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 quarter ended September 30, 2016

 

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 NATURAL GAS COMPANY

(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) 407-7043

 

(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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).

 

YES  ☒                      NO  ☐

 

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

 

Large accelerated filer ☐	Accelerated filer ☐	Non-accelerated filer ☐	Smaller reporting company ☒
		(Do not check if a smaller reporting company)

 

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 10, 2016, there were 110,638,849 issued and outstanding shares of the Company’s common stock, $0.01 par value.

 

 

 

Carbon Natural Gas Company

 

TABLE OF CONTENTS

  

Part I – FINANCIAL INFORMATION

 

Item 1.  Consolidated Financial Statements
Consolidated Balance Sheets (unaudited)	2
Consolidated Statements of Operations (unaudited)	3
Consolidated Statements of Stockholders’ Equity (unaudited)	4
Consolidated Statements of Cash Flows (unaudited)	5
Notes to the Consolidated Financial Statements (unaudited)	6
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 4. Controls and Procedures	32
Part II – OTHER INFORMATION
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 6. Exhibits	33

  

 

PART I. FINANCIAL INFORMATION

ITEM 1.

Financial Statements

 

CARBON NATURAL GAS COMPANY

Consolidated Balance Sheets

 

		September 30,				December 31,
(in thousands)		2016				2015
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	128			$	305
Accounts receivable:
Revenue			1,240				1,082
Joint interest billings and other			609				778
Commodity derivative asset			-				408
Prepaid expense, deposits and other current assets			185				213
Total current assets			2,162				2,786
Property and equipment (note 4):
Oil and gas properties, full cost method of accounting:
Proved, net			19,836				25,032
Unproved			3,140				3,194
Other property and equipment, net			167				238
			23,143				28,464
Investments in affiliates (note 5)			741				1,025
Other long-term assets			185				433
Total assets		$	26,231			$	32,708
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities		$	6,043			$	5,621
Firm transportation contract obligations (note 12)			421				436
Commodity derivative liability			264				-
Notes payable (note 6)			4,007				-
Total current liabilities			10,735				6,057
Non-current liabilities:
Asset retirement obligations (note 3)			3,205				3,095
Firm transportation contract obligations (note 12)			103				416
Notes payable (note 6)			-				3,500
Total non-current liabilities			3,308				7,011
Commitments (note 12)
Stockholders’ equity:
Preferred stock, $0.01 par value; authorized 1,000,000 shares, no shares issued and outstanding at September 30, 2016 and December 31, 2015			-				-
Common stock, $0.01 par value; authorized 200,000,000 shares, 110,638,849 and 107,655,916 shares issued and outstanding at September 30, 2016 and December 31, 2015, respectively			1,107				1,077
Additional paid-in capital			56,401				54,394
Accumulated deficit			(47,174	)			(38,130	)
Total Carbon stockholders’ equity			10,334				17,341
Non-controlling interests			1,854				2,299
Total stockholders’ equity			12,188				19,640
Total liabilities and stockholders’ equity		$	26,231			$	32,708

 

See accompanying notes to Consolidated Financial Statements.

 

 

CARBON NATURAL GAS COMPANY

Consolidated Statements of Operations

(Unaudited)

 

		Three Months Ended September 30,								Nine Months Ended September 30,
(in thousands except per share amounts)		2016				2015				2016				2015
Revenue:
Natural gas sales		$	1,431			$	1,567			$	3,484			$	4,453
Oil sales			765				1,104				2,201				4,187
Commodity derivative income (loss)			160				353				(474	)			500
Other income			9				53				10				71
Total revenue			2,365				3,077				5,221				9,211
Expenses:
Lease operating expenses			622				717				1,864				2,330
Transportation costs			364				496				1,121				1,251
Production and property taxes			184				334				443				763
General and administrative			2,327				1,830				5,402				5,496
Depreciation, depletion and amortization			393				611				1,332				1,952
Accretion of asset retirement obligations			35				32				105				95
Impairment of oil and gas properties			-				-				4,299				-
Total expenses			3,925				4,020				14,566				11,887
Operating loss			(1,560	)			(943	)			(9,345	)			(2,676	)
Other income and (expense):
Interest expense			(38	)			(52	)			(141	)			(149	)
Equity investment (loss) income			(4	)			7				(10	)			6
Other income (expense)			-				21				17				(15	)
Total expense			(42	)			(24	)			(134	)			(158	)
Loss before income taxes			(1,602	)			(967	)			(9,479	)			(2,834	)
Provision for income taxes			-				-				-				-
Net loss before non-controlling interests			(1,602	)			(967	)			(9,479	)			(2,834	)
Net loss attributable to non-controlling interests			(3	)			(9	)			(435	)			(65	)
Net loss attributable to controlling interest		$	(1,599	)		$	(958	)		$	(9,044	)		$	(2,769	)
Net loss per common share:
Basic		$	(0.01	)		$	(0.01	)		$	(0.08	)		$	(0.03	)
Diluted		$	(0.01	)		$	(0.01	)		$	(0.08	)		$	(0.03	)
Weighted average common shares outstanding:
Basic			110,149				107,047				109,102				106,720
Diluted			110,149				107,047				109,102				106,720

 

See accompanying notes to Consolidated Financial Statements.

 

 

CARBON NATURAL GAS COMPANY

Consolidated Statement of Stockholders’ Equity

(Unaudited)

(in thousands)

  

										Additional				Non-								Total
		Common Stock								Paid-in				Controlling				Accumulated				Stockholders’
		Shares				Amount				Capital				Interests				Deficit				Equity
Balances, December 31, 2015			107,655			$	1,077			$	54,394			$	2,299			$	(38,130	)		$	19,640
Stock-based compensation			-				-				2,037				-				-				2,037
Restricted stock vested			1,293				13				(13	)			-				-				-
Performance units vested			1,690				17				(17	)			-				-				-
Non-controlling interests distributions, net			-				-				-				(3	)			-				(3	)
Non-controlling interest-purchase			-				-				-				(7	)			-				(7	)
Net loss			-				-				-				(435	)			(9,044	)			(9,479	)
Balances, September 30, 2016			110,638			$	1,107			$	56,401			$	1,854			$	(47,174	)		$	12,188

 

See accompanying notes to Consolidated Financial Statements. 

 

 

CARBON NATURAL GAS COMPANY

Consolidated Statements of Cash Flows

(Unaudited)

 

		Nine Months Ended
		September 30,
(in thousands)		2016				2015
Cash flows from operating activities:
Net loss		$	(9,479	)		$	(2,834	)
Items not involving cash:
Depreciation, depletion and amortization			1,332				1,952
Accretion of asset retirement obligations			105				95
Unrealized commodity derivative loss			823				779
Impairment of oil and gas properties			4,299				-
Stock-based compensation expense			2,037				1,071
Equity investment loss (income)			10				(6	)
Other			(8	)			(12	)
Net change in:
Accounts receivable			43				1,680
Prepaid expenses, deposits and other current assets			27				(51	)
Accounts payable, accrued liabilities and firm transportation obligations			118				(1,795	)
Net cash (used in) provided by operating activities			(693	)			879
Cash flows from investing activities:
Development and acquisition of properties and equipment			(328	)			(2,648	)
Proceeds from sale of oil and gas properties and other assets			8				68
Equity investment distribution			275				-
Other long-term assets			57				459
Net cash provided by (used in) investing activities			12				(2,121	)
Cash flows from financing activities:
Proceeds from notes payable			707				1,800
Payments on notes payable			(200	)			(600	)
Purchase of common stock			-				(244	)
Distributions to non-controlling interests			(3	)			(79	)
Net cash provided by financing activities			504				877
Net decrease in cash and cash equivalents			(177	)			(365	)
Cash and cash equivalents, beginning of period			305				1,132
Cash and cash equivalents, end of period		$	128			$	767

 

See accompanying notes to Consolidated Financial Statements. 

