe for the three months ended September 30, 2018. We experience higher costs on a per Mcfe basis associated with the production of oil versus gas. Oil production accounted for approximately 41% of our production mix for the three months ended September 30, 2018 and 14% for the three months ended September 30, 2019.

Transportation costs – Transportation costs for the three months ended September 30, 2019 increased due to an increase in production as a result of the OIE Membership Acquisition. On a per Mcfe basis, these expenses decreased from $0.59 per Mcfe for the three months ended September 30, 2018 to $0.25 per Mcfe for the three months ended September 30, 2019.

Production and property taxes – Production and property taxes decreased for the three months ended September 30, 2019 due to decreased ad valorem estimated tax rates. Production taxes averaged approximately 3.5% and 1.9% of product sales for the three months ended September 30, 2019 and 2018, respectively. Production taxes associated with oil production are generally lower on a per Mcfe basis versus gas production. Oil production accounted for approximately 41% of our production mix for the three months ended September 30, 2018 and 14% for the three months ended September 30, 2019.

Depreciation, depletion and amortization (“DD&A”) – DD&A increased for the three months ended September 30, 2019 primarily due to the consolidation of Carbon Appalachia. On a per Mcfe basis, DD&A decreased from $1.13 per Mcfe for the three months ended September 30, 2018 to $0.65 per Mcfe for the three months ended September 30, 2019. The decrease in the depletion rate is primarily attributable to the consolidation of Carbon Appalachia.

General and administrative expenses – General and administrative expenses increased for the three months ended September 30, 2019, primarily due to the consolidation of Carbon Appalachia. As a result of the consolidation of Carbon Appalachia during the three months ended September 30, 2019, management reimbursements which offset general and administrative expenses decreased by approximately $1.2 million compared to the three months ended September 30, 2018.

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We define the term cash-based general and administrative expense (non-GAAP measure) as consolidated general and administrative expense adjusted to exclude non-cash stock-based compensation and related party reimbursements. On a per Mcfe basis, cash-based general and administrative expenses, net of related party reimbursements, decreased from $0.89 per Mcfe for the three months ended September 30, 2018 to $0.42 per Mcfe for the three months ended September 30, 2019. Cash-based general and administrative expenses for the three months ended September 30, 2019 and 2018 are summarized in the following table:

General and administrative expenses	Three Months Ended September 30,
(in thousands)	2019			2018
General and administrative expenses	$	2,852		$	3,517
Adjustments:
Stock-based compensation		(204	)		(187	)
General and administrative – related party reimbursement		-			(1,170	)
Cash-based general and administrative expense	$	2,648		$	2,160

Interest expense, net – Interest expense, net increased for the three months ended September 30, 2019, primarily due to higher outstanding debt balances related to borrowings to complete the OIE Membership Acquisition and the Seneca Acquisition in 2018.

Transportation and handling, marketing gas sales, pipeline operating expenses and marketing gas purchases – Subsequent to the OIE Membership Acquisition on December 31, 2018, we consolidate Carbon Appalachia operations. The associated revenues and expenses are presented within our unaudited consolidated statements of operations during the three months ended September 30, 2019. These operations were not presented in our unaudited consolidated statements of operations during the three months ended September 30, 2018.

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Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018

