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, 2018

or

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

For the transition period from ___________ to ____________

Commission File Number: 000-02040

Carbon Energy Corporation

(Exact name of registrant as specified in its charter)

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

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

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

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

YES ☒               NO ☐

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

YES ☒               NO ☐

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

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

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

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

YES ☐               NO ☒

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

At November 12, 2018, there were 7,700,619 issued and outstanding shares of the Company’s common stock, $0.01 par value.

Carbon Energy Corporation 

TABLE OF CONTENTS

Part I - FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements	1
Consolidated Balance Sheets (unaudited)	1
Consolidated Statements of Operations (unaudited)	2
Consolidated Statements of Stockholders’ Equity (unaudited)	3
Consolidated Statements of Cash Flows (unaudited)	4
Notes to the Consolidated Financial Statements (unaudited)	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 4. Controls and Procedures	42
Part II - OTHER INFORMATION
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 6. Exhibits	43

i

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

CARBON ENERGY CORPORATION

Consolidated Balance Sheets

	September 30,			December 31,
(in thousands)	2018			2017
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	4,477		$	1,650
Accounts receivable:
Revenue		7,002			2,206
Trade receivable		1,562			-
Joint interest billings and other		-			349
Insurance receivable (Note 2)		871			802
Due from related parties		1,272			2,075
Commodity derivative asset		-			215
Prepaid expense, deposits and other current assets		2,051			783
Total current assets		17,235			8,080
Property and equipment (Note 4)
Oil and gas properties, full cost method of accounting:
Proved, net		128,093			34,178
Unproved		3,616			1,947
Other property and equipment, net		1,989			737
Total property and equipment, net		133,698			36,862
Investments in affiliates (Note 6)		13,459			14,267
Other non-current assets		3,200			800
Total assets	$	167,592		$	60,009
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities (Note 11)	$	14,378		$	11,218
Firm transportation contract obligations (Note 14)		52			127
Commodity derivative liability (Note 13)		6,502			-
Total current liabilities		20,932			11,345
Non-current liabilities:
Firm transportation contract obligations (Note 14)		115			134
Production and property taxes payable		849			520
Warrant liability (Note 12)		-			2,017
Asset retirement obligations (Note 5)		10,935			7,357
Credit facility (Note 7)		26,141			22,140
Long-term debt		65			-
Credit facility-related party (Note 7)		49,995			-
Commodity derivative liability (Note 13)		4,299			-
Total non-current liabilities		92,399			32,168
Commitments (Note 14)
Stockholders’ equity:
Preferred stock, $0.01 par value; authorized 1,000,000 shares, 50,000 shares issued and outstanding at September 30, 2018 and no shares issued and outstanding at December 31, 2017		1			-
Common stock, $0.01 par value; authorized 35,000,000 shares, 7,700,619 and 6,005,633 shares issued and outstanding at September 30, 2018 and December 31, 2017, respectively		77			60
Additional paid-in capital		75,858			58,813
Accumulated deficit		(45,863	)		(44,218	)
Total Carbon stockholders’ equity		30,073			14,655
Non-controlling interests		24,188			1,841
Total stockholders’ equity		54,261			16,496
Total liabilities and stockholders’ equity	$	167,592		$	60,009

See accompanying notes to Consolidated Financial Statements.

1 

 CARBON ENERGY CORPORATION

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands except per share amounts)	2018			2017			2018			2017
Revenue:
Natural gas sales	$	4,372		$	3,689		$	11,835		$	11,706
Natural gas liquid sales		406			-			1,119			-
Oil sales		11,850			997			22,924			3,189
Commodity derivative gain (loss)		(3,902	)		(499	)		(10,550	)		2,642
Other income		16			8			35			28
Total revenue		12,742			4,195			25,363			17,565
Expenses:
Lease operating expenses		4,767			1,605			10,824			4,311
Transportation and gathering costs		1,433			556			3,786			1,571
Production and property taxes		743			331			1,792			1,186
General and administrative		3,517			2,129			9,007			5,623
General and administrative - related party reimbursement		(1,170	)		(423	)		(3,383	)		(723	)
Depreciation, depletion and amortization		2,731			613			6,202			1,847
Accretion of asset retirement obligations		206			77			510			232
Total expenses		12,227			4,888			28,738			14,047
Operating (loss) income		515			(693	)		(3,375	)		3,518
Other income and (expense):
Interest expense		(1,127	)		(279	)		(3,331	)		(801	)
Warrant derivative gain		-			811			225			2,494
Equity investment loss		157			(285	)		6,511			(285	)
Total other (expense) income		(970	)		247			3,405			1,408
(Loss) income before income taxes		(455	)		(446	)		30			4,926
Provision for income taxes		-			-			-			-
Net (loss) income before non-controlling interests		(455	)		(446	)		30			4,926
Net (loss) income attributable to non-controlling interests		270			16			(2,234	)		92
Net (loss) income attributable to controlling interest	$	(725	)	$	(462	)	$	2,264		$	4,834
Net income (loss) per common share:
Basic	$	(0.09	)	$	(0.08	)	$	0.30		$	0.87
Diluted	$	(0.10	)	$	(0.08	)	$	0.10		$	0.36
Weighted average common shares outstanding:
Basic		7,701			5,628			7,466			5,579
Diluted		7,701			5,628			7,466			6,486

See accompanying notes to Consolidated Financial Statements.

2

 CARBON ENERGY CORPORATION

Consolidated Statements of Stockholders’ Equity

(Unaudited)

(in thousands)

	Common Stock				Preferred Stock				Additional paid			Non- controlling			Accumulated			Total Stockholders’
	Shares		Amount		Shares		Amount		in capital			interest			Deficit			Equity
Balances, December 31, 2017		6,006		60		-		-		58,813			1,841			(44,218	)		16,496
Stock based compensation		-		-		-		-		672			-			-			672
Vested restricted stock		59		1		-		-		(1	)		-			-			-
Vested performance units		108		1		-		-		(1	)		-			-			-
Preferred share issuance		-		-		50		1		4,999			-			-			5,000
Beneficial conversion feature		-		-		-		-		1,125			-			(1,125	)		-
Deemed dividend		-		-		-		-		147			-			(147	)		-
CCC warrant exercise - share issuance		1,528		15		-		-		8,312			16,466			-			24,793
CCC warrant exercise - liability extinguishment		-		-		-		-		1,792			-			-			1,792
Non-controlling interest contributions, net		-		-		-		-		-			5,478			-			5,478
Net income (loss)		-		-		-		-		-			(2,234	)		2,264			30
Balances, September 30, 2018		7,701	$	77		50	$	1	$	75,858		$	21,551		$	(43,226	)	$	54,261

See accompanying notes to Consolidated Financial Statements.

3

 CARBON ENERGY CORPORATION

Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended
	September 30,
(in thousands)	2018			2017
Cash flows from operating activities:
Net income	$	30		$	4,926
Items not involving cash:
Depreciation, depletion and amortization		6,202			1,847
Accretion of asset retirement obligations		510			232
Unrealized commodity derivative loss (gain)		8,381			(2,179	)
Warrant derivative gain		(225	)		(2,494	)
Stock-based compensation expense		672			752
Equity investment income		(6,511	)		315
Amortization of debt issuance costs		468			131
Other		-			(108	)
Net change in:
Accounts receivable		(2,975	)		863
Prepaid expenses, deposits and other current assets		456			(280	)
Accounts payable, accrued liabilities, firm transportation contract obligations, and other long-term obligations		(1,945	)		(1,425	)
Other non-current assets		(1,751	)		-
Net cash provided by operating activities		3,312			2,580
Cash flows from investing activities:
Development and acquisition of properties and equipment		(44,681	)		(1,268	)
Proceeds from sale of oil and gas properties and other assets		-			16
Other long-term assets		275			(56	)
Investment in affiliates		-			(6,798	)
Net cash used in investing activities		(44,406	)		(8,106	)
Cash flows from financing activities:
Proceeds from credit facility		34,529			7,210
Proceeds from preferred shares		5,000			-
Payments on credit facility		(14	)		(1,300	)
Payments of debt issuance costs		(586	)		(59	)
Contributions from non-controlling interests		5,000			-
Distributions to non-controlling interests		(8	)		(64	)
Net cash provided by (used in) financing activities		43,921			5,787
Net increase in cash and cash equivalents		2,827			261
Cash and cash equivalents, beginning of period		1,650			858
Cash and cash equivalents, end of period	$	4,477		$	1,119

See accompanying notes to Consolidated Financial Statements.

4

 CARBON ENERGY CORPORATION

Notes to Consolidated Financial Statements

(Unaudited)

Note 1 - Organization

Carbon Energy Corporation and its subsidiaries (referred to herein as “we”, “us”, the “Company” or “Carbon”) is an independent oil and gas company engaged in the exploration, development and production of oil and natural gas in the United States. The Company’s business is comprised of the assets and properties of Nytis Exploration (USA) Inc. (“Nytis USA”) and its subsidiary Nytis Exploration Company LLC (“Nytis LLC”) which conducts the Company’s operations in the Appalachian and Illinois Basins, Carbon California Operating Company, LLC (“CCOC”) and Carbon California Company, LLC (“Carbon California”) which conduct the Company’s operations in California, and the Company’s equity investment in Carbon Appalachian Company, LLC (“Carbon Appalachia”).

Appalachian and Illinois Basin Operations

Nytis LLC conducts operations for Carbon and Carbon Appalachia as illustrated in the following diagram.

5

Ventura Basin Operations

CCOC conducts our operations in the Ventura Basin of California. On February 1, 2018, an entity managed by Yorktown Partners, LLC (“Yorktown”) exercised a warrant it held to purchase shares of our common stock at an exercise price of $7.20 per share (the “California Warrant”), resulting in the issuance of 1,527,778 shares of our common stock. In exchange, we received Yorktown’s Class A Units of Carbon California representing approximately 46.96% of the then outstanding Class A Units of Carbon California (a profits interest of approximately 38.59%). As of February 1, 2018, we owned 56.4% of the voting and profits interests of Carbon California. On May 1, 2018, Carbon California closed the Seneca Acquisition. Following the exercise of the California Warrant by Yorktown and the Seneca Acquisition, we own 53.9% of the voting and profits interests and Prudential owns 46.1% voting and profits interest in Carbon California. As of February 1, 2018, we consolidate Carbon California for financial reporting purposes. The structure of the ownership of the operations and ownership of Carbon California is illustrated in the following diagram:

Note 2 - Summary of Significant Accounting Policies

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information. Accordingly, they do not include all the information and footnotes required by GAAP for complete financial statements. In the opinion of management, the accompanying unaudited condensed consolidated financial statements include all adjustments considered necessary to present fairly our financial position as of September 30, 2018, and our results of operations and cash flows for the three and nine months ended September 30, 2018 and 2017. Operating results for the three and nine months ended September 30, 2018, are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results, seasonality, and other factors. The unaudited condensed consolidated financial statements and related notes included in this Quarterly Report on Form 10-Q should be read in conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2017. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in our 2017 Annual Report on Form 10-K.

Principles of Consolidation

The unaudited condensed consolidated financial statements include the accounts of Carbon, Carbon California, CCOC, Nytis USA and its consolidated subsidiary, Nytis LLC. Carbon owns 100% of Nytis USA and CCOC. Nytis USA owns approximately 99% of Nytis LLC. Carbon owns 53.9% of Carbon California and Prudential owns 46.1% voting and profits interest in Carbon California.

Nytis LLC also holds an interest in 64 oil and gas partnerships. For the 47 partnerships where we have a controlling interest, the partnerships are consolidated. In these instances, we reflect the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on our unaudited consolidated statements of operations, non-controlling ownership interests in the net assets of the partnerships as non-controlling interests within stockholders’ equity on our unaudited consolidated balance sheets. All significant intercompany accounts and transactions have been eliminated.

6

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 interest 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.

Effective February 1, 2018, Yorktown exercised the California Warrant, which resulted in us acquiring Yorktown’s ownership interest in Carbon California in exchange for shares of our common stock. On May 1, 2018, Carbon California closed the Seneca Acquisition. Following the exercise of the California Warrant by Yorktown and the Seneca Acquisition, we own 53.9%, of the voting and profits interests, and Prudential owns 46.1%.

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 and is in receipt of a portion of partial funds associated with the claims as of September 30, 2018. Therefore, the Company has determined the receivable is collectible and is included in insurance receivable on the unaudited consolidated balance sheets. As of September 30, 2018, the Company has an insurance receivable of $871,000 and collected $2.7 million from the previously submitted claims.

Long-term Assets

Long-term assets are comprised of (i) debt issuance costs, (ii) bonds, and (iii) deferred registration fees associated with a registration statement for a possible equity offering of the Company’s Common Stock. We have recorded debt issuance costs and amortize the balance over the life of the loan. As of September 30, 2018, we have within non-current assets approximately $1.7 million of deferred financing costs associated with our credit facility and with Carbon California’s Senior Revolving Notes (note 7). As of September 30, 2018, we have incurred approximately $1.9 million for outside professional services in conjunction with the preparation of the completion of a registration statement associated with the possible offering. We will continue to accumulate deferred financing costs until the completion of the registration statement and a successful equity offering is commenced which at that time will be recognized as a financing charge and applied against the equity component of the transaction. If the raise is unsuccessful, the amount will be expensed in the current period.

Accounting for Oil and Gas Operations

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

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

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

7

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

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

For the three and nine months ended September 30, 2018, the Company did not recognize a ceiling test impairment as the Company’s full cost pool did not exceed the ceiling limitations. For the three months ended September 30, 2017, the Company did not recognize a ceiling test impairment as the Company’s full cost pool did not exceed the ceiling limitations.

Investments in Affiliates

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

If we hold between 20% and 50% of the voting interest in non-consolidated corporate affiliates or generally greater than a 3% to 5% interest of a partnership or limited liability company and can exert significant influence or control (e.g., through our influence with a seat on the board of directors or management of operations), the equity method of accounting is generally used to account for the investment. Equity method investments will increase or decrease by our share of the affiliate’s profits or losses and such profits or losses are recognized in our unaudited consolidated statements of operations. For our equity method investment in Carbon Appalachia, we use the hypothetical liquidation at book value method to recognize our share of the affiliate’s profits or losses. We review equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred.