 

 

CARBON NATURAL GAS COMPANY

Notes to Consolidated Financial Statements

(Unaudited)

 

Note 1 – Organization

 

Carbon Natural Gas Company (“Carbon” or the “Company”) 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. Collectively, Carbon, Nytis USA and Nytis LLC are referred to as the Company.

 

Note 2 – Liquidity

 

The accompanying unaudited Consolidated Financial Statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these Consolidated Financial Statements.

 

On October 3, 2016, Nytis LLC completed an acquisition of producing natural gas wells and natural gas gathering facilities located in the Appalachia Basin. In connection with and concurrently with the closing of the acquisition, the Company entered into a four year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank. The initial borrowing base established under the credit facility is $17.0 million. See Note 6 – Bank Credit Facility and Note 14 – Subsequent Events, for additional information.

 

Based on these events, the Company believes that with the cash flow from Carbon’s expanded asset base, as well as access to undrawn debt capacity under the new credit facility, the Company will have sufficient liquidity to fund normal recurring operating needs, anticipated capital expenditures (other than the potential acquisition of additional oil and natural gas properties) and its contractual obligations.

 

Note 3 – Summary of Significant Accounting Policies

 

Basis of Presentation

 

The accompanying unaudited Consolidated Financial Statements of the Company 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 of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, the accompanying unaudited Consolidated Financial Statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of September 30, 2016, the Company’s results of operations for the three and nine months ended September 30, 2016 and 2015 and the Company’s cash flows for the nine months ended September 30, 2016 and 2015. Operating results for the three and nine months ended September 30, 2016 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 and other factors. For a more complete understanding of the Company’s operations, financial position and accounting policies, the unaudited Consolidated Financial Statements and the notes thereto should be read in conjunction with the Company’s audited Consolidated Financial Statements for the year ended December 31, 2015 filed on Form 10-K with the Securities and Exchange Commission.

 

In the course of preparing the unaudited Consolidated Financial Statements, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenue and expenses and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and accordingly, actual results could differ from amounts initially established.

 

Principles of Consolidation

 

The unaudited Consolidated Financial Statements include the accounts of Carbon, Nytis USA and its consolidated subsidiary. Carbon owns 100% of Nytis USA. Nytis USA owns approximately 99% of Nytis LLC.

 

Nytis LLC also holds an interest in various oil and gas partnerships. For partnerships where the Company has a controlling interest, the partnerships are consolidated. The Company is currently consolidating on a pro-rata basis 47 partnerships. In these instances, the Company reflects the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on its Consolidated Statements of Operations and also reflects the non-controlling ownership interests in the net assets of the partnerships as non-controlling interests within stockholders’ equity on its Consolidated Balance Sheets. All significant intercompany accounts and transactions have been eliminated.

 

 

Note 3 – Summary of Significant Accounting Policies (continued)

 

In accordance with established practice in the oil and gas industry, the Company’s unaudited Consolidated Financial Statements also include its pro-rata share of assets, liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which the Company has a non-controlling interest.

 

Non-majority owned investments that do not meet the criteria for pro-rata consolidation are accounted for using the equity method when the Company has the ability to significantly influence the operating decisions of the investee. When the Company does 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 Consolidated Financial Statements.

 

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 whether or not 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.

 

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 months ended September 30, 2016, the Company did not recognize a ceiling test impairment as the Company’s full cost pool did not exceed the ceiling limitations. For the nine months ended September 30, 2016, the Company recognized a ceiling test impairment of approximately $4.3 million as the Company’s full cost pool exceeded ceiling limitations during the first six months of 2016. For the three and nine months ended September 30,

 

 

Note 3 – Summary of Significant Accounting Policies (continued)

 

2015, the Company did not recognize a ceiling test impairment. Future declines in oil and natural gas prices, and increases in future operating expenses and future development costs could result in additional impairments of our oil and gas properties in future periods. The effects of low commodity prices may continue to impact the ceiling test value until such time that prices improve. Impairment charges are a non-cash charge and accordingly, do not affect cash flow, but adversely affect our net income and stockholders’ equity.

 

Investments in Affiliates

 

Investments in non-consolidated affiliates are accounted for under either the equity or cost method of accounting as appropriate. The cost method of accounting is used for investments in affiliates in which the Company has less than 20% of the voting interests of a corporate affiliate or less than a 5% interest of a partnership or limited liability company and does not have significant influence. Investments in non-consolidated affiliates, accounted for using the cost method of accounting, are recorded at cost and an impairment assessment of each investment is 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 the Company holds between 20% and 50% of the voting interest in non-consolidated corporate affiliates or greater than a 5% interest in partnerships or limited liability companies and exercises significant influence or control, the equity method of accounting is used to account for the investment. The Company’s investment in affiliates that are accounted for using the equity method of accounting, increases or decreases by the Company’s share of the affiliate’s profits or losses and such profits or losses are recognized in the Company’s Consolidated Statements of Operations. The Company reviews equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred. The amount of the impairment is based on quoted market prices, where available, or other valuation techniques.

 

Asset Retirement Obligations

 

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

 

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

 

The following table is a reconciliation of the ARO for the nine months ended September 30, 2016 and 2015:

 

		Nine Months Ended September 30,
(in thousands)		2016				2015
Balance at beginning of period		$	3,095			$	2,968
Accretion expense			105				95
Additions during period			5				-
Balance at end of period		$	3,205			$	3,063

  

 

Note 3 – Summary of Significant Accounting Policies (continued)

 

Earnings Per Common Share

 

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

 

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

 

		Three Months Ended September 30,								Nine Months Ended September 30,
(in thousands except per share amounts)		2016				2015				2016				2015
Net loss		$	(1,599	)		$	(958	)		$	(9,044	)		$	(2,769	)
Basic weighted-average common shares outstanding during the period			110,149				107,047				109,102				106,720
Add dilutive effects of stock options, warrants and non-vested shares of restricted stock			-				-				-				-
Diluted weighted-average common shares outstanding during the period			110,149				107,047				109,102				106,720
Basic net loss per common share		$	(0.01	)		$	(0.01	)		$	(0.08	)		$	(0.03	)
Diluted net loss per common share		$	(0.01	)		$	(0.01	)		$	(0.08	)		$	(0.03	)

 

For the three and nine months ended September 30, 2016 and 2015, the Company had a net loss and therefore, the diluted net loss per share calculation excluded the anti-dilutive effect of approximately 250,000 warrants and approximately 5.8 million and 5.0 million non-vested shares of restricted stock in 2016 and 2015, respectively. For the three and nine months ended September 30, 2016, approximately 6.0 million restricted performance units, in each period, subject to future contingencies are excluded from the basic and diluted loss per share. For the three and nine months ended September 30, 2015, approximately 6.3 million restricted performance units, subject to future contingencies, were excluded from the basic and diluted loss per share in each respective period.

 

Adopted and Recently Issued Pronouncements

 

In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, Improvements To Employee Share-Based Payment Accounting (“ASU 2016-09”). The objective of this ASU is to simplify several aspects of the accounting for employee share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities and classification in the statement of cash flows. ASU 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. Portions of this ASU must be applied prospectively while other portions may be applied either prospectively or retrospectively. Early adoption is permitted. The Company is currently evaluating the impact on its Consolidated Financial Statements of adopting ASU 2016-09.