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

	Nine Months Ended
	September 30,						Percent
(in thousands, except production and per unit data)	2019			2018 (1)			Change
Revenue:
Natural gas sales	$	45,495		$	11,835			284	%
Natural gas liquids sales		451			1,119			(60	%)
Oil sales		27,940			22,924			22	%
Transportation and handling		1,361			-			*
Marketing gas sales		11,656			-			*
Commodity derivative loss		4,969			(10,550	)		(147	%)
Other income		820			35			2243	%
Total revenues		92,692			25,363			265	%
Expenses:
Lease operating expenses		21,784			10,824			101	%
Pipeline operating expenses		8,650			-			*
Transportation costs		4,392			3,786			16	%
Production and property taxes		3,692			1,792			106	%
Marketing gas purchases		14,969			-			*
General and administrative		11,489			9,007			28	%
General and administrative – related party reimbursement		-			(3,383	)		(100	%)
Depreciation, depletion and amortization		11,973			6,202			93	%
Accretion of asset retirement obligations		1,219			510			139	%
Total expenses		78,168			28,738			172	%
Operating income (loss)	$	14,524		$	(3,375	)		*
Other income (expense):
Interest expense, net		(9,772	)		(3,331	)		193	%
Warrant derivative gain		-			225			*
Gain on derecognized equity investment in affiliate-Carbon California		-			5,390			*
Equity investment income		73			1,121			*
Total other (expense) income	$	(9,699	)	$	3,405			*
Production data:
Natural gas (Mcf)		16,236,149			4,205,890			286	%
Oil (Bbl)		444,926			327,028			36	%
Natural gas liquids (Bbl)		26,990			29,454			(8	%)
Combined (Mcfe)		19,067,645			6,344,782			201	%
Average prices before effects of hedges:
Natural gas (per Mcf)	$	2.80		$	2.81			0	%
Oil (per Bbl)	$	62.80		$	70.10			(10	%)
Natural gas liquids (per Bbl)	$	16.72		$	37.97			(56	%)
Combined (per Mcfe)	$	3.87		$	5.65			(32	%)
Average prices after effects of hedges**:
Natural gas (per Mcf)	$	2.95		$	2.89			2	%
Oil (per Bbl)	$	62.42		$	62.51			0	%
Natural gas liquids (per Bbl)	$	16.72		$	37.97			(56	%)
Combined (per Mcfe)	$	3.99		$	5.31			(25	%)
Average costs (per Mcfe):
Lease operating expenses	$	1.14		$	1.71			(33	%)
Transportation costs	$	0.23		$	0.60			(62	%)
Production and property taxes	$	0.19		$	0.28			(32	%)
Cash-based general and administrative expense, net of related party reimbursement	$	0.57		$	0.78			(27	%)
Depreciation, depletion and amortization	$	0.63		$	0.98			(36	%)

*	Not meaningful or applicable
**	Includes effect of settled commodity derivative gains and losses
(1)	Includes Carbon California activity for the period of consolidation from February 1, 2018 through September 30, 2018 and does not include Carbon Appalachia activity during 2018 as Carbon Appalachia did not consolidate until December 31, 2018 upon the closing of the OIE Membership Acquisition. See Recent Developments and Factors Affecting Comparability.

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Natural gas, natural gas liquids, and oil sales – Sales of natural gas, natural gas liquids and oil increased approximately 106% for the nine months ended September 30, 2019 compared to the same period in 2018 primarily due to a 201% increase in natural gas, natural gas liquids and oil sales volumes, partially offset by a 32% decrease in combined product pricing. The increases in production were a direct result of the acquisitions of Carbon Appalachia and Carbon California and the resultant consolidation of the related activity for the nine months ended September 30, 2019. Carbon Appalachia operating results are included in each of the nine months ended September 30, 2019 whereas no Carbon Appalachia results were included in the nine months ended September 30, 2018. Additionally, the December 2017 California wildfires significantly impacted Carbon California results of operations for the nine months ended September 30, 2018. Carbon California oil production was not impacted during the nine months ended September 30, 2019. Finally, the Seneca Acquisition closed May 1, 2018, and therefore operations for the nine months ended September 30, 2018 include only five months of operations from the assets acquired compared to their inclusion for all nine months during 2019.

Commodity derivative gains and losses – To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we enter into derivative contracts including fixed price swap contracts and costless collars. Because we do not designate these derivatives as cash flow hedges, they do not receive hedge accounting treatment and all mark-to-market gains or losses, as well as settlement gains or losses on the derivative instruments, are currently recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these contracts as oil and natural gas futures prices fluctuate relative to the fixed price we will receive from these contracts. For the nine months ended September 30, 2019 and 2018, we had hedging gains of approximately $5.0 million and hedging losses of approximately $10.6 million, respectively.