Related Party Transactions

Management Reimbursements

In our role as manager of Carbon California and Carbon Appalachia, we received reimbursements for the provision of management from Carbon Appalachia of approximately $744,000 and $2.3 million for the three and nine months ended September 30, 2018, and $50,000 for the one month ended January 31, 2018, from Carbon California. These reimbursements are included in general and administrative - related party reimbursement on our unaudited consolidated statements of operations. Effective February 1, 2018, the management reimbursement received from Carbon California is eliminated at consolidation. This elimination was $650,000 for the period February 1, 2018 through September 30, 2018.

In addition to the management reimbursements, approximately $376,000 and $1.1 million in general and administrative expenses were reimbursed for the three and nine months ended September 30, 2018, from Carbon Appalachia, and $14,000 for the one month ended January 31, 2018, from Carbon California. General and administrative expenses reimbursed by Carbon California and eliminated upon consolidation were approximately $42,000 for the period February 1, 2018, through September 30, 2018.

8

Operating Reimbursements

In our role as operator of Carbon Appalachia, we receive reimbursements of operating expenses. These expenses are recorded directly to receivable - related party on our unaudited consolidated balance sheets and are therefore not included in our operating expenses on our unaudited consolidated statements of operations.

Carbon California Credit Facilities

The credit facilities of Carbon California, including the Senior Revolving Notes, Carbon California Notes and Carbon California 2018 Subordinated Notes (all defined below), are held by Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America or its affiliates (“Prudential”). See note 7.

Preferred Stock

In April 2018, we issued 50,000 shares of Preferred Stock to Yorktown in conjunction with our Seneca Acquisition. See note 9.

Old Ironsides Membership Interest Purchase Agreement 

On May 4, 2018, we entered into a Membership Interest Purchase Agreement with Old Ironsides to acquire all of Old Ironsides’ membership interests of Carbon Appalachia. Following the closing of the transaction we will own 100% of the issued and outstanding ownership in Carbon Appalachia and Carbon Appalachia will become a wholly-owned subsidiary of ours. See note 6.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to makes estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. There have been no changes in our critical accounting estimates from those that were disclosed in the 2017 Annual Report on Form 10-K. Actual results could differ from these estimates.

Earnings (Loss) Per Common Share

Basic earnings per common share is computed by dividing the net income (loss) attributable to common stockholders for the period by the weighted average number of common shares outstanding during the period. The shares of restricted stock granted to our officers, directors and employees are included in the computation of basic net income per share only after the shares become fully vested. Diluted earnings per common share includes both the vested and unvested shares of restricted. We issued 50,000 shares of Series B Convertible Preferred Stock, par value $0.01 per share (the “Preferred Stock”), and the difference between the carrying amount of the Preferred Stock in equity and the fair value of the Preferred Stock) is treated as a dividend for purposes of calculating earnings per common share. The Preferred Stock deemed dividend could potentially dilute basic earnings per common share in the future.

In periods when we report a net loss, all shares of restricted stock are excluded from the calculation of diluted weighted average shares outstanding because of its anti-dilutive effect on loss per share. As a result, all restricted stock is excluded from the calculation of diluted earnings per common share for the three months ended September 30, 2018. Potentially dilutive securities (restricted stock awards) included in the calculation of diluted earnings per share totaled 315,040 for the three months ended September 30, 2018. Potentially dilutive securities that are anti-dilutive totaled 315,040 for the three months ended September 30, 2018 and 901,109 for the three months ended September 30, 2017. The dilutive units did not have a material impact on our earnings per common share calculations for any of the periods presented.

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands except per share amounts)	2018			2017			2018			2017
Net income (loss) attributable to controlling interest	$	(725	)	$	(462	)	$	2,264		$	4,834
Less: warrant derivative gain		-			-			(225	)		(2,494	)
Less: deemed dividend for convertible preferred shares		(77	)		-			(147	)		-
Less: beneficial conversion feature		-			-			(1,125	)		-
Diluted net (loss) income	$	(802	)	$	(462	)	$	767		$	2,340
Basic weighted-average common shares outstanding during the period		7,701			5,628			7,466			5,579
Add dilutive effects of warrants and non-vested shares of restricted stock		-			-			315			907
Diluted weighted-average common shares outstanding during the period		7,701			5,628			7,781			6,486
Basic net (loss) income per common share	$	(0.09	)	$	(0.08	)	$	0.30		$	0.87
Diluted net (loss) income per common share	$	(0.10	)	$	(0.08	)	$	0.10		$	0.36

9

Recently Adopted Accounting Pronouncement

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 (collectively with ASU 2014-09, the “Revenue ASUs”) to clarify principal versus agent considerations. The Revenue ASUs allow for the use of either the full or modified retrospective transition method, and the standard is effective for annual reporting periods beginning after December 15, 2017 including interim periods within that period, with early adoption permitted for annual reporting periods beginning after December 15, 2016. We adopted the guidance using the modified retrospective method with the effective date of January 1, 2018. We did not record a cumulative-effect adjustment to the opening balance of retained earnings as no adjustment was necessary. The adoption of the Revenue ASUs did not impact net income or cash flows. See note 10 for the new disclosures required by the Revenue ASUs. 

Recently Issued Accounting Pronouncements

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)” (“ASU 2016-02”), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous GAAP standards. ASU 2016-02 is effective for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The Company is in the process of evaluating the effect of adopting ASU 2016-02 on the financial statements, accounting policies, and internal controls. The adoption is expected to result in an increase in the assets and liabilities recorded on its consolidated balance sheet and additional disclosures. The Company does not expect a material impact on its consolidated statement of operations.

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

 Note 3 - Acquisitions and Divestitures

Acquisition of Majority Control of Carbon California

Carbon California was formed in 2016 by us and entities managed by Yorktown and Prudential to acquire oil and gas producing assets in the Ventura Basin of California.

In connection with the entry into the limited liability company agreement of Carbon California, we received Class B Units and issued to Yorktown the California Warrant exercisable for shares of our common stock. The exercise price for the California Warrant was payable exclusively with Class A Units of Carbon California held by Yorktown and the number of shares of our common stock for which the California Warrant was exercisable was determined, as of the time of exercise, by dividing (a) the aggregate unreturned capital of Yorktown’s Class A Units of Carbon California by (b) the exercise price. The California Warrant had a term of seven years and included certain standard registration rights with respect to the shares of our common stock issuable upon exercise of the California Warrant.

The issuance of the Class B Units and the California Warrant were in contemplation of each other (note 6), and under non-monetary related party guidance, we accounted for the California Warrant, at issuance, based on the fair value of the California Warrant as of the date of grant (February 15, 2017) and recorded a long-term warrant liability with an associated offset to Additional Paid in Capital (“APIC”). Future changes to the fair value of the California Warrant were recognized in earnings. We accounted for the fair value of the Class B Units at their estimated fair value at the date of grant, which became our investment in Carbon California with an offsetting entry to Additional Paid In Capital (“APIC”). Additionally, we accounted for our 17.81% profits interest in Carbon California as an equity method investment until January 31, 2018.

10

On February 1, 2018, Yorktown exercised the California Warrant resulting in the issuance of 1,527,778 shares of our common stock in exchange for Yorktown’s Class A Units of Carbon California representing approximately 46.96% of the outstanding Class A Units of Carbon California (a profits interest of approximately 38.59%). After giving effect to the exercise on February 1, 2018, we owned 56.4% of the voting and profits interests of Carbon California. On May 1, 2018, Carbon California closed the Seneca Acquisition. Following the exercise of the California Warrant by Yorktown and the Seneca Acquisition, we own 53.9% of the voting and profits interests, and Prudential owns 46.1% voting and profits interest in Carbon California.

The exercise of the California Warrant and the acquisition of the additional ownership interest is accounted for as a step acquisition in which we obtained control in accordance with ASC 805, Business Combinations (“ASC 805”) (referred to herein as the “Carbon California Acquisition”). We recognized 100% of the identifiable assets acquired, liabilities assumed and the non-controlling interest at their respective fair value as of the date of the acquisition. We exchanged 1,527,778 common shares at a fair value of approximately $8.3 million ($5.45 per share), for 11,000 Class A Units of Carbon California, representing a 38.59% profits ownership interest in Carbon California. We followed the fair value method to allocate the consideration transferred to the identifiable net assets acquired and non-controlling interest (“NCI”) on a preliminary basis as follows:

	Amount  (in thousands)
Fair value of Carbon common shares transferred as consideration	$	8,326
Fair value of NCI		16,466
Fair value of previously held interest		7,244
Fair value of business acquired	$	32,036

Assets acquired and liabilities assumed are as follows:

	Amount (in thousands)
Cash	$	275
Accounts receivable:
Joint interest billings and other		690
Receivable - related party		1,610
Prepaid expense, deposits, and other current assets		1,723
Oil and gas properties:
Proved		56,477
Unproved		1,495
Other property and equipment, net		877
Other long-term assets		475
Accounts payable and accrued liabilities		(6,054	)
Commodity derivative liability - short-term		(916	)
Commodity derivative liability - long-term		(1,729	)
Asset retirement obligations - short-term		(384	)
Asset retirement obligations - long-term		(2,537	)
Subordinated Notes, related party, net		(8,874	)
Senior Revolving Notes, related party		(11,000	)
Notes payable		(92	)
Total net assets acquired	$	32,036

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

On the date of the acquisition, we derecognized our equity investment in Carbon California and recognized a gain of approximately $5.4 million based on the fair value of our previously held interest compared to its carrying value.

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

11

Seneca Acquisition

In October 2017, Carbon California signed a Purchase and Sale Agreement with Seneca Resources (“Seneca”) to acquire approximately 309 oil wells and approximately 5,700 gross acres (5,500 net) of oil and gas leases, and fee interests in and to certain lands, situated in the Ventura Basin, together with associated pipelines, facilities, equipment and other property rights. The transaction closed on May 1, 2018 for a purchase price of $43.0 million, subject to customary and standard purchase price adjustments. We contributed approximately $5.0 million to Carbon California to fund our portion of the purchase price, through the $5.0 Preferred Stock issuance. Prudential also contributed $5.0 million to fund its share of the equity portion of the purchase price. Carbon California funded the remaining purchase price from cash, increased borrowings under the Senior Revolving Notes and $3.0 million in proceeds from the issuance of Senior Subordinated Notes.

Utilizing the assistance of third-party valuation specialists, we considered various factors in our estimate of fair value of the acquired assets including (i) reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, including price differentials, (v) future cash flows, and (vi) working conditions and expected lives of vehicles and equipment.

We determined that substantially all of the fair value of the assets acquired related to proved oil and gas properties and, as such the Seneca Acquisition does not meet the definition of a business. Therefore, we have accounted for the transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired.

The fair value of the production assets were determined using the income approach using Level 3 inputs according to the ASC 820, Fair Value, hierarchy. The fair value of the other assets was determined using the market approach using Level 3 inputs. The determination of the fair value of the oil and gas and other property and equipment acquired and accounts payable and accrued liability assumed, required significant judgement, including estimates relating to the production assets and the other transaction costs. We recorded $639,000 in Asset Retirement Obligation (“ARO”), and $330,000 in assumed liabilities in connection with the Seneca Acquisition. We incurred transaction costs related to the Seneca Acquisition in the amount of $318,000. As this acquisition was determined to be an asset acquisition, transaction costs were capitalized to oil and gas properties- proved, net on the balance sheet. Below is the summary of the assets acquired (in thousands):

Identifiable assets acquired:
Proved oil and gas properties	$	37,386
Unproved oil and gas properties		100
Other property and equipment		545
Intangible assets		300
Total identified assets	$	38,331

Consolidation of Carbon California and Seneca Acquisition Unaudited Pro Forma Results of Operations

Below are unaudited consolidated results of operations for the three and nine months ended September 30, 2018 and 2017, as though the Carbon California Acquisition and the Seneca Acquisition had been completed as of January 1, 2017. The Carbon California Acquisition closed February 1, 2018, and the Seneca Acquisition closed May 1, 2018, and accordingly, our unaudited consolidated statements of operations for the year ended September 30, 2018, includes the Carbon California Acquisition results of operations for the period February 1, 2018 through September 30, 2018, inclusive of the Seneca Acquisition results of operations for the period May 1, 2018 through September 30, 2018.

	Unaudited Pro Forma Consolidated Results For Three Months Ended September 30,						Unaudited Pro Forma Consolidated Results For Nine Months Ended September 30,
(in thousands, except per share amounts)	2018			2017			2018			2017
Revenue	$	12,742		$	11,227		$	33,256		$	35,122
Net (loss) income before non-controlling interests		(455	)		(1,518	)		5,232			13,969
Net (loss) income attributable to non-controlling interests		270			16			(2,334	)		92
Net (loss) income attributable to controlling interests	$	(725	)	$	(1,534	)	$	7,566		$	13,877
Net income per share (basic)	$	(0.09	)	$	(0.27	)	$	1.00		$	2.49
Net income per share (diluted)	$	(0.10	)	$	(0.27	)	$	.96		$	2.14

Liberty Acquisition

On July 11, 2018, we completed an acquisition of 54 operated oil and gas wells covering approximately 55,000 gross acres (22,000 net) and 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 ownership in the acquired wells from 60% to 100%.  The Liberty Acquisition was funded through borrowings under our Credit Facility. The Liberty Acquisition is accounted for as a non-significant asset acquisition.