 

In February 2016, the FASB issued ASU No. 2016-02, Leases (“ASU 2016-02”). The objective of this ASU is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and should be applied using a modified retrospective approach. Early adoption is permitted. The Company is currently evaluating the impact on its Consolidated Financial Statements of adopting ASU 2016-02.

  

 

Note 3 – Summary of Significant Accounting Policies (continued)

 

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements – Going Concern (“ASU 2014-15”). The objective of ASU 2014-15 is to provide guidance on management’s responsibility to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for fiscal years ending after December 15, 2016 and annual and interim periods thereafter. The Company is currently evaluating the impact on its Consolidated Financial Statements of adopting ASU 2014-15.

 

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The FASB subsequently issued ASU 2015-14, ASU 2016-08, ASU 2016-10 and ASU 2016-12, which deferred the effective date of ASU 2014-09 and provided additional implementation guidance. These ASUs are effective for fiscal years, and interim periods within those years, beginning after December 31, 2017. The standards permit retrospective application using either of the following methodologies: (i) restatement of each prior reporting period presented or (ii) recognition of a cumulative-effect adjustment as of the date of initial application. The Company is currently evaluating the impact of adopting these standards on its Consolidated Financial Statements, as well as the transition method to be applied.

 

Note 4 – Property and Equipment

 

Net property and equipment as of September 30, 2016 and December 31, 2015 consists of the following:

  

(in thousands)		September 30, 2016				December 31, 2015
Oil and gas properties:
Proved oil and gas properties		$	97,802			$	97,453
Unproved properties not subject to depletion			3,140				3,194
Accumulated depreciation, depletion, amortization and impairment			(77,966	)			(72,421	)
Net oil and gas properties			22,976				28,226
Furniture and fixtures, computer hardware and software, and other equipment			804				825
Accumulated depreciation and amortization			(637	)			(587	)
Net other property and equipment			167				238
Total net property and equipment		$	23,143			$	28,464

 

As of September 30, 2016 and December 31, 2015, the Company had approximately $3.1 million and $3.2 million, respectively, of unproved oil and gas properties not subject to depletion. The costs not subject to depletion relate to unproved properties that are excluded from amortized capital costs until it is determined whether or not proved reserves can be assigned to such properties. The excluded properties are assessed for impairment at least annually. Subject to industry conditions, evaluation of most of these properties and the inclusion of their costs in amortized capital costs is expected to be completed within five years.

 

During the three months ended September 30, 2016 and 2015, the Company capitalized general and administrative expenses applicable to development and exploration activities of approximately $142,000 and $133,000, respectively. During the nine months ended September 30, 2016 and 2015, the Company capitalized general and administrative expenses applicable to development and exploration activities of approximately $431,000 and $421,000, respectively.

 

Depletion expense related to oil and gas properties for the three months ended September 30, 2016 and 2015 was approximately $368,000, or $0.60 per Mcfe, and approximately $578,000, or $0.87 per Mcfe, respectively. For the nine months ended September 30, 2016 and 2015, depletion expense was approximately $1.2 million, or $0.68 per Mcfe, and approximately $1.8 million, or $0.94 per Mcfe, respectively.

 

 

Note 4 – Property and Equipment (continued)

 

Depreciation and amortization expense related to furniture and fixtures, computer hardware and software and other equipment for the three months ended September 30, 2016 and 2015 was approximately $25,000 and $34,000, respectively, and for the nine months ended September 30, 2016 and 2015 was approximately $85,000 and $106,000, respectively.

 

Note 5– Equity Method Investment

 

The Company has a 50% interest in Crawford County Gas Gathering Company, LLC (“CCGGC”) which owns and operates pipelines and related gathering and treating facilities. The Company’s gas production located in Illinois is gathered and transported on CCGGC’s gathering facilities. The Company’s investment in CCGGC is accounted for under the equity method of accounting, and its share of the income or loss is recognized. For the nine months ended September 30, 2016 and 2015, the Company recorded equity method loss of approximately $10,000 and income of approximately $6,000, respectively, related to this investment. In addition, during the first quarter of 2016, the Company received a cash distribution of $275,000 from CCGGC.

 

Note 6 – Bank Credit Facility

 

On September 30, 2016, the Company terminated its credit facility with Bank of Oklahoma. On October 3, 2016, in connection with and concurrently with the closing of an acquisition of producing natural gas wells and natural gas gathering facilities located in the Appalachian Basin (the “EXCO Acquisition”), Carbon entered into a 4-year $100.0 million senior secured asset-based revolving credit facility (the “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 $0.5 million 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 is $17.0 million.

 

The Credit Facility is guaranteed by each existing and future direct or indirect subsidiary of Carbon (subject to certain exceptions). The obligations of Carbon and the subsidiary guarantors under the Credit Facility are secured by pledges of the equity of Nytis USA held by Carbon and the equity of Nytis LLC held by Nytis USA and by essentially all tangible and intangible personal and real property of the Company.

 

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 Carbon’s option. The actual margin percentage is dependent on the Credit Facility utilization percentage. Carbon is obligated to pay certain fees and expenses in connection with the Credit Facility, including a commitment fee for any unused amounts of 0.50% and an origination fee of 0.75%.

 

The Credit Facility contains certain affirmative and negative covenants that, among other things, limit the Company’s ability to (i) incur additional debt; (ii) incur additional liens; (iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distributions on, or repurchases of, equity; (vi) make certain investments; (vii) enter into certain transactions with its affiliates; (viii) enter into sales-leaseback transactions; (ix) make optional or voluntary payments of debt; (x) change the nature of its business; (xi) change its 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 certain basket amounts and acceptable transaction levels. In addition, the Credit Facility requires Carbon’s compliance, on a consolidated basis, with (i) a maximum funded Debt/EBITDA ratio of 3.5 to 1.0 and (ii) a minimum current ratio of 1.0 to 1.0, commencing with the quarter ending March 31, 2017.

 

Carbon may at any time repay the loans under the Credit Facility, in whole or in part, without penalty. Carbon must pay down borrowings under the 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.

 

 

Note 6 – Bank Credit Facility (continued)

 

As required under the terms of the Credit Facility, the Company has agreed to establish pricing for a certain percentage of its production through the use of derivative contracts. To that end, the Company has entered into an ISDA Master Agreement with BP Energy Company that establishes standard terms for the derivative contracts and an inter-creditor agreement with LegacyTexas Bank and BP Energy Company whereby any credit exposure related to the derivative contracts entered into by the Company and BP Energy Company is secured by the collateral and backed by the guarantees supporting the Credit Facility.

 

Initial borrowings under the Credit Facility were used (i) to pay off and terminate Nytis LLC’s existing credit facility with Bank of Oklahoma, (ii) to pay the purchase price of the EXCO Acquisition, (iii) to pay costs and expenses associated with the EXCO Acquisition and (iv) to provide working capital for the Company.

 

Note 7 – Income Taxes

 

The Company recognizes 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. The Company has 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, 2016, the Company has established a full valuation allowance against the balance of net deferred tax assets.

 

Note 8 – Stockholders’ Equity

 

Authorized and Issued Capital Stock

 

As of September 30, 2016, the Company had 200,000,000 shares of common stock authorized with a par value of $0.01 per share, of which 110,638,849 were issued and outstanding. The Company also had 1,000,000 shares of preferred stock authorized with a par value of $0.01 per share, none of which were issued and outstanding. During the first nine months of 2016, the increase in the Company’s issued and outstanding common stock was a result of the vesting of restricted stock and performance units during the period.