Lease operating expenses – Lease operating expenses for the nine months ended September 30, 2019 increased primarily due to the OIE Membership Acquisition and the resultant increased production volumes. Expenses during the nine months ended September 30, 2018 were also lower as a result of the December 2017 California wildfires. On a per Mcfe basis, lease operating expenses decreased to $1.14 per Mcfe for the nine months ended September 30, 2019 from $1.71 per Mcfe for the nine months ended September 30, 2018. We experience higher costs on a per Mcfe basis associated with the production of oil versus gas. Oil production accounted for approximately 31% of our production mix for the nine months ended September 30, 2018 and 14% for the nine months ended September 30, 2019.

Transportation costs – Transportation costs for the nine months ended September 30, 2019 increased due to an increase in production as a result of the OIE Membership Acquisition and a full nine months of Carbon California operations, including Seneca Acquisition assets. On a per Mcfe basis, these expenses decreased from $0.60 per Mcfe for the nine months ended September 30, 2018 to $0.23 per Mcfe for the nine months ended September 30, 2019.

Production and property taxes – Production and property taxes increased for the nine months ended September 30, 2019 due to increased oil and natural gas sales as a result of the consolidation of Carbon Appalachia and a full nine months of Carbon California production, partially offset due to decreased ad valorem estimated tax rates utilized. Production taxes averaged approximately 3.6% and 2.2% of product sales for the nine months ended September 30, 2019 and 2018, respectively. Production taxes associated with oil production are generally lower on a per Mcfe basis versus gas production. Oil production accounted for approximately 31% of our production mix for the nine months ended September 30, 2018 and 14% for the nine months ended September 30, 2019.

Depreciation, depletion and amortization (“DD&A”) – DD&A increased for the nine months ended September 30, 2019 primarily due to the consolidation of Carbon Appalachia and a full nine months of Carbon California operations, including the Seneca Acquisition assets. On a per Mcfe basis, DD&A decreased from $0.98 per Mcfe for the nine months ended September 30, 2018 to $0.63 per Mcfe for the nine months ended September 30, 2019. The decrease in the depletion rate is primarily attributable to the consolidation of Carbon Appalachia.

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General and administrative expenses – General and administrative expenses increased for the nine months ended September 30, 2019 primarily due to the consolidation of Carbon Appalachia and a full nine months of Carbon California operations. As a result of the consolidation of Carbon Appalachia and Carbon California during the nine months ended September 30, 2019, management reimbursements which offset general and administrative expenses, decreased by approximately $3.4 million compared to the nine months ended September 30, 2018. On a per Mcfe basis, cash-based general and administrative expenses, net of related party reimbursements, decreased from $0.78 per Mcfe for the nine months ended September 30, 2018 to $0.57 per Mcfe for the nine months ended September 30, 2019. Cash-based general and administrative expenses for the nine months ended September 30, 2019 and 2018 are summarized in the following table:

General and administrative expenses	Nine Months Ended September 30,
(in thousands)	2019			2018
General and administrative expenses	$	11,489		$	9,007
Adjustments:
Stock-based compensation		(650	)		(672	)
General and administrative – related party reimbursement		-			(3,383	)
Cash-based general and administrative expense	$	10,839		$	4,952

Interest expense, net – Interest expense, net increased for the nine months ended September 30, 2019 primarily due to higher outstanding debt balances related to borrowings to complete the OIE Membership Acquisition and the Seneca Acquisition in 2018.

Transportation and handling, marketing gas sales, pipeline operating expenses and marketing gas purchases – Subsequent to the OIE Membership Acquisition on December 31, 2018, we consolidate Carbon Appalachia operations. The associated revenues and expenses are presented within our unaudited consolidated statements of operations during the nine months ended September 30, 2019. These operations were not presented in our unaudited consolidated statements of operations during the nine months ended September 30, 2018.

Liquidity and Capital Resources

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

As of September 30, 2019, our liquidity was $19.5 million, consisting of cash on hand of $3.5 million and $16.0 million of available borrowing capacity on our credit facilities.

On December 31, 2018, we closed the OIE Membership Acquisition. As a result, we now own 100% of all interests in Carbon Appalachia; therefore, we receive 100% of the cash flows associated with Carbon Appalachia.

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

Commodity Derivatives

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

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 2018 Annual Report on Form 10-K for further details of the risks associated with our hedging activities. In the future, we may determine to increase or decrease our hedging positions. See Note 14 – Commodity Derivatives in the unaudited condensed consolidated financial statements in Item 1 for more information, including our outstanding derivatives.