12

Note 4 - Property and Equipment

Net property and equipment as of September 30, 2018 and December 31, 2017, consists of the following:

(in thousands)	September 30, 2018			December 31, 2017
Oil and gas properties:
Proved oil and gas properties	$	215,620		$	114,893
Unproved properties not subject to depletion		3,616			1,947
Accumulated depreciation, depletion, amortization and impairment		(87,527	)		(80,715	)
Net oil and gas properties		131,709			36,125
Furniture and fixtures, computer hardware and software, and other equipment		3,783			1,758
Accumulated depreciation and amortization		(1,794	)		(1,021	)
Net other property and equipment		1,989			737
Total net property and equipment	$	133,698		$	36,862

We had approximately $3.6 million and $1.9 million, at September 30, 2018 and December 31, 2017, respectively, of unproved oil and gas properties not subject to depletion. At September 30, 2018 and December 31, 2017, our unproved properties consist principally of leasehold acquisition costs in the following areas:

(in thousands)	September 30, 2018		December 31, 2017
Ventura Basin	$	1,595	$	-
Illinois Basin:
Indiana		432		432
Illinois		142		136
Appalachian Basin:
Kentucky		952		915
Ohio		66		66
West Virginia		429		398
Total unproved properties not subject to depletion	$	3,616	$	1,947

During the three and nine months ended September 30, 2018 and 2017, there were no expiring leasehold costs that were reclassified into proved property. The excluded properties are assessed for impairment at least annually. Subject to industry conditions, evaluations of most of these properties and the inclusion of their costs in amortized capital costs is expected to be completed within five years.

We capitalized overhead applicable to acquisition, development and exploration activities of approximately $106,000 and $306,000 for the three and nine months ended September 30, 2018, respectively. For the three and nine months ended September 30, 2017, we capitalized overhead applicable to acquisition, development, and exploration activities of approximately $47,000 and $178,000, respectively.

13

Depletion expense related to oil and gas properties for the three and nine months ended September 30, 2018 was approximately $2.4 million, or $1.01 per Mcfe, and $5.6 million, or $0.88 per Mcfe, respectively. For the three and nine months ended September 30, 2017, depletion expense was approximately $521,000, or $0.38 per Mcfe, and $1.6 million, or $0.40 per Mcfe, respectively. 

Note 5 - Asset Retirement Obligation

Our 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 or acquired, and the cost of such liability is recorded as an increase in the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability.

The estimated ARO liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or acquired or increased as a result of a reassessment of expected cash flows and assumptions inherent in the estimation of the liability. Upward revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. AROs are valued utilizing Level 3 fair value measurement inputs (see note 12).

The following table is a reconciliation of the ARO:

	Nine Months Ended September 30,
(in thousands)	2018			2017
Balance at beginning of period	$	7,737		$	5,120
Accretion expense		510			232
Additions from Carbon California Company, LLC		2,921			-
Additions from Seneca Acquisition		639			-
Additions from Liberty Acquisition		30			-
Additions during period		-			5
Obligations on sale of oil & gas properties		-			(93	)
		11,837			5,264
Less: ARO recognized as a current liability		(902	)		(144	)
Balance at end of period	$	10,935		$	5,120

Note 6 - Investments in Affiliates

Carbon California

Carbon California was formed in 2016 by us and entities controlled by, Yorktown and Prudential to acquire producing assets in the Ventura Basin in California. On February 15, 2017, we, Yorktown and Prudential entered into a limited liability company agreement (the “Carbon California LLC Agreement”) of Carbon California, a Delaware limited liability company.

Prior to February 1, 2018, we held 17.81% of the voting and profits interests, Yorktown held 38.59% of the voting and profits interests and Prudential held 43.59% of the voting and profits interests in Carbon California. On February 1, 2018, Yorktown exercised the California Warrant, pursuant to which Yorktown obtained additional shares of common stock in us in exchange for the transfer and assignment by Yorktown of all its rights in Carbon California. Following the exercise of the California Warrant by Yorktown, we owned 56.4% of the voting and profits interests, and Prudential held the remainder of the interests, in Carbon California. On May 1, 2018, Carbon California closed the Seneca Acquisition. Following the exercise of the California Warrant by Yorktown and the Seneca Acquisition, we own 53.9% of the voting and profits interests, and Prudential owns 46.1% voting and profits interest in Carbon California.

On February 15, 2017, Carbon California (i) issued and sold Class A Units to Yorktown and Prudential for an aggregate cash consideration of $22.0 million, (ii) entered into a Note Purchase Agreement (the “Note Purchase Agreement”) with Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America for the issuance and sale of up to $25.0 million of Senior Secured Revolving Notes (the “Senior Revolving Notes”) due February 15, 2022 and (iii) entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”) with Prudential for the issuance and sale of $10.0 million of Senior Subordinated Notes (the “Subordinated Notes”) due February 15, 2024. We are not a guarantor of the Senior Revolving Notes or the Subordinate Notes.

14

The closing of the Note Purchase Agreement and the Securities Purchase Agreement on February 15, 2017, resulted in the sale and issuance by Carbon California of (i) Senior Revolving Notes in the principal amount of $10.0 million and (ii) Subordinated Notes in the original principal amount of $10.0 million. 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, 2018, the borrowing base was $41.0 million, of which $38.5 million was outstanding.

Net proceeds from the offering transaction were used by Carbon California to complete the acquisitions of oil and gas assets in the Ventura Basin of California, which acquisitions also closed on February 15, 2017. The remainder of the net proceeds were used to fund field development projects, to fund a future complementary acquisition and for general working capital purposes of Carbon California.

For the period February 15, 2017 (inception) through January 31, 2018, based on our 17.8% interest in Carbon California, our ability to appoint a member to the board of directors and our role of manager of Carbon California, we accounted for our investment in Carbon California under the equity method of accounting as we believed we exerted significant influence. We used the Hypothetical Liquidation at Book Value Method (“HLBV”) to determine our share of profits or losses in Carbon California and adjusted the carrying value of our investment accordingly. The HLBV is a balance-sheet approach that calculates the amount each member of Carbon California would have received if Carbon California were liquidated at book value at the end of each measurement period. The change in the allocated amount to each member during the period represents the income or loss allocated to that member. In the event of liquidation of Carbon California, to the extent that Carbon California has net income, available proceeds are first distributed to members holding Class B Units and any remaining proceeds are then distributed to members holding Class A Units. For the period February 15, 2017 (inception) through January 31, 2018, Carbon California incurred a net loss of which our share (as a holder of Class B Units for that period) was zero.

In connection with our entry into the Carbon California LLC Agreement, we received the aforementioned Class B Units and issued to Yorktown the California Warrant. The exercise price for the California Warrant was payable exclusively with Class A Units of Carbon California held by Yorktown and the number of shares of our common stock for which the California Warrant was exercisable was determined, as of the time of exercise, by dividing (a) the aggregate unreturned capital of Yorktown’s Class A Units of Carbon California by (b) the exercise price. The California Warrant had a term of seven years and included certain standard registration rights with respect to the shares of our common stock issuable upon exercise of the California Warrant. On February 1, 2018, Yorktown exercised the California Warrant. As a result of the warrant exercise, Carbon holds 11,000 Class A Units of Carbon California and all of the Class B units, resulting in an aggregate Sharing Percentage of 56.4%. Effective February 1, 2018, the Company consolidates Carbon California in its unaudited condensed consolidated financial statements.

On May 1, 2018, Carbon California entered into an agreement with Prudential Capital Energy Partners, L.P. for the issuance and sale of $3.0 million of unsecured notes due February 15, 2024, bearing interest of 12% per annum (the “Carbon California 2018 Subordinated Notes”).   Prudential received 585 Class A Units, representing an approximately 2% additional sharing percentage, for the issuance of the Carbon California 2018 Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding Carbon California 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 Carbon California 2018 Subordinated Notes. As of September 30, 2018, Carbon California had an outstanding discount of $454,000 associated with these notes, which is presented net of the Carbon California 2018 Subordinated Notes within Credit facility-related party on the unaudited consolidated balance sheets.

As a result of these transactions, we have at September 30, 2018, an aggregate Sharing Percentage of 53.9%.

Carbon Appalachia

Carbon Appalachia was formed in 2016 by us, Yorktown and entities controlled by Old Ironsides Energy LLC (“Old Ironsides”) to acquire producing assets in the Appalachian Basin in Kentucky, Tennessee, Virginia and West Virginia.

Outlined below is a summary of (i) our contributions, (ii) our resulting percentage of Class A unit ownership and (iii) our overall resulting Sharing Percentage of Carbon Appalachia after giving effect to the Class C Unit ownership. Holders of units within each class of units participate in profit or losses and distributions according to their proportionate share of each class of units (“Sharing Percentage”). Each contribution and its use are described in summary following the table.

Date	Capital Contribution	Resulting Class A Units (%)			Resulting Sharing %
April 2017	$0.24 million		2.00	%		2.98	%
August 2017	$3.71 million		15.20	%		16.04	%
September 2017	$2.92 million		18.55	%		19.37	%
November 2017	Warrant exercise		26.50	%		27.24	%

15

On April 3, 2017, we, Yorktown and Old Ironsides, entered in to a limited liability company agreement (the “Carbon Appalachia LLC Agreement”), with an initial equity commitment of $100.0 million, of which $37.0 million has been contributed as of September 30, 2018.

Pursuant to the Carbon Appalachia LLC Agreement, we acquired a 2.0% interest in Carbon Appalachia for $240,000 of Class A Units associated with our initial equity commitment of $2.0 million. We also have the ability to earn up to an additional 14.7% of Carbon Appalachia distributions (represented by Class B Units) after certain return thresholds to the holders of Class A Units are met. The Class B Units were acquired for no cash consideration.

In addition, we acquired a 1.0% interest represented by Class C Units which were obtained in connection with the contribution to Carbon Appalachia of a portion of our working interest in undeveloped properties in Tennessee. If Carbon Appalachia agrees to drill horizontal Chattanooga Shale wells on these properties, it will pay 100% of the cost of drilling and completion of the first 20 wells to earn a 75% working interest in such properties. We, through our subsidiary, Nytis LLC, will retain a 25% working interest in the properties. There was no activity associated with these properties in 2017 nor during the first nine months of 2018.

In 2017, Carbon Appalachia Enterprises, LLC, formerly known as Carbon Tennessee Company, LLC (“CAE”), a subsidiary of Carbon Appalachia, entered into a 4-year $100.0 million (with $1.5 million sublimit for letters of credit) senior secured asset-based revolving credit facility with Legacy Texas Financial Group, Inc. (“LegacyTexas Bank”) with an initial borrowing base of $10.0 million (the “CAE Credit Facility”).

The CAE Credit Facility borrowing base was adjusted for acquisitions completed in 2017. Most recently, on April 30, 2018, the CAE Credit Facility was amended, which increased the borrowing base to $70.0 million with redeterminations as of April 1 and October 1 each year. As of September 30, 2018, there was approximately $38.0 million outstanding under the CAE Credit Facility.

The CAE Credit Facility is guaranteed by each of CAE’s existing and future direct or indirect subsidiaries (subject to certain exceptions). CAE’s obligations and those of CAE’s subsidiary guarantors under the CAE Credit Facility are secured by essentially all of CAE’s tangible and intangible personal and real property (subject to certain exclusions).

Interest is payable quarterly and accrues on borrowings under the CAE Credit Facility at a rate per annum equal to either (i) the base rate plus an applicable margin between 0.00% and 1.00% or (ii) the Adjusted LIBOR rate plus an applicable margin between 3.00% and 4.00% at our option. The actual margin percentage is dependent on the CAE Credit Facility utilization percentage. CAE is obligated to pay certain fees and expenses in connection with the CAE Credit Facility, including a commitment fee for any unused amounts of 0.50%.

The CAE Credit Facility contains affirmative and negative covenants that, among other things, limit CAE’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, the CAE Credit Facility requires CAE’s compliance, on a consolidated basis, with (i) a maximum Debt/EBITDA ratio of 3.5 to 1.0 and (ii) a minimum current ratio of 1.0 to 1.0.

CAE may at any time repay the loans under the CAE Credit Facility, in whole or in part, without penalty. CAE must pay down borrowings under the CAE Credit Facility or provide mortgages of additional oil and natural gas properties to the extent that outstanding loans and letters of credit exceed the borrowing base.

In connection with our entry into the Carbon Appalachia LLC Agreement, and Carbon Appalachia engaging in certain transactions during 2017, we received the aforementioned Class B Units and issued to Yorktown a warrant to purchase approximately 408,000 shares of our common stock at an exercise price of $7.20 per share (the “Appalachia Warrant”). The Appalachia Warrant was payable exclusively with Class A Units of Carbon Appalachia held by Yorktown and the number of shares of our common stock for which the Appalachia Warrant was exercisable was determined, as of the time of exercise, by dividing (a) the aggregate unreturned capital of Yorktown’s Class A Units of Carbon Appalachia plus a required 10% internal rate of return by (b) the exercise price.

On November 1, 2017, Yorktown exercised the Appalachia Warrant, resulting in the issuance of approximately 432,000 shares of our common stock in exchange for Class A Units representing approximately 7.95% of then outstanding Class A Units of Carbon Appalachia. We accounted for the exercise through extinguishment of the warrant liability associated with the Appalachia Warrant of approximately $1.9 million and the receipt of Yorktown’s Class A Units as an increase to investment in affiliates in the amount of approximately $2.9 million. After giving effect to the exercise, we own 26.5% of Carbon Appalachia’s outstanding Class A Units along with 100% of its Class C Units.

16

The issuance of the Class B Units and the Appalachia Warrant were in contemplation of each other, and under non-monetary related party guidance, we accounted for the Appalachia Warrant, at issuance, based on the fair value of the Appalachia Warrant as of the date of grant (April 3, 2017) and recorded a warrant liability with an associated offset to APIC. Future changes to the fair value of the Appalachia Warrant were recognized in earnings. We accounted for the fair value of the Class B Units at their estimated fair value at the date of grant, which became our investment in Carbon Appalachia with an offsetting entry to APIC.

As of the grant date of the Appalachia Warrant, we estimated that the fair market value of the Appalachia Warrant was approximately $1.3 million, and the fair value of the Class B Units was approximately $924,000. The difference in the fair value of the Appalachia Warrant from the grant date though its exercise on November 1, 2017, was approximately $619,000 and was recognized in warrant derivative gain in our consolidated statements of operations for the year ended December 31, 2017.