 

Equity Plans Prior to Merger

 

Pursuant to the merger of Nytis USA with and into the Company in 2011, all options, warrants and restricted stock were adjusted to reflect the conversion ratio used in the merger. As of September 30, 2016, the Company has 250,000 warrants outstanding and exercisable and approximately 490,000 shares of common stock outstanding that are subject to restricted stock agreements.

 

Nytis USA Restricted Stock Plan

 

As of September 30, 2016, there were approximately 489,000 shares of unvested restricted stock granted under the Nytis USA Restricted Stock Plan (“Nytis USA Plan”). The Company accounted for these grants at their intrinsic value. From the dates of grant through March 31, 2013, the Company estimated that none of these shares would vest and accordingly, no compensation cost had been recorded through March 31, 2013.

 

In June 2013, the vesting terms of these restricted stock grants were modified so that 25% of the shares would vest on the first of January from 2014 through 2017. As such, the Company is recognizing compensation expense for these restricted stock grants based on the fair value of the shares on the date the vesting terms were modified. Compensation costs recognized for these restricted stock grants were approximately $84,000 for the three months ended September 30, 2016 and 2015 and approximately $252,000 for the nine months ended September 30, 2016 and 2015. As of September 30, 2016, there was approximately $84,000 of unrecognized compensation costs related to these restricted stock grants which the Company expects will be recognized ratably over the next three months.

  

 

Note 8 – Stockholders’ Equity (continued)

 

Carbon Stock Incentive Plans

 

The Company has two stock plans, the Carbon 2011 and 2015 Stock Incentive Plans (collectively the “Carbon Plans”). The Carbon Plans were approved by the shareholders of the Company and in the aggregate provide for the issuance of 22.6 million shares of common stock to Carbon’s officers, directors, employees or consultants eligible to receive these awards under the Carbon Plans.

 

The Carbon Plans provide for granting Director Stock Awards to non-employee directors and for granting Incentive Stock Options, Non-qualified Stock Options, Restricted Stock Awards, Performance Awards and Phantom Stock Awards, or a combination of the foregoing as is best suited to the circumstances of the particular employee, officer or consultant.

 

Restricted Stock

 

During the nine months ended September 30, 2016, approximately 2.5 million shares of restricted stock were granted under the terms of the Carbon Plans in addition to approximately 6.6 million shares granted during previous years. For employees, these restricted stock awards either vest ratably over a three-year service period or cliff vest after a three year service period. For non-employee directors, the awards vest upon the earlier of a change in control of the Company or the date their membership on the Board of Directors is terminated other than for cause. The Company recognizes 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). As of September 30, 2016, approximately 3.9 million of these restricted stock grants have vested and approximately 5.2 million shares are unvested.

 

Compensation costs recognized for these restricted stock grants were approximately $186,000 and $201,000 for the three months ended September 30, 2016 and 2015, respectively, and approximately $554,000 and $560,000 for the nine months ended September 30, 2016 and 2015, respectively. As of September 30, 2016, there was approximately $1.4 million of unrecognized compensation costs related to these restricted stock grants. This cost is expected to be recognized over the next 6.8 years.

 

Restricted Performance Units

 

During the nine months ended September 30, 2016, 1.6 million shares of performance units were granted under the terms of the Carbon Plans in addition to approximately 6.4 million shares granted during previous years. The performance units represent a contractual right to receive one share of the Company’s 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 for the Company as well as the lapse of forfeiture restrictions pursuant to the terms and conditions of the agreements, including for certain of the grants, the requirement of continuous employment by the grantee prior to a change in control of the Company. Based on the relative achievement of performance, approximately 6.0 million restricted performance units are outstanding as of September 30, 2016.

 

The Company accounts for the performance units granted during 2012 and 2014 through 2016 at their fair value determined at the date of grant. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At September 30, 2016, the Company estimated that none of the performance units granted in 2012 and 2016 would vest due to change in control and other performance provisions and accordingly, no compensation cost has been recorded for these performance units. At September 30, 2016, the Company estimated that it was probable that certain of the performance units granted in 2014 and 2015 would vest and compensation costs of approximately $1.1 million related to these performance units were recognized for the three months ended September 30, 2016. As of September 30, 2016, if change in control provisions pursuant to the terms and conditions of the agreements are met in full, the estimated unrecognized compensation cost related to the performance units granted in 2012 and 2014 through 2016 would be approximately $2.6 million.

 

 

Note 8 – Stockholders’ Equity (continued)

 

The performance units granted in 2013 contain specific vesting provisions, no change in control provisions nor any performance conditions other than stock price performance. Due to different vesting requirements compared to the performance units granted in 2012 and 2014 through 2016, the Company recognizes compensation expense for the performance units granted in 2013 based on the grant date fair value of the performance units, amortized ratably over three years (the performance period). The fair value of the performance units granted in 2013 was estimated using a Monte Carlo simulation (“MCS”) valuation model using the following key assumptions: no expected dividends, volatility of our stock and those of defined peer companies used to determine our performance relative to the defined peer group, a risk free interest rate and an expected life of three years. Compensation costs recognized for these performance unit grants were nil and approximately $86,000 for the three months ended September 30, 2016 and 2015, respectively, and approximately $127,000 and $259,000 for the nine months ended September 30, 2016 and 2015, respectively. As of September 30, 2016, compensation costs related to performance units granted in 2013 have been fully recognized.

 

Note 9 – Accounts Payable and Accrued Liabilities

 

Accounts payable and accrued liabilities at September 30, 2016 and December 31, 2015 consist of the following:

 

		September 30,				December 31,
(in thousands)		2016				2015
Accounts payable		$	1,673			$	577
Oil and gas revenue payable to oil and gas property owners			1,045				1,221
Production taxes payable			69				59
Drilling advances received from joint venture partner			1,477				2,115
Accrued drilling costs			112				112
Accrued lease operating costs			61				76
Accrued ad valorem taxes			536				496
Accrued general and administrative expenses			779				833
Other accrued liabilities			291				132
Total accounts payable and accrued liabilities		$	6,043			$	5,621

 

Note 10 – 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 based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability based on the best information available under 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. The Company’s policy is to recognize transfers in and/or out of the fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed below for all periods presented.

 

 

Note 10 – Fair Value Measurements (continued)

 

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2016 and December 31, 2015 by level within the fair value hierarchy:

 

		Fair Value Measurements Using
(in thousands)		Level 1				Level 2				Level 3				Total
September 30, 2016
Liabilities:
Commodity derivatives		$	-			$	264			$	-			$	264
December 31, 2015
Assets:
Commodity derivatives		$	-			$	559			$	-			$	559

 

On September 30, 2016, the Company terminated its credit facility with the Bank of Oklahoma. In connection with the termination of the credit facility, the Company closed all of its open commodity derivative financial instruments in which Bank of Oklahoma was its counterparty and paid the amounts due Bank of Oklahoma subsequent to September 30, 2016. The fair values of these agreements are determined under an income valuation technique. The valuation models require a variety of inputs, including contractual terms, published forward prices, volatilities for options, and discount rates, as appropriate. The Company’s estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, the Company’s credit worthiness and the time value of money. The consideration of these factors resulted in an estimated exit-price for each derivative asset or liability under a market place participant’s view. All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s derivative instruments are included within the Level 2 fair value hierarchy.