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Sources and Uses of Cash

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

	Nine Months Ended
	September 30,
(in thousands)	2019			2018
Net cash provided by operating activities	$	14,122		$	3,312
Net cash used in investing activities	$	(3,862	)	$	(44,406	)
Net cash (used in) provided by financing activities	$	(12,482	)	$	43,921

Operating Activities

Net cash provided by operating activities is primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and changes in working capital. Operating cash flows increased approximately $10.8 million for the nine months ended September 30, 2019 as compared to the same period in 2018. This increase was primarily due to increased revenues from the acquisition of producing oil and natural gas properties in the Appalachian Basin in the fourth quarter of 2018 and increased revenues from the consolidation of Carbon California, including the Seneca Acquisition.

Investment Activities

Net cash used in investing activities is primarily comprised of the acquisition, exploration and development of oil and natural gas properties, net of dispositions of oil and natural gas properties. Net cash used in investing activities decreased approximately $40.5 million for the nine months ended September 30, 2019 as compared to the same period in 2018, primarily due to the Seneca Acquisition.

Financing Activities

Net cash provided by or used in financing activities is primarily comprised of activities associated with our credit facilities. During the nine months ended September 30, 2019, the Company paid $2.0 million in principal associated with the Old Ironsides Notes, paid approximately $8.7 million in principal associated with the 2018 Credit Facility, and paid approximately $5.7 million in principal associated with the Senior Revolving Notes. The payments were partially offset by an increase in borrowings under the 2018 Credit Facility by approximately $4.0 million. During the nine months ended September 30, 2018, the Company increased borrowings by approximately $34.5 million, received $5.0 million in proceeds from the issuance of preferred stock to Yorktown, and received an equity contribution of $5.0 million from Prudential related to the Seneca Acquisition.

Capital Expenditures

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

	Nine Months Ended September 30,
(in thousands)	2019		2018
Drilling and development	$	4,003	$	940
Other		223		43,741
Total capital expenditures	$	4,226	$	44,681

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

Due 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. We have approximately $3.0 million to $5.0 million in planned capital expenditures for the remainder of 2019 as we complete our oil drilling program in California.

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Credit Facilities and Notes Payable

For a discussion of our long-term debt, see Note 7 – 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 September 30, 2019.

Critical Accounting Policies, Estimates, Judgments, and Assumptions

Our critical accounting policies and estimates are set forth in “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations- Critical Accounting Policies, Estimates, Judgments, and Assumptions” in our 2018 Annual Report on Form 10-K. As of September 30, 2019, there have been no significant changes to our critical accounting policies and estimates since our 2018 Annual Report on Form 10-K was filed.  

Forward Looking Statements

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

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

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

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

● our future financial condition and results of operations;

● our future revenues, cash flows, and expenses;

● our access to capital and our anticipated liquidity;

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

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

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

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

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

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

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

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

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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, Patrick R. McDonald, and our Chief Financial Officer, Kevin D. Struzeski, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of September 30, 2019. Based on this evaluation, they believe that as of September 30, 2019 our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (i) is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms; and (ii) is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Changes in internal control over financial reporting.  There were no changes in our internal control over financial reporting during the quarter ended September 30, 2019, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

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

ITEM 1A. Risk Factors

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

ITEM 6. Exhibits

Exhibit No.	Description
10.1	Second Amendment to the Amended and Restated Credit Agreement, dated August 14, 2019,  incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 15, 2019.
10.2*	Omnibus Annual Incentive Plan, dated August 9, 2019.
31.1*	Certification of Chief Executive Officer Pursuant to Rule 13a-15(e) / Rule 15d-15(e).
31.2*	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) / Rule 15(e)/15d-15(e).
32.1†	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2†	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
101*	Interactive data files pursuant to Rule 405 of Regulation S-T.

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

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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: November 13, 2019	By:	/s/ Patrick R. McDonald
		PATRICK R. MCDONALD,
		Chief Executive Officer
Date: November 13, 2019	By:	/s/ Kevin D. Struzeski
		KEVIN D. STRUZESKI
		Chief Financial Officer

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