Based on our 27.24% combined Class A and Class C interest (and our ability as of September 30, 2018 to earn up to an additional 14.7%) in Carbon Appalachia, our ability to appoint a member to the board of directors and our role of manager of Carbon Appalachia, we are accounting for our investment in Carbon Appalachia under the equity method of accounting as we believe we exert significant influence. We use the HLBV to determine our share of profits or losses in Carbon Appalachia and adjust the carrying value of our investment accordingly. Our investment in Carbon Appalachia is represented by our Class A and C interests, which we acquired by contributing approximately $6.9 million in cash and unevaluated property. In the event of liquidation of Carbon Appalachia, available proceeds are first distributed to members holding Class C Units then to holders of Class A Units until their contributed capital is recovered with an internal rate of return of 10%. Any additional distributions would then be shared between holders of Class A, Class B and Class C Units. For the three and nine months ended September 30, 2018, Carbon Appalachia earned net income, of which our share is approximately $139,000 and $1.1 million, respectively. The ability of Carbon Appalachia to make distributions to its owners, including us, is dependent upon the terms of its credit facility, which currently prohibit distributions unless agreed to by the lender.

As of September 30, 2018, Carbon Appalachia is in compliance with all CAE Credit Facility covenants.

The following table sets forth selected historical unaudited consolidated statements of operations and production data for Carbon Appalachia.

(in thousands)	As of  September 30, 2018
Current assets	$	22,478
Total oil and gas properties, net	$	81,833
Total other property and equipment, net	$	15,880
Other long-term assets	$	1,302
Current liabilities	$	15,313
Non-current liabilities	$	61,234
Total members’ equity	$	44,946

	Three months ended		Three months ended
(in thousands)	September 30, 2018		September 30, 2017
Revenues	$	18,058	$	1,348
Operating expenses		16,686		2,691
Income (loss) from operations		1,372		(1,344	)
Net income (loss)	$	537	$	(1,546	)

	Nine months ended		April 3, 2017 to
(in thousands)	September 30, 2018		September 30, 2017
Revenues	$	62,480	$	2,905
Operating expenses		56,441		4,449
Income (loss) from operations		6,039		(1,544	)
Net income (loss)	$	4,017	$	(1,874	)

17

Old Ironsides Membership Interest Purchase Agreement 

On May 4, 2018, we entered into a Membership Interest Purchase Agreement (the “MIPA”) with Old Ironsides. Old Ironsides owns 73.5%, and we own 26.5%, of the issued and outstanding Class A Units of Carbon Appalachia. We also own all of the Class B and Class C units of Carbon Appalachia. Pursuant to the MIPA, we may acquire all of Old Ironsides’ membership interests of Carbon Appalachia. Subject to the terms and conditions of the MIPA, we will pay Old Ironsides, approximately $58.0 million at closing, subject to adjustment, in accordance with the MIPA. The MIPA is contingent upon the issuance of common equity of the Company. We have filed a registration statement.

Upon the completion of the transaction, we would own 100% of the issued and outstanding ownership interests in Carbon Appalachia, and Carbon Appalachia will become a wholly-owned subsidiary of ours.

The MIPA contains termination rights for us and Old Ironsides, including, among others, if the closing of the transaction has not occurred on or before November 30, 2018. The MIPA may also be terminated by mutual written consent of us and Old Ironsides. On November 6^, 2018, we entered into an amendment to extend the closing of the transaction from November 6, 2018 to November 30, 2018.

Investments in Affiliates

During the three and nine months ended September 30, 2018, we recorded total equity method income of approximately $83,000 and $1.0 million, respectively. For the nine months ended September 30, 2017, we recorded total equity method income of approximately $32,000. On February 1, 2018, as a result of the Carbon California Acquisition, we derecognized our equity investment in Carbon California and recognized a gain of approximately $5.4 million based on the fair value of our previously held interest compared to its carrying value.

Note 7 - Credit Facilities

Our Credit Facility

In 2016, we entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank. LegacyTexas Bank is the initial lender and acts as administrative agent.

The credit facility has a maximum availability of $100.0 million (with a $500,000 sublimit for letters of credit), which availability is subject to the amount of the borrowing base. The initial borrowing base established under the credit facility was $17.0 million. The borrowing base is subject to semi-annual redeterminations in March and September. In July 2018, the borrowing base was increased from $25.0 to $28.0 million, of which approximately $26.1 million was outstanding as of September 30, 2018. Our effective interest rate as of September 30, 2018 was 7.52%.

The credit facility is guaranteed by each of our existing and future subsidiaries (subject to certain exceptions). Our obligations and those of our subsidiary guarantors under the credit facility are secured by essentially all of our tangible and intangible personal and real property (subject to certain exclusions).

Interest is payable quarterly and accrues on borrowings under the credit facility at a rate per annum equal to either (i) the base rate plus an applicable margin between 0.50% and 1.50% or (ii) the Adjusted LIBOR rate plus an applicable margin between 3.50% and 4.50% at our option. The actual margin percentage is dependent on the credit facility utilization percentage. We are obligated to pay certain fees and expenses in connection with the credit facility, including a commitment fee for any unused amounts of 0.50%.

The credit facility contains affirmative and negative covenants that, among other things, limit our 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, the credit facility requires our compliance, on a consolidated basis, with (i) a maximum Debt/EBITDA ratio of 3.5 to 1.0 and (ii) a minimum current ratio of 1.0 to 1.0.

On March 27, 2018, the credit facility was amended to revise the calculation of the Leverage Ratio from a Debt/EBITDA ratio to a Net Debt/Adjusted EBITDA ratio, reset the testing period used in the determination of Adjusted EBITDA, eliminated the minimum current ratio and substituted alternative liquidity requirements, including maximum allowed current liabilities in relation to current assets, a minimum cash balance requirement of $750,000 and maximum aged trade payable requirements. As of September 30, 2018, we were in compliance with our financial covenants.

We may at any time repay the loans under the credit facility, in whole or in part, without penalty. We must pay down borrowings under the credit facility or provide mortgages of additional oil and natural gas properties to the extent that outstanding loan and letters of credit exceed the borrowing base.

18

As required under the terms of the credit facility, we entered into derivative contracts with fixed pricing for a certain percentage of our production. We are a party to an ISDA Master Agreement with BP Energy Company that established 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 the Company and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facility.

Carbon California – Credit Facilities

Effective as of February 1, 2018, our ownership in Carbon California increased to 56.4% due to the exercise of the California Warrant. As a result of this transaction, we consolidate Carbon California for financial reporting purposes.

On May 1, 2018, Carbon California closed the Seneca Acquisition. Following the exercise of the California Warrant by Yorktown and the Seneca Acquisition, we own 53.9% of the voting and profits interests, and Prudential owns 46.1% voting and profit interest in Carbon California.

The table below summarizes the outstanding notes payable for Carbon California as of September 30, 2018 (in thousands):

Senior Revolving Notes, related party, due February 15, 2022	$	38,500
Subordinated Notes, related party, due February 15, 2024		13,000
Long-term debt		65
Total gross notes payable		51,565
Less: Deferred notes costs		(220	)
Less: Notes discount		(1,284	)
Total net notes payable	$	50,061

Carbon California-Senior Revolving Notes, Related Party

On February 15, 2017, Carbon California entered into the Note Purchase Agreement with Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America for the issuance and sale of the Senior Revolving Notes due February 15, 2022. We are 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, 2018, the borrowing base was $41.0 million, of which $38.5 million was outstanding.

Carbon California may elect to incur interest at either (i) 5.0% plus the London interbank offered rate (“LIBOR”) or (ii) 4.00% plus Prime Rate (which is defined as the interest rate published daily by JPMorgan Chase Bank, N.A.). As of September 30, 2018, the effective borrowing rate for the Senior Revolving Notes was 8.14%. 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 long-term assets for a combined value of $898,000. During the three and nine months ended September 30, 2018, Carbon California amortized fees of $57,000 and $134,000, respectively. For the three and nine months ended September 30, 2017, Carbon California amortized $29,000 and $72,000, respectively.

The Note Purchase Agreement requires Carbon California to maintain certain financial and non-financial covenants which include the following ratios: total leverage ratio, senior leverage ratio, interest coverage ratio, current ratio, and other qualitative covenants as defined in the Note Purchase Agreement. As of September 30, 2018, Carbon California was in compliance with its financial covenants.

2017 Carbon California-Subordinated Notes

On February 15, 2017, Carbon California entered into the Securities Purchase Agreement with Prudential Capital Energy Partners, L.P. for the issuance and sale of the Subordinated Notes due February 15, 2024, bearing interest of 12% per annum. We are 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.

Prudential received an additional 1,425 Class A Units, representing 5% of total sharing percentage, for the issuance of the Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding Subordinated Notes of $10.0 million. The Company then allocated the non-cash value of the units of approximately $1.3 million, which was recorded as a discount to the Subordinated Notes. As of September 30, 2018, Carbon California has an outstanding discount of $830,000, which is presented net of the Subordinated Notes within Credit facility-related party on the unaudited consolidated balance sheets.

19

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

Prepayment of the Subordinated Notes is available after February 15, 2019. Prepayment is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted.

The Securities Purchase Agreement requires Carbon California to maintain certain financial and non-financial covenants, which include the following ratios: total leverage ratio, senior leverage ratio, interest coverage ratio, asset coverage ratio, current ratio, and other qualitative covenants as defined in the Securities Purchase Agreement. As of September 30, 2018, Carbon California was in compliance with its financial covenants.

Carbon California-2018 Subordinated Notes

On May 1, 2018, Carbon California entered into an agreement with Prudential for the issuance and sale of the Carbon California 2018 Subordinated Notes.

Prudential received 585 Class A Units, representing an approximate 2% additional sharing percentage, for the issuance of the Carbon California 2018 Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding Carbon California 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 Carbon California 2018 Subordinated Notes. As of September 30, 2018, Carbon California had an outstanding discount of $454,000 associated with these notes, which is presented net of the Carbon California 2018 Subordinated Notes within Credit facility-related party on the unaudited consolidated balance sheets. During the three and nine months ended September 30, 2018, Carbon California amortized $97,000 and $236,000, respectively.

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

Prepayment of the Subordinated Notes is available after February 15, 2019. Prepayment is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted.

The Carbon California 2018 Subordinated Notes agreement requires Carbon California to maintain certain financial and non-financial covenants, which include the following ratios: total leverage ratio, senior leverage ratio, interest coverage ratio, asset coverage ratio, current ratio, and other qualitative covenants as defined in the Carbon California 2018 Subordinated Notes. As of September 30, 2018, Carbon California was in compliance with its financial covenants.

Note 8 - Income Taxes

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

At September 30, 2018, we have established a full valuation allowance against the balance of net deferred tax assets.

Note 9 - Stockholders’ Equity

Authorized and Issued Capital Stock

Effective March 15, 2017, and pursuant to a reverse stock split approved by the stockholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. References to the number of shares and price per share give retroactive effect to the reverse stock split for all periods presented.

20

As of September 30, 2018, we had 35.0 million shares of common stock authorized with a par value of $0.01 per share, of which approximately 7.7 million were issued and outstanding, and 1.0 million shares of preferred stock authorized with a par value of $0.01 per share. On April 6, 2018, the Company entered into a preferred stock purchase agreement with Yorktown for a private placement of 50,000 shares of the Preferred Stock for $5.0 million. During the nine months ended September 30, 2018, the increase in our issued and outstanding common stock is primarily due to (a) Yorktown’s exercise of the California Warrant (see note 3), resulting in the issuance of approximately 1.5 million shares of our common stock in exchange for Class A Units in Carbon California representing approximately 46.96% of the then outstanding Class A Units, in addition to (b) restricted stock and restricted performance units that vested during the year.

Carbon Stock Incentive Plans

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

The Carbon Plans provide for the granting of incentive stock options, non-qualified stock options, restricted stock awards, performance awards and phantom stock awards, or a combination of the foregoing, as 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, 2018, approximately 649,000 shares of restricted stock have been granted under the terms of the Carbon Plans. Restricted stock awards for employees vest ratably over a three-year service period or cliff vest at the end of a three-year service period. For non-employee directors, the awards vest upon the earlier of a change in control of us or the date their membership on the Board of Directors is terminated other than for cause. We recognize compensation expense for these restricted stock grants based on the grant date fair value of the shares, amortized ratably over three years for employee awards (based on the required service period for vesting) and seven years for non-employee director awards (based on a market survey of the average tenure of directors among U.S. public companies). For restricted stock granted between 2014 and 2017, we recognized compensation expense based on the grant date fair value of the shares, utilizing an enterprise value approach, using valuation metrics primarily based on multiples of cash flow from operations, production and reserves. For restricted stock and performance units granted in 2013 and 2018, we utilized the closing price of our stock on the date of grant to recognize compensation expense. During the nine months ended September 30, 2018, approximately 59,000 restricted stock units vested.

Compensation costs recognized for these restricted stock grants were approximately $189,000 and $537,000 for the three and nine months ended September 30, 2018, respectively. For the three and nine months ended September 30, 2017, we recognized compensation expense of approximately $160,000 and $513,000, respectively. As of September 30, 2018, there was approximately $1.6 million unrecognized compensation costs related to these restricted stock grants which we expect to be recognized over the next 6.5 years. In 2018 we utilized the traded value of our common stock on the date of grant instead of the enterprise value to record compensation expense related to new equity grants. Due to the price received for our Preferred Stock, we believe the closing price of our common stock is now a better representation of the fair value of our common stock, instead of the enterprise value used to record compensation expense related to new equity grants.

Restricted Performance Units

As of September 30, 2018, approximately 597,000 shares of performance units have been granted under the terms of the Carbon Plans. Performance units represent a contractual right to receive one share of our common stock subject to the terms and conditions of the agreements, including the achievement of certain performance measures relative to a defined peer group or the growth of certain performance measures over a defined period of time as well as, in some cases, continued service requirements.