 

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

 

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

 

The Company uses 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, 2016 and 2015, the Company recorded asset retirement obligations for additions of approximately $5,000 and nil, respectively. See Note 3 for additional information.

 

Note 11 – Physical Delivery Contracts and Commodity Derivatives

 

The Company has historically used commodity-based derivative contracts to manage commodity price exposure on certain of its oil and natural gas production. The Company does not hold or issue derivative financial instruments for speculative or trading purposes. The Company also enters into, on occasion, oil and natural gas physical delivery contracts to effectively provide price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives and therefore these contracts are not recorded at fair value in the unaudited Consolidated Financial Statements. At September 30, 2016, these physical oil and gas sales contracts provide for sale prices that approximate regional market index prices.

 

 

Note 11 – Physical Delivery Contracts and Commodity Derivatives (continued)

 

In connection with the closing of the EXCO Acquisition and entering into the Credit Facility with LegacyTexas Bank (see Note 14 - Subsequent Events for additional information), the Company has entered into swap derivative agreements to hedge certain of its oil and natural gas production for 2016 through 2019. As of November 10, 2016, these derivative agreements consisted of the following:

 

		Natural Gas								Oil
Year		MMBtu				Weighted Average Price (a)				Bbl				Weighted Average Price (b)
Oct – Dec 2016			930,000			$	3.20				12,000			$	50.73
2017			3,360,000			$	3.30				48,000			$	52.83
2018			3,120,000			$	3.01				36,000			$	54.25
2019			1,320,000			$	2.85				24,000			$	54.85

 

(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.

 

For its swap instruments, the Company receives a fixed price for the hedged commodity and pays 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.

 

The following table summarizes the fair value of the derivatives recorded in the Consolidated Balance Sheets. These derivative instruments are not designated as cash flow hedging instruments for accounting purposes:

 

(in thousands)		September 30, 2016				December 31, 2015
Commodity derivative contracts:
Current assets		$	-			$	408
Non-current assets		$	-			$	151
Current liabilities		$	264			$	-

 

The table below summarizes the realized (settled) and unrealized gains and losses related to the Company’s derivative instruments for the three and nine months ended September 30, 2016 and 2015. These realized and unrealized gains or losses are recorded and included in commodity derivative gain or loss in the accompanying unaudited Consolidated Statements of Operations.

 

		Three Months Ended September 30,								Nine Months Ended September 30,
(in thousands)		2016				2015				2016				2015
Commodity derivative contracts:
Realized gains		$	17			$	368			$	349			$	1,279
Unrealized gains (losses)			143				(15	)			(823	)			(779	)
Total realized and unrealized gains (losses), net		$	160			$	353			$	(474	)		$	500

 

Realized gains and losses from commodity derivative contracts are included in cash flows from operating activities in the Company’s unaudited Consolidated Statements of Cash Flows.

 

 

Note 11 – Physical Delivery Contracts and Commodity Derivatives (continued)

 

Prior to the termination of the credit facility on September 30, 2016, Bank of Oklahoma was the counterparty to all of the Company’s derivative instruments. Accordingly, the Company was not required to post collateral since the bank was secured by the Company’s oil and gas assets. The Company nets its derivative instrument fair value amounts executed with its counterparty pursuant to an ISDA master agreement, which provides for the net settlement over the term of the contract and in the event of default or termination of the contract. The following table summarizes the location and fair value amounts of all derivative instruments in the Consolidated Balance Sheet as of September 30, 2016, as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited Consolidated Balance Sheet:

 

										Net
		Gross								Recognized
		Recognized				Gross				Fair Value
Balance Sheet Classification		Assets/				Amounts				Assets/
(in thousands)		Liabilities				Offset				Liabilities
Commodity derivative assets:
Current derivative assets		$	41			$	(41	)		$	-
Total derivative assets		$	41			$	(41	)		$	-
Commodity derivative liabilities:
Current derivative liabilities			305				(41	)			264
Total derivative liabilities		$	305			$	(41	)		$	264

 

Due to the volatility of oil and natural gas prices, the estimated fair value of the Company’s commodity derivatives are subject to large fluctuations from period to period.

 

Note 12 – Commitments

 

The Company has entered into long-term firm transportation contracts to ensure the transport for certain of its gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts at September 30, 2016 are summarized in the table below.

 

Period		Dekatherms per day				Demand Charges
Oct 2016 - Apr 2018			4,450				$0.20 - $0.65
May 2018 - May 2020			2,150			$	0.20
Jun 2020 - May 2036			1,000			$	0.20

 

A liability of approximately $524,000 related to firm transportation contracts assumed in a 2011 asset acquisition, which represents the remaining commitment, is reflected on the Company’s unaudited Consolidated Balance Sheet as of September 30, 2016. The fair value of these firm transportation obligations were determined based upon the contractual obligations assumed by the Company and discounted based upon the Company’s effective borrowing rate. These contractual obligations are being amortized on a monthly basis as the Company pays these firm transportation obligations in the future.

 

 

Note 13 – Supplemental Cash Flow Disclosure

 

Supplemental cash flow disclosures for the nine months ended September 30, 2016 and 2015 are presented below:

 

		Nine Months Ended September 30,
(in thousands)		2016				2015
Cash paid during the period for:
Interest payments		$	117			$	121
Income taxes		$	-			$	325
Non-cash transactions:
Increase in net asset retirement obligations		$	5			$	-
Decrease in accounts payable and accrued liabilities
included in oil  and gas properties		$	(23	)		$	(225	)

 

Note 14 – Subsequent Events

 

On October 3, 2016, Nytis LLC closed the EXCO Acquisition consisting of producing natural gas wells and natural gas gathering facilities located in the Appalachian Basin. The acquisition was pursuant to a purchase and sale agreement (the “EXCO Purchase Agreement”), effective October 1, 2016 by and among EXCO Production Company (WV), LLC, BG Production Company (WV), LLC and EXCO Resources (PA) LLC (collectively, the “Sellers”) and Nytis LLC, as the buyer. The acquired assets will significantly increase the natural gas production of the Company and will position the Company to generate additional shareholder value through increased cash flow, significantly reduced general and administrative expenses (per unit of production) and a broad inventory of value enhancing development projects, along with increased financial and operational flexibility. The purchase price of the acquired assets pursuant to the EXCO Purchase Agreement was $9 million, subject to normal and customary closing and post-closing adjustments.

 

The Acquisition is comprised of 2,334 natural gas wells which are currently producing approximately 9,300 net Mcfe of gas per day (95% natural gas) and have an average working interest and average net revenue interest of 95% and 79%, respectively. Also included are over 900 miles of natural gas gathering pipelines and associated compression facilities. Nytis LLC will operate the wells and gathering systems.

 

In connection with and concurrently with the closing of the EXCO Acquisition, the Company entered into a four year $100.0 million senior secured asset-based revolving Credit Facility with LegacyTexas Bank. Borrowings under the Credit Facility were used (i) to pay off and terminate Nytis LLC’s exiting credit facility with Bank of Oklahoma, (ii) to pay the purchase price for the EXCO Acquisition, (iii) to pay costs and expenses associated with the EXCO Acquisition and the Credit Facility and (iv) to provide working capital for the Company. See Note 6 – Bank Credit Facility for additional information.

 

As of the date of filing this quarterly report, the Company did not have information available to present pro forma financials and will present at a later date.

 

 

ITEM 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

General Overview

 

All expectations, forecasts, assumptions and beliefs about our future results, condition, operations and performance are forward-looking statements as described under the heading “Forward Looking Statements” at the end of this Item. Our actual results may differ materially because of a number of risks and uncertainties. The following discussion and analysis should be read in conjunction with the Company’s Consolidated Financial Statements and Notes thereto and the information included or incorporated by reference in the Company’s 2015 Annual Report on Form 10-K as filed with the Securities and Exchange Commission (“SEC”) under the headings “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

Carbon is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil and natural gas properties located in the Appalachian and Illinois Basins of the United States. We focus on conventional and unconventional reservoirs, including shale, tight sands and coalbed methane. Our executive offices are located in Denver, Colorado and we maintain an office in Lexington, Kentucky from which we conduct our oil and natural gas operations.

 

At September 30, 2016, our proved developed reserves were comprised of 10% oil and 90% natural gas. Our current capital expenditure program is focused on the development of our oil and coalbed methane reserves. We believe that our drilling inventory and lease position, combined with our low operating expense and cost structure, provides us with a portfolio of opportunities for the development of our oil and natural gas properties. Our operating plan is centered on the following activities:

 

	●	Development and maintenance of a portfolio of low risk, long-lived oil and natural gas properties that provide stable cash flows and attractive risk adjusted rates of return; and

●

Producing property and land acquisitions which provide attractive risk adjusted rates of return and which can complement our existing asset base.

 

The following table highlights the quarterly average NYMEX oil and natural gas prices for the last eight calendar quarters:

  

		2014				2015																2016
		Q4				Q1				Q2				Q3				Q4				Q1				Q2				Q3
Oil (Bbl)		$	73.12			$	48.57			$	57.96			$	46.44			$	42.17			$	33.51			$	45.60			$	44.94
Natural Gas (MMBtu)		$	4.04			$	2.99			$	2.61			$	2.74			$	2.17			$	2.06			$	1.98			$	2.93

 

Oil prices have fallen since reaching highs of over $105.00 per barrel in 2014 and dropped below $23.00 per barrel in February 2016. Natural gas prices have also declined from over $4.80 per Mcf in 2014 to below $1.70 per Mcf in March 2016. Although oil and natural gas prices have begun to recover from the lows experienced during the first quarter of 2016, forecasted prices for both oil and natural gas remain low. Lower oil and natural gas prices may not only decrease the Company’s revenues, but may also reduce the amount of oil and natural gas that can be produced economically and potentially lower our oil and natural gas reserves. A substantial or extended decline in oil or natural gas prices may result in future impairments of our proved reserves and may materially and adversely affect our future business, financial condition, cash flows, results of operations or liquidity.

 

The Company uses the full cost method of accounting for oil and gas properties and performs a ceiling test quarterly. Because the ceiling calculation requires a rolling 12-month average commodity price, the effect of lower prices in 2015 and 2016 caused the Company to recognize ceiling test impairments of approximately $5.4 million and approximately $4.3 million for the nine months ended September 30, 2015 and 2016, respectively.

 

 

Impairment charges do not affect cash flows from operating activities, but do adversely affect net income and stockholders’ equity. If commodity prices continue to stay low, this may impact the ceiling test value until such time as commodity prices improve. In addition, extended depressed oil and natural gas prices may materially and adversely affect our future business, financial condition, cash flows and liquidity. Low oil and natural gas prices may also reduce the amount of borrowing base under our bank credit facility, which is determined at the discretion of our lender.

 

Future 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 future acquisitions by selling non-strategic properties or through issuance of additional equity or debt.

 

Operational Highlights

 

At September 30, 2016, we had over 266,000 net acres of mineral leases located in the Appalachian and Illinois Basins of the United States. Approximately 51% of this acreage is held by production and, of the remaining acreage, approximately 51% have lease terms of greater than five years remaining in the primary term or contractual extension periods.

 

The principal focus of our leasing, drilling and completion activities is directed at a Berea Sandstone Formation horizontal oil drilling program in eastern Kentucky and western West Virginia. At September 30, 2016, we have over 41,000 net mineral acres in the development area. Since 2010, we have drilled 54 gross horizontal wells in the drilling program. During the program, we have enhanced our well performance, improved well drilling and completion performance, including reduced drilling days, increased horizontal lateral length, decreased cost per frac stage and reduced days from spud to first production. In addition, we have established an infrastructure of oil and natural gas gathering and salt water handling and disposal facilities which will benefit the economics of future drilling. We continue to acquire leases and producing properties in the areas where we have identified additional potential to expand our activities.

 

Another area of focus of our drilling and completion activities is the development of a coalbed methane resource located in the Illinois Basin. The Company has approximately 63,000 net mineral acres in Indiana and Illinois which are prospective for the development of coalbed methane. The Company also owns interests in natural gas gathering compression and salt water disposal facilities. Since 2006, we have conducted a drilling program in the Seelyville Coal formation, including participating as a 50% joint venture partner in the drilling of 36 vertical and two horizontal wells. During 2015, the Company participated in the drilling of 25 stratigraphic wells to identify potential future horizontal locations in the Seelyville coal formation.

 

Our natural gas properties are largely held by production and contain a low risk multi-year development inventory of locations which, at the appropriate level of natural gas commodity price, will provide significant drilling and completion opportunities from multiple proven producing formations.

 

Recent Developments

 

On October 3, 2016, Nytis LLC completed an acquisition (the “EXCO Acquisition”) of producing natural gas wells and natural gas gathering facilities located in the Company’s Appalachian Basin operating area. The acquisition was pursuant to a purchase and sale agreement, effective as of October 1, 2016 (the “EXCO Purchase Agreement”), by and among EXCO Production Company (WV), LLC, BG Production Company (WV), LLC and EXCO Resources (PA) LLC (collectively, the “Sellers”) and Nytis LLC, as the buyer. The purchase price of the acquired assets pursuant to the EXCO Purchase Agreement was $9 million, subject to normal and customary closing and post-closing adjustments.

 

The acquired assets will significantly increase the natural gas production of the Company and will position the Company to generate additional shareholder value through increased cash flow, significantly reduced general and administrative expenses (per unit of production) and a broad inventory of value enhancing development projects, along with increased financial and operational flexibility. The acquired assets consist of the following:

 

●

Approximately 2,300 natural gas wells which are currently producing approximately 9,300 net Mcfe per day (95% natural gas), which the Company will operate.

 

 

	●	The average working interest and average net revenue interest of the acquired wells is 95% and 79%, respectively.

	●	Estimated proved developed producing reserves of approximately 37.7 Bcfe (98% natural gas).

	●	Over 900 miles of natural gas gathering pipelines and associated compression facilities which the Company will operate.

●

Approximately 216,000 net acres of oil and natural gas mineral interests.

 

As a result of the EXCO Acquisition, Carbon will have the following attributes:

 

	●	Concentrated southern Appalachian Basin natural gas properties which offer meaningful growth potential through recompletions and optimization of gathering and compression facilities, an extensive inventory of low risk development drilling projects and a number of identified additional acquisition opportunities.

	●	Average net daily production of approximately 15,300 Mcfe (90% natural gas).

	●	Approximately 487,000 net acres of oil and gas mineral interests of which approximately 70% are held by production.

	●	Interests in over 3,200 wells of which 86% are operated by Carbon.

	●	Average working interest and average net revenue interest of 91% and 77%, respectively.

	●	High heating content natural gas.

●

A multi-year hedge strategy which the Company believes will provide protection against commodity price volatility.