We account for the performance units granted during 2014 through 2018 at their fair value determined at the date of grant, which were $11.80, $8.00, $5.40, $7.20 and $9.80 per share, respectively. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At September 30, 2018, we estimated that none of the performance units granted in 2016-2018 would vest, and, accordingly, no compensation cost has been recorded for these performance units. During 2016, we estimated that it was probable that the performance units granted in 2014 and 2015 would vest and therefore compensation costs of approximately $135,000 and $239,000 related to these performance units were recognized for the nine months ended September 30, 2018 and 2017, respectively. As of September 30, 2018, compensation costs related to the performance units granted in 2014 and 2015 have been fully recognized. As of September 30, 2018, if change in control and other performance provisions pursuant to the terms and conditions of these award agreements are met in full, the estimated unrecognized compensation cost related to the performance units granted in 2012 and 2016 through 2018 would be approximately $3.3 million.

21

Preferred Stock

Series B Convertible Preferred Stock – Related Party

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

The Preferred Stock accrues cash dividends at a rate of six percent (6%) of the initial issue price of $100 per share per annum. The holders of the Preferred Stock are entitled to the same number of votes of common stock that such share of Preferred Stock would represent on an as converted basis. The holders of the Preferred Stock receive liquidation preference based on the initial issue price of $100 per share plus any accrued dividends over common stock holders and the holders of any junior ranking stock. As of September 30, 2018, we accrued $147,000 of dividends.

We apply the guidance in ASC 480 “Distinguishing Liabilities from Equity” when determining the classification and measurement of the Preferred Stock. The Preferred Stock does not feature any redemption rights within the holders’ control or conditional redemption features not within our control as of September 30, 2018. Accordingly, the Preferred Stock is presented as a component of consolidated stockholders’ equity.

We have evaluated the Preferred Stock in accordance with ASC 815, “Derivatives and Hedging”, including consideration of embedded derivatives requiring bifurcation. The issuance of the Preferred Stock could generate a beneficial conversion feature (“BCF”), which arises when a debt or equity security is issued with an embedded conversion option that is beneficial to the investor or in the money at inception because the conversion option has an effective strike price that is less than the market price of the underlying stock at the commitment date. Based on the conversion terms and the price at the commitment date, we determined that a BCF was required to be recorded related to the voluntary conversion option by the holder as of September 30, 2018. We recorded the BCF as a reduction of retained earnings and an increase to APIC of $1.1 million, which is based on the difference between the floor price of $8.00 and our stock price as of the commitment date multiplied by the number of shares to be issued. We are also required to evaluate a contingent BCF for the automatic conversion feature, but in accordance with ASC 470, “Debt”, we will not record the effect of the BCF until the contingency is resolved. As of September 30, 2018, we have a BCF of approximately $1.1 million.

Note 10 - Revenue Recognition

Revenue from Contracts with Customers

We recognize revenue when it satisfies a performance obligation by transferring control over a product to a customer. Revenue is measured based on the consideration we expect to receive in exchange for those products. Revenues from contracts with customers are recorded on the unaudited consolidated statements of operations based on the type of product being sold.

22

Performance Obligations and Significant Judgments

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

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

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

A portion of our product sales are short-term in nature. For those contracts, we use the practical expedient in ASC 606-10-50-14 exempting us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to an unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore, future volumes are unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. We have no unsatisfied performance obligations at the end of each reporting period.

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

Disaggregation of Revenues

In the following tables, revenue for the three and nine months ended September 30, 2018, is disaggregated by primary region within the United States and major product line. As noted above, we operate as one reportable segment.

For the three months ended September 30, 2018:

(in thousands)
Type	Appalachia and  Illinois Basin		Ventura Basin		Total
Natural gas sales	$	3,856	$	516	$	4,372
Natural gas liquids sales		-		406		406
Oil sales		3,327		8,524		11,850
Total natural gas, natural gas liquids, and oil revenue	$	7,185	$	9,444	$	16,629

For the nine months ended September 30, 2018:

(in thousands)
Type	Appalachia and  Illinois Basin		Ventura Basin		Total
Natural gas sales	$	10,776	$	1,059	$	11,835
Natural gas liquids sales		-		1,119		1,119
Oil sales		5,952		16,972		22,924
Total natural gas, natural gas liquids, and oil revenue	$	16,728	$	19,150	$	35,878

23

Contract Balances

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

Prior Period Performance Obligations

We record revenue in the month production is delivered to the purchaser, but settlement statements may not be received until 30 to 90 days after the month of production. As such, we estimate the production delivered and the related pricing. Any differences between our initial estimates and actuals are recorded in the month payment is received from the customer. These differences have not historically been material. For the three and nine months ended September 30, 2018, revenue recognized in the reporting period related to prior period performance obligations is immaterial.

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

Note 11 - Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities consist of the following:

	September 30, 2018		December 31, 2017
Accounts payable	$	3,923	$	3,274
Oil and gas revenue suspense		2,111		1,776
Gathering and transportation payables		817		497
Production taxes payable		375		214
Drilling advances received from joint venture partner		295		245
Accrued lease operating expenses		946		684
Accrued ad valorem taxes-current		1,704		1,054
Accrued general and administrative expenses		1,085		2,473
Accrued asset retirement obligation-current		902		380
Accrued interest		633		247
Accrued environmental liability		728		-
Other liabilities		859		374
Total accounts payable and accrued liabilities	$	14,378	$	11,218

Note 12 - Fair Value Measurements

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

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

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

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

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

24

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

	Fair Value Measurements Using
(in thousands)	Level 1		Level 2		Level 3		Total
September 30, 2018
Liabilities
Commodity derivatives	$	-	$	10,801	$	-	$	10,801
December 31, 2017
Asset:
Commodity derivatives	$	-	$	225	$	-	$	225
Liabilities
Warrant derivative liability	$	-	$	-	$	2,017	$	2,017

Commodity Derivative

As of September 30, 2018, our commodity derivative financial instruments are comprised of natural gas and oil swaps and costless collars. The fair values of these agreements are determined under an income valuation technique. The valuation model requires a variety of inputs, including contractual terms, published forward prices, volatilities for options and discount rates, as appropriate. Our estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, our credit worthiness and the time value of money. The consideration of these factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. All the significant inputs are observable, either directly or indirectly; therefore, our derivative instruments are included within the Level 2 fair value hierarchy. The counterparty for all our outstanding commodity derivative financial instruments as of September 30, 2018, is BP Energy Company.

Warrant Derivative

A third-party valuation specialist was utilized to determine the fair value our California Warrant. The warrant was designated as Level 3. We review the valuations, including the related model inputs and assumptions, and analyze changes in fair value measurements between periods. We corroborate such inputs, calculations and fair value changes using various methodologies, and review unobservable inputs for reasonableness utilizing relevant information from other published sources.

We estimated the fair value of the California Warrant on February 15, 2017, the grant date of the warrant, to be approximately $5.8 million, using a call option pricing model with the following assumptions: a seven-year term, exercise price of $7.20, volatility rate of 41.8% and a risk-free rate of 2.3%. As we will receive Class A Units in Carbon California in the event the holder exercises the California Warrant, we also considered the fair value of the Class A Units in its valuation. We utilized the same measurement as of December 31, 2017 for January 31, 2018, using a Monte Carlo valuation model which utilized unobservable inputs including the percentage return on our shares at various timelines, the percentage return on the privately-held Carbon California Class A Units at various timelines, an exercise price of $7.20, volatility rate of 45%, a risk-free rate of 2.1% and an estimated remaining term of 6.4 years. As of December 31, 2017, the fair value of the California Warrant was approximately $2.0 million. On February 1, 2018, Yorktown exercised the California Warrant, resulting in the issuance of 1,527,778 shares of our common stock. In exchange, we received Yorktown’s Class A Units of Carbon California representing approximately 46.96% of the outstanding Class A Units of Carbon California and a profits interest of approximately 38.59%.

The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:

(in thousands)	Total
Balance, December 31, 2017	$	2,017
Warrant derivative gain for the period January 1- January 31, 2018		(225	)
CCC Warrant Exercise - liability extinguishment		(1,792	)
Balance, September 30, 2018	$	-

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.

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. During the nine months ended September 30, 2018 and 2017, we recorded approximately $4.1 million and $5,000, in additions to asset retirement obligations, respectively. Additions during the nine months ended September 30, 2018, primarily related to the Carbon California Acquisition. See note 3 for additional information.

25

The exercise of the California Warrant and the acquisition of the additional ownership interest in Carbon California on February 1, 2018, is accounted for as a step acquisition in which we obtained control in accordance with ASC 805, Business Combinations (“ASC 805”). We consolidate the results of Carbon California into our unaudited condensed consolidated financial statements from the date of the Carbon California Acquisition forward. The Carbon California Acquisition was accounted for as a business combination, and the identifiable assets acquired, and liabilities assumed, were recorded at their estimated fair value at the date of acquisition. We have completed our preliminary valuation to determine the fair value of the identifiable assets acquired and liabilities assumed. The fair value of the assets acquired was determined using various valuation techniques, including an income approach. The fair value measurements were primarily based on significant inputs that are not directly observable in the market and are considered Level 3 under the fair value measurements and disclosure framework. See note 3 for additional information.

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 obligations was determined based upon the contractual obligations assumed by us and discounted based upon our effective borrowing rate. These contractual obligations are being amortized monthly as we pay these firm transportation obligations in the future.

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 $15,000 to $45,000, which is based on 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 of 1.92%; and a credit adjusted risk-free rate of 7.24%, which takes into account our credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs (see note 3). During the nine months ended September 30, 2018, we recorded additions to asset retirement obligations of approximately $4.1 million, primarily due to the Carbon California Acquisition. Carbon California estimates 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. Carbon California’s asset retirement obligation was calculated by taking into account the cost of abandoning oil and gas wells based on industry expectations for similar work, the economic lives of its properties between 1-49 years; an inflation rate between 2.01% and 2.03%; and a credit adjusted risk-free rate between 8.09% and 15.5%.

Class B Units

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

Note 13 - Physical Delivery Contracts and Gas Derivatives

We historically have used commodity-based derivative contracts to manage exposures to commodity price on certain 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 fixed price 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. Therefore, these contracts are not recorded at fair value in the unaudited condensed consolidated financial statements.

Pursuant to the terms of our credit facility, the Note Purchase Agreements and the Securities Purchase Agreement, we have entered into swap and collar derivative agreements to hedge certain of our oil and natural gas production through 2021. As of September 30, 2018, these derivative agreements consisted of the following:

Our Physical Delivery Contracts and Oil and Gas Derivatives

	Natural Gas Swaps				Natural Gas Collars				Oil Swaps
			Weighted				Weighted				Weighted
			Average				Average Price				Average
Year	MMBtu		Price (a)		MMBtu		Range (a)		Bbl		Price (b)
2018		870,000	$	3.00		-		-		23,000	$	55.09
2019		2,596,000	$	2.86		204,000		$2.60-$2.80		61,900	$	56.05
2020						1,018,000		$2.50-$2.70		21,000	$	60.72

(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.

26

Carbon California Physical Delivery Contracts and Oil and Gas Derivatives

	Natural Gas Swaps				Natural Gas Collars				Oil Swaps
			Weighted				Weighted				Weighted				Weighted
			Average				Average Price		WTI		Average		Brent		Average
Year	MMBtu		Price (a)		MMBtu		Range (a)		Bbl		Price (b)		Bbl		Price (c)
2018		90,000	$	3.03		-		-		48,628	$	53.06		62,792	$	66.46
2019		-	$	-		360,000		$2.60-$3.03		139,797	$	51.96		141,786	$	66.58
2020		-	$	-		-		-		73,147	$	50.12		139,682	$	65.71
2021		-	$	-		-		-			$	-		86,341	$	67.12

(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 and NYMEX 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 we will receive for the volumes under contract, while the floor establishes a minimum price.

The following table summarizes the fair value of the derivatives recorded in the unaudited consolidated balance sheets (see note 12). These derivative instruments are not designated as cash flow hedging instruments for accounting purposes:

(in thousands)	September 30, 2018		December 31, 2017
Commodity derivative contracts:
Commodity derivative asset	$	-	$	215
Other long-term assets	$	-	$	10
Commodity derivative liabilities	$	6,502	$	-
Commodity derivative liabilities, non-current	$	4,299	$	-

The table below summarizes the commodity settlements and unrealized gains and losses related to our derivative instruments. These commodity settlements and unrealized gains and losses are recorded and included in commodity derivative gain or loss in the accompanying unaudited consolidated statements of operations.

	For the three months ended September 30,						For the nine months ended September 30,
(in thousands)	2018			2017			2018			2017
Commodity derivative contracts:
Settlement (loss) gain	$	(1,108	)	$	345		$	(2,169	)	$	463
Unrealized (loss) gain		(2,794	)		(844	)		(8,381	)		2,179
Total settlement and unrealized (loss) gain, net	$	(3,902	)	$	(499	)	$	(10,550	)	$	2,642

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

27

The counterparty in all our derivative instruments is BP Energy Company. We and Carbon California have entered into International Swaps and Derivatives Association (“ISDA”) Master Agreements with BP Energy Company that establish standard terms for the derivative contracts and inter-creditor agreements whereby any credit exposure related to the derivative contracts entered into by us and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facility.

We and Carbon California net our derivative instrument fair value amounts executed with BP Energy Company 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 location and fair value amounts of all derivative instruments in the unaudited consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited consolidated balance sheets as of September 30, 2018.

								Net
		Gross						Recognized
		Recognized			Gross			Fair Value
		Assets/			Amounts			Assets/
	Balance Sheet Classification	Liabilities			Offset			Liabilities
Commodity derivative assets:	Commodity derivative	$	334		$	(334	)	$	-
	Other long-term assets		248			(248	)		-
Total derivative assets		$	582		$	(582	)	$	-
Commodity derivative liabilities:
	Commodity derivative	$	(6,836	)	$	334		$	(6,502	)
	Commodity derivative: non-current		(4,547	)		248			(4,299	)
Total derivative liabilities		$	(11,383	)	$	582		$	(10,801	)

The following table summarizes the location and fair value amounts of all derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets as of December 31, 2017.