 

In connection with and concurrently with the closing of the EXCO Acquisition, Carbon entered into a 4-year $100.0 million senior secured asset-based revolving credit facility (the “Credit Facility”) with LegacyTexas Bank. Borrowings under the Credit Facility were used (i) to pay off and terminate Nytis LLC’s existing credit facility with Bank of Oklahoma, (ii) to pay the purchase price of the EXCO Acquisition, (iii) to pay costs and expenses associated with the acquisition and the Credit Facility and (iv) to provide working capital for the Company. The initial borrowing base established under the Credit Facility is $17.0 million.

 

 

Results of Operations

 

Three Months Ended September 30, 2016 Compared to Three Months Ended September 30, 2015

 

The following discussion and analysis relates to items that have affected our results of operations for the three months ended September 30, 2016 and 2015. The following table sets forth, for the periods presented, selected historical statements of operations data. The information contained in the table below should be read in conjunction with the Company’s Consolidated Financial Statements and Notes thereto and the information under “Forward Looking Statements” below.

 

		Three Months Ended
		September  30,								Percent
(in thousands except production and per unit data)		2016				2015				Change
Revenue:
Natural gas sales		$	1,431			$	1,567				(9	)%
Oil sales			765				1,104				(31	)%
Commodity derivative income			160				353				(55	)%
Other income			9				53				(83	)%
Total revenues			2,365				3,077				(23	)%
Expenses:
Lease operating expenses			622				717				(13	)%
Transportation costs			364				496				(27	)%
Production and property taxes			184				334				(45	)%
General and administrative			2,327				1,830				27	%
Depreciation, depletion and amortization			393				611				(36	)%
Accretion of asset retirement obligations			35				32				9	%
Total expenses			3,925				4,020				(2	)%
Operating loss		$	(1,560	)		$	(943	)			65	%
Other income and (expense):
Interest expense			(38	)			(52	)			(27	)%
Equity investment (loss) income			(4	)			7				*
Other income			-				21				*
Total other expense		$	(42	)		$	(24	)			75	%
Production data:
Natural gas (Mcf)			507,608				526,085				(4	)%
Oil (Bbl)			17,626				22,631				(22	)%
Combined (Mcfe)			613,364				661,871				(7	)%
Average prices before effects of hedges:
Natural gas (per Mcf)		$	2.82			$	2.98				(5	)%
Oil (per Bbl)		$	43.40			$	48.78				(11	)%
Combined (per Mcfe)		$	3.58			$	4.04				(11	)%
Average prices after effects of hedges**:
Natural gas (per Mcf)		$	3.08			$	3.33				(8	)%
Oil (per Bbl)		$	44.99			$	56.20				(20	)%
Combined (per Mcfe)		$	3.84			$	4.57				(16	)%
Average costs (per Mcfe):
Lease operating expenses		$	1.01			$	1.08				(6	)%
Transportation costs		$	0.59			$	0.75				(21	)%
Production and property taxes		$	0.30			$	0.50				(40	)%
Depreciation, depletion and amortization		$	0.64			$	0.92				(30	)%

 

*	Not meaningful or applicable

**	Includes realized and unrealized commodity derivative gains and losses.

 

 

Oil and natural gas revenues- Revenues from sales of oil and natural gas decreased 18% to approximately $2.2 million for the three months ended September 30, 2016 from approximately $2.7 million for the three months ended September 30, 2015. This decrease was primarily due to an 11% and 5% decrease in oil and natural gas prices, respectively, and a 22% decrease in oil sales volumes. The decline in oil sales was primarily attributed to normal natural production declines.

 

Commodity derivative revenue- 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 when our management believes that available futures prices for our oil and natural gas production are sufficient to warrant hedging to ensure predictable cash flows for certain of the Company’s production. Because we do not designate these derivatives as cash flow hedges, they do not receive hedge accounting treatment and all mark-to-market gains or losses, as well as realized (settlement) gains or losses on the derivative instruments, are currently recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these contracts as oil and natural gas futures prices fluctuate relative to the fixed price we will receive from these contracts. For the three months ended September 30, 2016 and 2015, we had hedging gains of approximately $160,000 and $353,000, respectively.

 

On September 30, 2016, the Company terminated its credit facility with Bank of Oklahoma. In connection with the termination of the credit facility, the Company closed all of its open commodity derivative instruments in which Bank of Oklahoma was the counterparty.

 

Lease operating expenses- Lease operating expenses for the three months ended September 30, 2016 decreased 13% compared to the three months ended September 30, 2015. The decrease was primarily attributed to cost reduction initiatives and to lower water hauling and salt water disposal fees as a result of lower oil production. On a per Mcfe basis, lease operating expenses decreased from $1.08 per Mcfe for the three months ended September 30, 2015 to $1.01 per Mcfe for the three months ended September 30, 2016.

 

Transportation costs- Transportation costs for the three months ended September 30, 2016 decreased 27% compared to the three months ended September 30, 2015. The decrease is primarily attributed to the expiration of a higher priced firm transportation contract that expired in the fourth quarter of 2015.

 

Production and property taxes- Production and property taxes decreased from approximately $334,000 for the three months ended September 30, 2015 to approximately $184,000 for the three months ended September 30, 2016. This decrease is primarily attributed to a decrease in oil and natural gas sales. In addition, during the third quarter of 2015, the Company established a reserve for potential additional production taxes on certain of its wells in Kentucky due to a court ruling.

 

Production taxes averaged approximately 4.0% of oil and natural gas sales for the three months ended September 30, 2016 and 2015. Ad valorem tax rates, which can fluctuate by year, are determined by individual counties where the Company has production and are assessed on the Company’s sales one or two years in arrears depending on the location of the production.

 

Depreciation, depletion and amortization (DD&A)- DD&A decreased from approximately $611,000 for the three months ended September 30, 2015 to approximately $394,000 for the three months ended September 30, 2016 primarily due to a decrease in the Company’s depletion rate. The decrease in the depletion rate is primarily attributed to a reduction in the depletable asset base caused by impairment charges recognized in the fourth quarter of 2015 and the first six months of 2016. On a per Mcfe basis, these expenses decreased from $0.92 per Mcfe for the three months ended September 30, 2015 to $0.64 per Mcfe for the three months ended September 30, 2016.

 

General and administrative expenses- Cash based general and administrative expenses decreased from approximately $1.5 million for the three months ended September 30, 2015 to approximately $954,000 for the three months ended September 30, 2016 primarily due to decreases in personnel related costs attributed to reduction measures implemented by the Company during 2016 as a response to low commodity prices partially offset by costs associated with the EXCO Acquisition and other potential acquisition opportunities. Non-cash stock based compensation increased from approximately $371,000 for the three months ended September 30, 2015 to approximately $1.4 million for the three months ended September 30, 2016. At September 30, 2016, the Company estimated that it was probable that certain of the performance units granted in 2014 and 2015 would vest and compensation costs of approximately $1.1 million related to these performance units were recognized for the three months ended September 30, 2016. Non-cash stock based compensation and other general and administrative expenses for the three months ended September 30, 2016 and 2015 are summarized in the following table:

 

										Increase
		2016				2015				(Decrease)
(in thousands)
Stock-based compensation		$	1,373			$	371			$	1,002
Other general and administrative expenses			954				1,459				(505	)
General and administrative expense, net		$	2,327			$	1,830			$	497

 

Interest expense- Interest expense decreased from approximately $52,000 for the three months ended September 30, 2015 to approximately $38,000 for the three months ended September 30, 2016. This decrease is primarily attributed to lower credit facility commitment fees as a result of the Company’s lender under its former credit facility reducing the Company’s borrowing base in May 2016.