								Net
		Gross						Recognized
		Recognized			Gross			Fair Value
		Assets/			Amounts			Assets/
	Balance Sheet Classification	Liabilities			Offset			Liabilities
Commodity derivative assets:	Commodity derivative	$	624		$	(409	)	$	215
	Other long-term assets		250			(240	)		10
Total derivative assets		$	874		$	(649	)	$	225
Commodity derivative liabilities:
	Commodity derivative	$	(409	)	$	409		$	-
	Commodity derivative: non-current		(240	)		240			-
Total derivative liabilities		$	(649	)	$	649		$	-

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

Note 14 – Commitment and Contingencies

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

28

We have entered into long-term firm transportation contracts to ensure the transport for certain of our gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts at September 30, 2018 are summarized in the table below.

Period	Dekatherms per day		Demand Charges
October 2018 - March 2020		3,230	$	0.20 - $0.62
April 2020 - May 2020		2,150	$	0.20
June 2020 - May 2036		1,000	$	0.20

A liability of approximately $166,000 related to firm transportation contracts assumed in the EXCO Acquisition in 2016, is reflected on our unaudited consolidated balance sheets as of September 30, 2018. The fair value of these firm transportation obligations was determined based upon the contractual obligations assumed upon acquisition by us and discounted based upon our effective borrowing rate. These contractual obligations are being amortized monthly as they become due.

Capital Commitment

In our participation as a Class A member of Carbon Appalachia we made a capital commitment of $23.6 million, of which we have contributed $6.9 million as of September 30, 2018.

As of September 30, 2018, we had no capital commitments associated with Carbon California.

Contingency

During March 2018, we became aware through our internal control system that one of our field employees had been misappropriating funds from our suspended revenue accounts over a period of several years. Upon the discovery of the misappropriation, we terminated the employee and engaged an external forensic specialist to lead an investigation to determine the extent of the misappropriation and the impact on our financial statements. The investigation determined that the employee’s ability to misappropriate funds from the suspense accounts was eliminated in 2017 when we instituted our current revenue accounting practices and internal controls.

We have recorded a provision at September 30, 2018, to reflect the estimated loss of suspended revenue. We have determined that this event constituted a significant deficiency.

Note 15 - Supplemental Cash Flow Disclosure

Supplemental cash flow disclosures are presented below:

	Nine Months Ended September 30,
(in thousands)	2018			2017
Cash paid during the period for:
Interest	$	2,770		$	645
Non-cash transactions:
Increase in asset retirement obligations	$	3,590		$	5
Decrease in accounts payable and accrued liabilities included in oil and gas properties	$	(491	)	$	(12	)
Non-cash acquisition of Carbon California interests (see note 3)	$	(18,906	)	$	-
Carbon California Acquisition on February 1, 2018 (see note 3)	$	17,114		$	-
Obligations assumed with Seneca asset purchase (see note 2)	$	330		$	-
Accrued dividend for convertible preferred stock (see note 9)	$	148		$	-
Beneficial conversion feature for convertible preferred stock (see note 9)	$	1,125		$	-
Issuance of warrants for investment in affiliates	$	-		$	7,094
Exercise of warrant derivative (see note 3)	$	(1,792	)	$	-

29

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 2017 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2018 and June 30, 2018.

Overview

Carbon Energy Corporation, a Delaware corporation formed in 2007, 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. Our acreage positions provide multiple resource play opportunities and have been delineated largely through drilling by us, as well as by other industry operators.

Our assets are characterized by stable, long-lived producing properties in the Appalachian Basin in Kentucky, Ohio, Tennessee, Virginia and West Virginia; the Ventura Basin in California; and the Illinois Basin in Illinois and Indiana. 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, 2018, our proved developed reserves and our interest in Carbon Appalachia’s proved developed reserves were comprised of 31.9% oil and natural gas liquids (“NGL”), and 68.2% natural gas. Our current capital expenditure program for Carbon California is focused on the acquisition, development, and recompletions of oil and natural gas properties in areas where we currently operate. During 2017 and the first nine months of 2018, our capital expenditures consisted principally of the optimization and streamlining of our natural gas gathering and compression facilities in Appalachia to provide more efficient and lower cost operations and greater flexibility in moving our production to markets with more favorable pricing. 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 acquiring, developing, optimizing and maintaining 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:

	2016		2017								2018
	Q4		Q1		Q2		Q3		Q4		Q1		Q2		Q3
Oil (Bbl)	$	49.33	$	51.86	$	48.29	$	48.19	$	55.39	$	62.88	$	68.04	$	69.69
Natural Gas (MMBtu)	$	2.98	$	3.07	$	3.09	$	2.89	$	2.87	$	3.13	$	2.77	$	2.88

30

Low oil, natural gas liquids, and natural gas prices may result in a decrease of our revenues, may reduce the amount of oil, natural gas, and natural gas liquids that we can produce economically and may potentially lower our estimates of oil, natural gas liquids, and natural gas reserves. Our estimated proved reserves and our interest in Carbon Applachia’s estimated proved reserves may decrease if the economic life of the underlying producing wells is shortened as a result of lower oil and natural gas prices. A substantial or extended decline in oil or natural gas prices may result in future impairments of our proved reserves and our equity investee’s proved reserves and may materially and adversely affect our future business, financial condition, cash flows, results of operations or liquidity. Lower oil and natural gas prices may also reduce the amount of borrowing base under our bank credit facility and the Senior Revolving Notes, which is determined at the discretion of our lenders and may make it more difficult to comply with the covenants and other restrictions under these agreements.

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 in 2017 or for the first nine months of 2018.

Future write downs or impairments, if any, cannot be predicted 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.

We use commodity derivative instruments, such as swaps and costless collars, to manage and reduce price volatility and other market risks associated with the price received for 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.

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.

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 facility, the Senor Revolving Notes, sales of properties or the issuance of additional equity or debt.

Operational Highlights

During the last two months of 2017 and first three quarters of 2018, NYMEX oil prices increased substantially, from $57.26 to $77.41. Based on expected future prices for oil and the increased rate of return on oil projects, we will anticipate deploying capital primarily to oil development projects in the Appalachia and Ventura basins.

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

As of September 30, 2018, we owned working interests in 3,800 gross wells (3,400 net) and royalty interests located in Kentucky, Ohio, Tennessee, West Virginia, and California and had leasehold positions in approximately 216,000 net developed acres and approximately 250,000 net undeveloped acres. Approximately 42% of the undeveloped acreage is held by production and of the remaining undeveloped acreage, approximately 68% have lease terms of greater than five years remaining in the primary term or contractual extension periods.

31

As of September 30, 2018, Carbon Appalachia owned working interests in 5,000 gross wells (5,000 net) located in Kentucky, Tennessee, Virginia and West Virginia, and had leasehold positions in approximately 141,000 net developed acres and approximately 1.1 million net undeveloped acres. Approximately 72% of the undeveloped acreage is held by production and of the remaining undeveloped acreage, approximately 91% have lease terms of greater than five years remaining in the primary term or contractual extension periods. As described below, as of September 30, 2018, our proportionate share in Carbon Appalachia was 27.24%.

Our oil and natural gas assets and those of Carbon Appalachia contain an inventory of homogenous properties and potential drilling locations which may provide drilling and completion 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 and Carbon Appalachia’s operating area which would expand our or Carbon Appalachia’s operations and provide attractive risk adjusted rates of return on invested capital. The drilling of oil and natural gas wells is contingent on our expectation of future oil and natural gas prices. 

Liberty Acquisition

On July 11, 2018, we completed an acquisition of 54 operated oil and gas wells covering approximately 55,000 gross acres (22,000 net) and 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 ownership in the acquired wells from 60% to 100%.  The Liberty Acquisition was funded through borrowings under our Credit Facility. The Liberty Acquisition is accounted for as an asset acquisition and is considered non-significant and pro-forma are not presented.

Consolidation of Carbon California

On February 1, 2018, Yorktown exercised a warrant it held to purchase shares of our common stock at an exercise price of $7.20 per share (the “California Warrant”), resulting in the issuance of 1,527,778 shares of our common stock in exchange for Yorktown’s Class A Units of Carbon California representing approximately 46.96% of the outstanding Class A Units of Carbon California and a profits interest of approximately 38.59%. After giving effect to the exercise on February 1, 2018, we owned 56.4% of the voting and profits interests of Carbon California. As of February 1, 2018, we consolidate Carbon California for financial reporting purposes.

Closing of the Seneca Acquisition

In October 2017, Carbon California signed a Purchase and Sale Agreement to acquire 309 operated and one non-operated oil wells covering approximately 5,700 gross acres (5,500 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 partially fund the purchase price with the remainder funded by Prudential Capital Energy Partners, L.P. and debt. We raised our $5.0 million through the issuance of 50,000 shares of Series B Convertible Preferred Stock, par value $0.01 per share (the “Preferred Stock”), to Yorktown. The Seneca Acquisition closed on May 1, 2018 with an effective date as of October 1, 2017. We recorded $639,000 in ARO and $330,000 in assumed liabilities in connection with the Seneca Acquisition. Below is the summary of the assets acquired (in thousands):

Identifiable assets acquired:
Assets:
Proved oil and gas properties	$	37,386
Unproved oil and gas properties		100
Other property and equipment		545
Intangible assets		300
Total identified assets	$	38,331

Reverse Stock Split

Our stockholders and board of directors approved a reverse stock split of our common stock, effective March 15, 2017, pursuant to which every 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. All references to the number of shares of common stock and per share amounts give retroactive effect to the reverse stock split for all periods presented. In connection with the reverse stock split, the number of authorized shares decreased from 200,000,000 to 10,000,000. On June 14, 2018, we increased the number of authorized shares of our common stock from 10,000,000 to 35,000,000.

As a result of these transaction, we have at September 30, 2018, an aggregate voting and profits interest of 53.9%.

32

Principal Components of Our Cost Structure

● Lease operating expenses. These are costs incurred to bring oil and natural gas out of the ground and to market, 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.

● Transportation and gathering costs. Transportation and gathering costs are incurred to bring oil and natural gas to market. Gathering refers to using groups of small pipelines to move the oil and natural gas from several wells into a major pipeline, or in case of oil, into a tank battery.

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

● 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. 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.

We perform our ceiling tests based on average first-of-the-month prices during the twelve-month period prior to the reporting date. For nine months ended September 30, 2018, we did not incur a ceiling test impairment.

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

● General and administrative expense.  These costs include payroll and benefits for our corporate staff, non-cash stock-based compensation, costs of maintaining our offices, costs of managing our production, development and acquisition operations, franchise taxes, audit, tax, legal and other professional fees and legal compliance. Certain of these costs are recovered as management and general and administrative expenses reimbursement arrangements in place with Carbon California and Carbon Appalachia.

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

● Income tax expense.  We are subject to state and federal income taxes but typically have not been in a tax paying position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs (“IDC”) and net operating loss (“NOL”) carryforwards. We pay alternative minimum tax, state income or franchise taxes where IDC or NOL deductions do not exceed taxable income or where state income or franchise taxes are determined on another basis.

On December 22, 2017, the Tax Cut and Jobs Act (“TCJA”) was enacted. The TCJA significantly changes the U.S. corporate tax law by, among other things, lowering the U.S. corporate income tax rate from 35% to 21% beginning in January 2018. FASB ASC Topic 740, Income Taxes, requires companies to recognize the impact of the changes in tax law in the period of enactment.

Amounts recorded during the three and nine months ended September 30, 2018, related to the TCJA principally relate to the reduction in the U.S. corporate income tax rate to 21%, which resulted in (i) income tax expense of approximately $6.0 million from the revaluation of our deferred tax assets and liabilities as of the date of enactment as well as (ii) an income tax benefit totaling $74,000 related to a reduction in our existing valuation allowances relating to refundable Alternative Minimum Tax credits. Reasonable estimates were made based on our analysis of the remeasurement of our deferred tax assets and liabilities and valuation allowances under tax reform. These provisional amounts may be adjusted in future periods if additional information is obtained or further clarification and guidance is issued by regulatory authorities regarding the application of the law.

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

33

Results of Operations

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

The following discussion and analysis relates to items that have affected our results of operations for the three months ended September 30, 2018 and 2017. The following table sets forth for the periods presented our selected historical unaudited consolidated statements of operations and production data and does not include results of operations from Carbon Appalachia.

	Three Months Ended
	September 30,						Percent
(in thousands except production and per unit data)	2018			2017			Change
Revenue:
Natural gas sales	$	4,372		$	3,689			19	%
Natural gas liquids sales		406			-			*
Oil sales		11,850			997			*
Commodity derivative loss		(3,902	)		(499	)		682	%
Other income		16			8			100	%
Total revenues		12,742			4,195			204	%
Expenses:
Lease operating expenses		4,767			1,605			197	%
Transportation costs		1,433			556			158	%
Production and property taxes		743			331			125	%
General and administrative		3,517			2,129			65	%
General and administrative - related party reimbursement		(1,170	)		(423	)		177	%
Depreciation, depletion and amortization		2,731			613			346	%
Accretion of asset retirement obligations		206			77			168	%
Total expenses		12,227			4,888			150	%
Operating income (loss)	$	515		$	(693	)		174	%
Other income and (expense):
Interest expense		(1,128	)		(299	)		277	%
Other expenses		1			20			(99	)%
Warrant derivative gain		-			811			*
Equity investment income (loss)		157			(285	)		(155	)%
Total other income (expense)	$	(970	)	$	247			(493	)%
Production data:
Natural gas (Mcf)		1,357,350			1,244,951			9	%
Oil (Bbl)		165,427			21,848			657	%
Natural gas liquids (Bbl)		11,055			-			*
Combined (Mcfe)		2,416,242			1,376,039			76	%
Average prices before effects of hedges:
Natural gas (per Mcf)	$	3.22		$	2.96			9	%
Oil (per Bbl)	$	71.63		$	45.62			57	%
Natural gas liquids (per Bbl)	$	36.70			-			*
Combined (per Mcfe)	$	6.88		$	3.40			102	%
Average prices after effects of hedges**:
Natural gas (per Mcf)	$	3.29		$	2.84			13	%
Oil and (per Bbl)	$	64.29		$	29.52			18	%
Natural gas liquids (per Bbl)	$	36.70		$	-			*
Combined (per Mcfe)	$	6.42		$	3.04			111	%
Average costs (per Mcfe):
Lease operating expenses	$	1.97		$	1.17			68	%
Transportation costs	$	0.59		$	0.40			48	%
Production and property taxes	$	0.31		$	0.24			29	%
Cash-based general and administrative expense, net of related party reimbursement	$	0.89		$	1.08			(17	)%
Depreciation, depletion and amortization	$	1.13		$	0.45			151	%

* Not meaningful or applicable

** Includes settled commodity derivative gains and losses. 

34

Oil, natural gas, natural gas liquids sales- Revenues from sales of oil, natural gas, and natural gas liquids increased approximately 255% to approximately $16.6 million for the three months ended September 30, 2018, from approximately $4.7 million for the three months ended September 30, 2017. This increase was primarily due to the consolidation of Carbon California on February 1, 2018, which contributed approximately $9.4 million in oil, natural gas liquids, and natural gas sales. Oil prices increased from $ 45.62 to $71.63, or 57%, before hedges, and natural gas per MCF increased from $2.96 to $3.22, or 9%, before hedges, respectively.

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 using 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 as such, all mark-to-market gains or losses, as well as settlement gains or losses on the derivative instruments, are recognized in our results of operations. Unrealized gains and losses represent the changes in the fair value of these contracts as the settlement prices of 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, 2018 and 2017, we had commodity derivative losses of approximately $3.9 million and $499,000, respectively.

Lease operating expenses- Lease operating expenses for the three months ended September 30, 2018, increased approximately 197% compared to the three months ended September 30, 2017. This increase is primarily attributed to the consolidation of Carbon California properties. On a per Mcfe basis, lease operating expenses increased from $1.17 per Mcfe for the three months ended September 30, 2017 to $1.97 per Mcfe for the three months ended September 30, 2018. This increase was primarily attributed to the consolidation of Carbon California which is comprised of oil properties which have higher lease operating expenses per unit of production compared to Carbon’s Appalachian based natural gas production.

Transportation costs- Transportation costs for the three months ended September 30, 2018, increased approximately 48% compared to the three months ended September 30, 2017. This increase is attributed to an increase in production as a result of the consolidation of Carbon California that occurred on February 1, 2018. On a per Mcfe basis, these expenses increased from $0.40 per Mcfe for the three months ended September 30, 2017 to $0.59 per Mcfe for the three months ended September 30, 2018. The increase on a per Mcfe basis is primarily due to higher transportation and processing costs per unit for the Carbon California properties as compared to our Appalachia properties.

Production and property taxes- Production and property taxes increased from approximately $331,000 for the three months ended September 30, 2017, to approximately $743,000 for the three months ended September 30, 2018. This increase is primarily attributable to the consolidation Carbon California as of February 1, 2018. Production and property taxes were $0.31 and $0.24 per Mcfe for the three months ended September 30, 2018 and 2017, respectively. Production and property taxes averaged approximately 4.5%   and 4.1% of oil and natural gas sales for the three months ended September 30, 2018 and 2017, respectively. Ad valorem tax rates, which can fluctuate by year, are determined by individual counties where we have production and are assessed on our sales one or two years in arrears depending on the location of the production.

Depreciation, depletion and amortization (DD&A)- DD&A increased from approximately $613,000 for the three months ended September 30, 2017, to approximately $2.7 million for the three months ended September 30, 2018, primarily due to an increase in oil and natural gas production. On a per Mcfe basis, DD&A increased from $0.45 per Mcfe for the three months ended September 30, 2017 to $1.13 per Mcfe for the three months ended September 30, 2018. The increase in depletion rate is primarily attributable to the consolidation of Carbon California in the first quarter of 2018 which increased our blended depletion rate.

General and administrative expenses- Cash-based general and administrative expenses, net of related party reimbursement, were approximately $2.1 million and $1.5 million for the three months ended September 30, 2018 and 2017, respectively. The change was primarily due to an increase in personnel. Non-cash stock-based compensation and other general and administrative expenses for the three months ended September 30, 2018 and 2017 are summarized in the following table:

General and administrative expenses	Three Months Ended September 30,
							Increase/
(in thousands)	2018			2017			(Decrease)
Stock-based compensation	$	189		$	213		$	(24	)
Other general and administrative expenses		3,328			1,916			1,412
General and administrative – related party reimbursement		(1,170	)		(423	)		(747	)
General and administrative expense, net	$	2,347		$	1,706		$	641

Interest expense- Interest expense increased from approximately $299,000 for the three months ended September 30, 2017, to approximately $1.1 million for the three months ended September 30, 2018, primarily due to the consolidation of Carbon California on February 1, 2018, a $3 million draw in July, higher interest rates on our credit facility and higher debt balances on our credit facility for the three months ended September 30, 2018 compared to the same period in 2017. 

35

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

The following discussion and analysis relates to items that have affected our results of operations for the nine months ended September 30, 2018 and 2017. The following table sets forth for the periods presented our selected historical unaudited consolidated statements of operations and production data and does not include results of operations from Carbon Appalachia.

	Nine Months Ended
	September 30,						Percent
(in thousands except production and per unit data)	2018			2017			Change
Revenue:
Natural gas sales	$	11,835		$	11,706			1	%
Natural gas liquids sales		1,119			-			*
Oil sales		22,924			3,189			*
Commodity derivative (loss) gain		(10,550	)		2,642			*
Other income		35			28			26	%
Total revenues		25,363			17,565			44	%
Expenses:
Lease operating expenses		10,824			4,311			151	%
Transportation costs		3,786			1,571			141	%
Production and property taxes		1,792			1,186			51	%
General and administrative		9,007			5,623			60	%
General and administrative – related party reimbursement		(3,383	)		(723	)		368	%
Depreciation, depletion and amortization		6,202			1,847			236	%
Accretion of asset retirement obligations		510			232			120	%
Total expenses		28,738			14,047			105	%
Operating income (loss)	$	(3,375	)	$	3,518			(196	)%
Other income and (expense):
Interest expense		(3,328	)		(821	)		305	%
Warrant derivative gain		225			2,494			(91	)%
Equity investment income (loss)		6,511			(285	)		*
Other income		(3	)		20			(113	)%
Total other income (expense)	$	3,405		$	1,408			142	%
Production data:
Natural gas (Mcf)		4,205,890			3,601,946			17	%
Oil (Bbl)		327,028			66,959			388	%
Natural gas liquids (Bbl)		29,454			-			0	%
Combined (Mcfe)		6,344,782			4,003,700			58	%
Average prices before effects of hedges:
Natural gas (per Mcf)	$	2.81		$	3.25			(14	)%
Oil (per Bbl)	$	70.10		$	47.63			47	%
Natural gas liquids (per Bbl)	$	37.97			-			*
Combined (per Mcfe)	$	5.65		$	3.72			52	%
Average prices after effects of hedges**:
Natural gas (per Mcf)	$	2.89		$	3.77			(23	)%
Oil (per Bbl)	$	62.51		$	58.88			6	%
Natural gas liquids (per Bbl)	$	37.97		$	-			*
Combined (per Mcfe)	$	5.31		$	4.38			21	%
Average costs (per Mcfe):
Lease operating expenses	$	1.71		$	1.08			58	%
Transportation costs	$	0.60		$	0.39			54	%
Production and property taxes	$	0.28		$	0.30			(7	)%
Cash-based general and administrative expense, net of related party reimbursement	$	0.78		$	1.04			(25	)%
Depreciation, depletion and amortization	$	0.98		$	0.46			113	%

* Not meaningful or applicable

** Includes settled derivative gains and losses. 

36

Oil, natural gas, natural gas liquids sales- Revenues from sales of oil, natural gas, and natural gas liquids increased approximately 141% to approximately $35.9 million for the nine months ended September 30, 2018 from approximately $14.9 million for the nine months ended September 30, 2017. This increase was primarily due to the consolidation of Carbon California on February 1, 2018 which contributed approximately $19.1 million in oil, natural gas, and natural gas liquids sales. Oil prices increased from $47.63 to $70.10, or 47%, before hedges, for the nine months ended September 30, 2018 and 2017, respectively. Natural gas prices decreased from $3.25 to $2.81 per MCF before hedges, for the nine months ended September 30, 2018 and 2017, respectively.

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 using 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 as such, all mark-to-market gains or losses, as well as settlement gains or losses on the derivative instruments, are recognized in our results of operations. Unrealized gains and losses represent the changes in the fair value of these contracts as the settlement price of 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, 2018 and 2017, we had commodity derivative losses of approximately $10.6 million and gains of approximately $2.6 million, respectively.

Lease operating expenses- Lease operating expenses for the nine months ended September 30, 2018 increased approximately 151% compared to the nine months ended September 30, 2017. This increase is primarily attributed to the consolidation of Carbon California. On a per Mcfe basis, lease operating expenses increased from $1.08 per Mcfe for the nine months ended September 30, 2017 to $1.71 per Mcfe for the nine months ended September 30, 2018. This increase was primarily attributed to the consolidation of Carbon California, which is comprised of oil properties which have higher lease operating expenses per unit of production compared to Carbon’s Appalachian based natural gas production.

Transportation costs- Transportation costs for the nine months ended September 30, 2018, increased approximately 141% compared to the nine months ended September 30, 2017. This increase is attributed to an increase in production as a result of the consolidation of Carbon California which occurred on February 1, 2018. On a per Mcfe basis, these expenses increased from $0.39 per Mcfe for the nine months ended September 30, 2017, to $0.60 per Mcfe for the nine months ended September 30, 2018. The increase on a per Mcfe basis is primarily due to higher transportation and processing costs per unit for the Carbon California properties as compared to our Appalachia properties.

Production and property taxes- Production and property taxes increased from approximately $1.2 million for the nine months ended September 30, 2017 to approximately $1.8 million for the nine months ended September 30, 2018. This increase is primarily attributed to the consolidation Carbon California as of February 1, 2018. Production and property taxes were $0.28 and $0.30 per Mcfe for the nine months ended September 30, 2018 and 2017, respectively. Production and property taxes averaged approximately 5.0% and 4.2% of oil and natural gas sales for the nine months ended September 30, 2018 and 2017, respectively. Ad valorem tax rates, which can fluctuate by year, are determined by individual counties where we have production and are assessed on our sales one or two years in arrears depending on the location of the production.

Depreciation, depletion and amortization (DD&A)- DD&A increased from approximately $1.8 million for the nine months ended September 30, 2017, to approximately $6.2 million for the nine months ended September 30, 2018, primarily due to an increase in oil and natural gas production. On a per Mcfe basis, DD&A increased from $0.46 per Mcfe for the nine months ended September 30, 2017 to $0.98 per Mcfe for the nine months ended September 30, 2018. The increase in depletion rate is primarily attributable to the consolidation of Carbon California in the first quarter of 2018 which increased our blended depletion rate.

37

General and administrative expenses- Cash-based general and administrative expenses, net of related party reimbursement, increased from approximately $4.1 million for the nine months ended September 30, 2017, to approximately $5.0 million for the nine months ended September 30, 2018. The change was primarily due to an increase in personnel. Non-cash stock-based compensation and other general and administrative expenses for the nine months ended September 30, 2018 and 2017, are summarized in the following table:

General and administrative expenses	Nine Months Ended September 30,
							Increase/
(in thousands)	2018			2017			(Decrease)
Stock-based compensation	$	671		$	752		$	(81	)
Other general and administrative expenses		8,336			4,871			3,465
General and administrative - related party reimbursement		(3,383	)		(723	)		(2,660	)
General and administrative expense, net	$	5,624		$	4,900		$	724

Interest expense- Interest expense increased from approximately $821,000 for the nine months ended September 30, 2017, to approximately $3.3 million for the nine months ended September 30, 2018, primarily due the consolidation of Carbon California on February 1, 2018, a $3 million draw in July, higher interest rates on our credit facility and higher debt balances on our credit facility for the nine months ended September 30, 2018 compared to the same period in 2017. 

Carbon Appalachia

The following table sets forth selected historical unaudited consolidated statements of operations and production data for Carbon Appalachia.

(in thousands)	As of  September 30, 2018
Current assets	$	22,478
Total oil and gas properties, net	$	81,833
Total other property and equipment, net	$	15,880
Other long-term assets	$	1,302
Current liabilities	$	15,313
Non-current liabilities	$	61,234
Total members’ equity	$	44,946

	Three months ended		Three months ended
(in thousands)	September 30, 2018		September 30, 2017
Revenues	$	18,058	$	1,348
Operating expenses		16,686		2,692
Income from operations		1,372		(1,344	)
Net income	$	537	$	(1,546	)

	Nine months ended		April 3, 2017 to
(in thousands)	September 30, 2018		September 30, 2017
Revenues	$	62,480	$	2,905
Operating expenses		56,441		4,449
Income from operations		6,039		(1,544	)
Net income	$	4,017	$	(1,874	)

38

Liquidity and Capital Resources

Our exploration, development and acquisition activities may require us to make significant operating and capital expenditures. Historically, we have used cash flow from operations and our credit facilities as our primary sources of liquidity and on occasion, we have engaged in the sale of assets. We have filed a registration statement for common stock equity offering. We are also exploring the debt markets for additional capital resources to purchase Old Ironsides’ interest in Carbon Appalachia. Changes in the market prices for oil and natural gas directly impact our level of cash flow generated from operations. The prices we receive for our production are determined by prevailing market conditions and greatly influence our revenue, cash flow, profitability, access to capital and future rate of growth. We employ a commodity hedging strategy in an attempt to moderate the effects of commodity price fluctuations on our cash flow.

The following tables reflect our outstanding derivative agreements as of September 30, 2018:

Carbon Energy Corporation Physical Delivery Contracts and Oil and Gas Derivatives

	Natural Gas Swaps				Natural Gas Collars				Oil Swaps
			Weighted				Weighted				Weighted
			Average				Average Price				Average
Year	MMBtu		Price (a)		MMBtu		Range (a)		Bbl		Price (b)
2018		870,000	$	3.00		-		-		23,000	$	55.09
2019		2,596,000	$	2.86		204,000		$2.60-$2.80		61,900	$	56.05
2020		-		-		1,018,000		$2.50-$2.70		21,000	$	60.72

(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.

Carbon California Physical Delivery Contracts and Oil and Gas Derivatives

	Natural Gas Swaps				Natural Gas Collars				Oil Swaps
			Weighted				Weighted				Weighted				Weighted
			Average				Average Price		WTI		Average		Brent		Average
Year	MMBtu		Price (a)		MMBtu		Range (a)		Bbl		Price (b)		Bbl		Price (c)
2018		90,000	$	3.03		-		-		48,628	$	53.06		62,792	$	66.46
2019		-	$	-		360,000		$2.60 - $3.03		139,797	$	51.96		141,786	$	66.58
2020		-	$	-		-		-		73,147	$	50.12		139,682	$	65.71
2021		-	$	-		-		-		-	$	-		86,341	$	67.12

(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 and NYMEX 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 we will receive for the volumes under contract, while the floor establishes a minimum price.

This hedge program mitigates uncertainty regarding cash flow that we will receive with respect to a portion of our expected production through 2021. Future hedging activities may result in reduced income or even financial losses to us. See ” Risk Factors- We have entered into natural gas and oil derivative contracts and may in the future enter into additional commodity derivative contracts for a portion of our production, which may result in future cash payments or prevent us from receiving the full benefit of increases in commodity prices ,” in our Annual Report on Form 10-K for further details of the risks associated with our hedging activities. In the future, we may determine to increase or decrease our hedging positions.

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

39

Management Reimbursements

In our role as manager of Carbon California and Carbon Appalachia, we received reimbursements for the provision of management from Carbon Appalachia of approximately $744,000 and $2.3 million for the three and nine months ended September 30, 2018, and $50,000 for the one month ended January 31, 2018, from Carbon California. These reimbursements are included in general and administrative - related party reimbursement on our unaudited consolidated statements of operations. Effective February 1, 2018, the management reimbursement received from Carbon California is eliminated at consolidation. This elimination was $650,000 for the period February 1, 2018 through September 30, 2018.

In addition to the management reimbursements, approximately $376,000 and $1.1 million in general and administrative expenses were reimbursed for the three and nine months ended September 30, 2018 from Carbon Appalachia, and $14,000 for the one month ended January 31, 2018, from Carbon California. General and administrative expenses reimbursed by Carbon California and eliminated in consolidation were approximately $42,000 for the period February 1, 2018, through September 30, 2018.

Operating Reimbursements

In our role as operator of Carbon Appalachia, we receive reimbursements of operating expenses. These expenses are recorded directly to receivable - related party on our unaudited consolidated balance sheets and are therefore not included in our operating expenses on our unaudited consolidated statements of operations.

Bank Credit Facility 

Our Credit Facility 

In 2016, we entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank. LegacyTexas Bank is the initial lender and acts as administrative agent.

The credit facility has a maximum availability of $100.0 million (with a $500,000 sublimit for letters of credit), which availability is subject to the amount of the borrowing base. The borrowing base is subject to semi-annual redeterminations in March and September. In July 2018, the borrowing base was increased from $25.0 million to $28.0 million, of which approximately $26.1 million was drawn as of September 30, 2018. Our effective interest rate as of September 30, 2018 was 7.52%.

On March 27, 2018, the credit facility was amended to revise the calculation of the Leverage Ratio from a Debt/EBITDA ratio to a Net Debt/Adjusted EBITDA ratio, reset the testing period used in the determination of Adjusted EBITDA, eliminated the minimum current ratio and substituted alternative liquidity requirements, including maximum allowed current liabilities in relation to current assets, a minimum liquidity covenant of $750,000 and maximum aged trade payable requirements. As of September 30, 2018, we were in compliance with our financial covenants.

Carbon California’s Private Placement Notes

On February 15, 2017, Carbon California (i) entered into a Note Purchase Agreement (the “Note Purchase Agreement”) for the issuance and sale of Senior Secured Revolving Notes to Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America with a revolving borrowing capacity of $25.0 million (the “Senior Revolving Notes”) which mature on February 15, 2022 and (ii) entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”) with Prudential for the issuance and sale of $10.0 million of Senior Subordinated Notes (the “Subordinated Notes”) due February 15, 2024. We are not a guarantor of the Senior Revolving Notes or the Subordinated Notes. The closing of the Note Purchase Agreement and the Securities Purchase Agreement on February 15, 2017, resulted in the sale and issuance by Carbon California of (i) Senior Revolving Notes in the principal amount of $10.0 million and (ii) Subordinated Notes in the original principal amount of $10.0 million. 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 upon delivery of any reserve report. On May 1, 2018, the revolving borrowing base increased to $41.0 million, of which $38.5 million is outstanding as of September 30, 2018. On May 1, 2018, Carbon California entered into a securities purchase agreement with Prudential, which resulted in (i) the issuance and sale of $3.0 million of Senior Subordinated Notes due February 15, 2024 and (ii) the issuance of 585 Class A Units of Carbon California as partial consideration for the Subordinated Notes. The ability of Carbon California to make distributions to its owners, including us, is dependent upon the terms of the Note Purchase Agreement and securities purchase agreement, which currently prohibit distributions unless they are agreed to by Prudential.

40

Interest is payable quarterly and accrues on borrowings under the Senior Revolving Notes at a rate per annum equal to either (i) the prime rate plus an applicable margin of 4.00% or (ii) the LIBOR rate plus an applicable margin of 5.00% at our option. Carbon California is obligated to pay certain fees and expenses in connection with the Senior Revolving Notes, including a commitment fee for any unused amounts of 0.50%. Interest is payable quarterly and accrues on the Subordinated Notes at a fixed rate of 12.0% per annum.

The Senior Revolving Notes and the 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.

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. Carbon California may not voluntarily prepay the Subordinated Notes prior to February 15, 2019, and thereafter may do so subject to a premium of 3% which reduces to 0% after February 17, 2020. In the event the Subordinated Notes are accelerated prior to February 15, 2019, Carbon California would owe a make-whole premium calculated using a discount rate of 1% over United States Treasury securities rates, and otherwise calculated as provided in the Securities Purchase Agreement. Carbon California may not voluntarily prepay the 2018 Subordinated Notes prior to May 1, 2020, and thereafter may do so subject to a premium of 3% which reduces to 0% after May 1, 2021. In the event the 2018 Subordinated Notes are accelerated prior to May 1, 2020, Carbon California would owe a make-whole premium calculated using a discount rate of 1% over United States Treasury securities rates.

Additional borrowings under the Senior Revolving Notes may be used to fund field development projects and to fund future complementary acquisitions and for general working capital purposes of Carbon California.

As of September 30, 2018, Carbon California was in compliance with its financial covenants.

Carbon Appalachia’s Credit Facility

In 2017, Carbon Appalachia Enterprises, LLC, formerly known as Carbon Tennessee Company, LLC (“CAE”), a subsidiary of Carbon Appalachia, entered into a 4-year $100.0 million senior secured asset based revolving credit facility with LegacyTexas Bank with an initial borrowing base of $10.0 million (the “CAE Credit Facility”).

The CAE Credit Facility borrowing base was adjusted for acquisitions completed in 2017. Most recently, on April 30, 2018, CAE amended the CAE Credit Facility, which increased the borrowing base to $70.0 million with redeterminations as of April 1 and October 1 each year. As of September 30, 2018, there was approximately $38.0 million outstanding under the CAE Credit Facility. As of September 30, 2018, CAE was in compliance with its financial covenants.

Sources and Uses of Cash

Our primary sources of liquidity and capital resources are operating cash flow and borrowings under our credit facilities. Our primary uses of funds are expenditures for acquisition, exploration and development activities, leasehold and property acquisitions, other capital expenditures and debt service. We have also filed a Registration Statement with the Securities Exchange Commission (“SEC”) with our intent to raise additional common equity to be used to fund the purchase of Carbon Appalachia membership interest from Old Ironsides, pay down debt and other general corporate purposes, including to fund potential expansion capital expenditures and acquisitions.

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

The following table presents net cash provided by or used in operating, investing and financing activities for the nine months ended September 30, 2018 and 2017.

	Nine Months Ended
	September 30,
(in thousands)	2018			2017
Net cash provided by operating activities	$	3,312		$	2,580
Net cash used in investing activities	$	(44,406	)	$	(8,106	)
Net cash provided by (used in) financing activities	$	43,921		$	5,787

41

Net cash provided by or used in 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 $732,000 for the nine months ended September 30, 2018, as compared to the same period in 2017. The increase was primarily due to an increase in production and the consolidation of Carbon California, partially offset by decreases in working capital and increased cash interest payments.

Net cash provided by or 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 in addition to expenditures to fund our equity investment in Carbon Appalachia. Net cash used in investing activities increased approximately $36.3 million for the nine months ended September 30, 2018 as compared to the same period in 2017 primarily due to the Seneca and Liberty Acquisitions.

The increase in cash provided by financing cash flows of approximately $38.1 million for the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017 was primarily due to $33.9 million in proceeds from borrowings under our credit facilities and those of Carbon California, $5.0 million in proceeds from the Preferred Stock and $5.0 million in proceeds from Prudential for the Seneca Acquisition.

Capital Expenditures

Capital expenditures for the nine months ended September 30, 2018 and 2017, are summarized in the following table:

	Nine Months Ended September 30,
(in thousands)	2018		2017
Unevaluated property acquisitions	$	100	$	230
Oil and gas asset purchase		43,096		-
Drilling and development		940		738
Other		545		284
Total capital expenditures	$	44,681	$	1,252

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

Due to low commodity prices in recent years, we have focused on the optimization of our natural gas gathering and compression facilities and marketing arrangements to provide greater flexibility in moving production to markets with more favorable pricing. Other factors impacting the level of our capital expenditures include the cost and availability of oil field services, general economic and market conditions and weather disruptions. 

Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of September 30, 2018, the off-balance sheet arrangements and transactions that we entered into included (i) operating lease agreements, (ii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as natural gas transportation contracts, and (iii) oil and natural gas physical delivery contracts that are not expected to be net cash settled and are considered to be normal sales contracts and not derivatives. We do not believe that any of these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.

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 2017 Annual Report on Form 10-K. As of September 30, 2018, there have been no significant changes to our critical accounting policies and estimates since our 2017 Annual Report was filed.

Forward Looking Statements

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

42

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

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

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

● our future financial condition and results of operations and acquisitions;

● 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;

● 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 2017 Annual Report on Form 10-K and our First and Second Quarter 2018 Quarterly Reports on Form 10-Q.

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

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

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

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

ITEM 4. Controls and Procedures

Evaluation of disclosure controls and procedures.  

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

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

Changes in internal control over financial reporting.  There were no changes in our internal control over financial reporting during the quarter ended September 30, 2018, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

43

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

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

ITEM 1A. Risk Factors

Risk factors relating to us are discussed in “Part I, Item 1A. Risk Factors” in our 2017 Annual Report and “Part II, Item 1A. Risk Factors” in our First Quarter 2018 Quarterly Report. There have been no material changes from the risk factors previously disclosed in our 2017 Annual Report and First Quarter 2018 Quarterly Report. 

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

None.

ITEM 6. Exhibits

Exhibit No.	Description
3.1	Amended and Restated Certificate of Incorporation of Carbon Natural Gas Company, dated as of April 27, 2011, incorporated by reference to Exhibit 3(i)(a) to Form 10-K filed on March 31, 2017.
3.2	Certificate of Amendment to the Certificate of Incorporation of Carbon Natural Gas Company, dated as of July 14, 2011, incorporated by reference to Exhibit 3(i) to Form 8-K filed on July 19, 2011.
3.3	Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Carbon Natural Gas Company, dated as of March 15, 2017, incorporated by reference to Exhibit 3.1 to Form 8-K filed on March 16, 2017.
3.4	Certificate of Correction to the Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Carbon Natural Gas Company, dated as of March 23, 2018, incorporated by reference to Exhibit 3.1 to Form 8-K filed on March 28, 2018.
3.5	Certificate of Designation with respect to Series B Convertible Preferred Stock, incorporated by reference to Exhibit 3(i) to Form 8-K filed on April 9, 2018.
3.6	Amended and Restated Bylaws, incorporated by reference to Exhibit 3(i) to Form 8-K filed on May 5, 2015.
3.7	Amendment No. 1 to Amended and Restated Bylaws, incorporated by reference to Exhibit 3(ii) to Form 8-K filed on June 4, 2018.
10.1	Letter Amendments, dated October 15, 2018 and November 6, 2018, to Membership Interest Purchase Agreement, dated as of May 4, 2018, by and among Old Ironsides Fund II-A Portfolio Holding Company, LLC, Old Ironsides Fund II-B Portfolio Holding Company, LLC, and Carbon Natural Gas Company, incorporated by reference to Exhibit 10.1 to Form 8-Ks filed on October 19, 2018.
31.1*	Rule 13a-14(a)/15d-14(a) - Certification of Chief Executive Officer.
31.2*	Rule 13a-14(a)/15d-14(a) - Certification of Chief Financial Officer.
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

44

Pursuant to the requirements of Section 13 or Section 15(d) 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, 2018	By:	/s/ Patrick R. McDonald
		PATRICK R. MCDONALD,
		Chief Executive Officer
Date: November 13, 2018	By:	/s/ Kevin D. Struzeski
		KEVIN D. STRUZESKI
		Chief Financial Officer

45