 

 

Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015

 

The following discussion and analysis relates to items that have affected our results of operations for the nine months ended September 30, 2016 and 2015. The following table sets forth, for the periods presented, selected historical statements of operations data. The information contained in the table below should be read in conjunction with the Company’s Consolidated Financial Statements and Notes thereto and the information under “Forward Looking Statements” below.

 

		Nine Months Ended
		September  30,								Percent
(in thousands except production and per unit data)		2016				2015				Change
Revenue:
Natural gas sales		$	3,484			$	4,453				(22	)%
Oil sales			2,201				4,187				(47	)%
Commodity derivative (loss) income			(474	)			500				*
Other income			10				71				(86	)%
Total revenues			5,221				9,211				(43	)%
Expenses:
Lease operating expenses			1,864				2,330				(20	)%
Transportation costs			1,121				1,251				(10	)%
Production and property taxes			443				763				(42	)%
General and administrative			5,402				5,496				(2	)%
Depreciation, depletion and amortization			1,332				1,952				(32	)%
Accretion of asset retirement obligations			105				95				11	%
Impairment of oil and gas properties			4,299				-				*
Total expenses			14,566				11,887				22	%
Operating loss		$	(9,345	)		$	(2,676	)			249	%
Other income and (expense):
Interest expense			(141	)			(149	)			(5	)%
Equity investment (loss) income			(10	)			6				*
Other expense			17				(15	)			*
Total other expense		$	(134	)		$	(158	)			(15	)%
Production data:
Natural gas (Mcf)			1,502,505				1,497,097				-
Oil (Bbl)			55,530				79,443				(30	)%
Combined (Mcfe)			1,835,685				1,973,755				(7	)%
Average prices before effects of hedges:
Natural gas (per Mcf)		$	2.32			$	2.97				(22	)%
Oil (per Bbl)		$	39.63			$	52.70				(25	)%
Combined (per Mcfe)		$	3.10			$	4.38				(29	)%
Average prices after effects of hedges**:
Natural gas (per Mcf)		$	2.08			$	3.19				(35	)%
Oil (per Bbl)		$	37.59			$	54.99				(32	)%
Combined (per Mcfe)		$	2.84			$	4.63				(39	)%
Average costs (per Mcfe):
Lease operating expenses		$	1.02			$	1.18				(14	)%
Transportation costs		$	0.61			$	0.63				(3	)%
Production and property taxes		$	0.24			$	0.39				(38	)%
Depreciation, depletion and amortization		$	0.73			$	0.99				(26	)%

 

*	Not meaningful or applicable

**	Includes realized and unrealized commodity derivative gains and losses.

 

 

Oil and natural gas revenues- Revenues from sales of oil and natural gas decreased 34% to approximately $5.7 million for the nine months ended September 30, 2016 from approximately $8.6 million for the nine months ended September 30, 2015. This decrease was primarily due to a 25% and a 22% decrease in oil and natural gas prices, respectively, and a 30% decrease in oil sales volumes. The decline in oil sales volumes was primarily attributed to normal natural production declines.

 

Commodity derivative revenue- 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 when our management believes that available futures prices for our oil and natural gas production are sufficient to warrant hedging to ensure predictable cash flows for certain of the Company’s production. Because we do not designate these derivatives as cash flow hedges, they do not receive hedge accounting treatment and all mark-to-market gains or losses, as well as realized gains or losses on the derivative instruments, are currently recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these contracts as oil and natural gas futures prices fluctuate relative to the fixed price we will receive from these contracts. For the nine months ended September 30, 2016 we had hedging losses of approximately $474,000 compared to hedging gains of approximately $500,000 for the nine months ended September 30, 2015. 

 

On September 30, 2016, the Company terminated its credit facility with Bank of Oklahoma. In connection with the termination of the credit facility, the Company closed all of its open commodity derivative instruments in which Bank of Oklahoma was the counterparty.

 

Lease operating expenses- Lease operating expenses for the nine months ended September 30, 2016 decreased 20% compared to the first nine months of 2015. The decrease was primarily attributed to cost reduction initiatives and to lower water hauling and salt water disposal fees as a result of lower oil production. On a per Mcfe basis, lease operating expenses decreased from $1.18 per Mcfe for the nine months ended September 30, 2015 to $1.02 per Mcfe for the nine months ended September 30, 2016.

 

Transportation costs- Transportation costs for the nine months ended September 30, 2016 decreased 10% compared to the nine months ended September 30, 2015. The decrease is primarily attributed to the expiration of a higher priced firm transportation contract that expired in the fourth quarter of 2015.

 

Production and property taxes- Production and property taxes decreased from approximately $763,000 for the nine months ended September 30, 2015 to approximately $443,000 for the nine months ended September 30, 2016. This decrease is primarily attributed to a 34% decrease in oil and natural gas sales revenues. In addition, during the third quarter of 2015, the Company established a reserve for potential additional production taxes on certain of its wells in Kentucky due to a court ruling.

 

Production taxes averaged 4.1% and 4.3% of oil and natural gas sales for the nine months ended September 30, 2016 and 2015, respectively. Ad valorem tax rates, which can fluctuate by year, are determined by individual counties where the Company has production and are assessed on the Company’s oil and gas sales one or two years in arrears depending on the location of the production.

 

Depreciation, depletion and amortization (DD&A)- DD&A decreased from approximately $2.0 million for the nine months ended September 30, 2015 to approximately $1.3 million for the nine months ended September 30, 2016 primarily due to a reduction in the Company’s depletion rate. The decrease in the depletion rate is primarily attributed to a reduction in the depletable asset base caused by impairment charges recognized in the fourth quarter of 2015 and the first six months of 2016. On a per Mcfe basis, these expenses decreased from $0.99 per Mcfe for the nine months ended September 30 2015 to $0.73 per Mcfe for the nine months ended September 30, 2016.

 

Impairment of oil and gas properties- Due to low commodity prices used in the ceiling calculation based on the required trailing 12-month average at March 31, 2016 and June 30, 2016, the Company had impairment expenses of approximately $4.3 million for the nine months ended September 30, 2016. The Company did not record an impairment for the nine months ended September 30, 2015. The ceiling limitation calculation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet. Any recorded impairment is not reversible at a later date.

 

General and administrative expenses- Cash based general and administrative expenses decreased from approximately $4.4 million for the nine months ended September 30, 2015 to approximately $3.4 million for the nine months ended September 30, 2016 primarily due to decreases in personnel related costs attributed to reduction measures implemented by the Company during 2016 as a response to low commodity prices partially offset by costs associated with the EXCO Acquisition and other potential acquisition opportunities. Non-cash stock based compensation increased from approximately $1.1 million for the nine months ended September 30, 2015 to approximately $2.0 million for the nine months ended September 30, 2016. At September 30, 2016, the Company estimated that it was probable that certain of the performance units granted in 2014 and 2015 would vest and compensation costs of approximately $1.1 million related to these performance units were recognized for the third quarter ended September 30, 2016. Non-cash stock based compensation and other general and administrative expenses for the nine months ended September 30, 2016 and 2015 are summarized in the following table:

 

										Increase
		2016				2015				(Decrease)
(in thousands)
Stock-based compensation		$	2,037			$	1,071			$	966
Other general and administrative expenses			3,365				4,425				(1,060	)
General and administrative expense, net		$	5,402			$	5,496			$	(94	)

 

 

Interest expense- Interest expense decreased from approximately $149,000 for the nine months ended September 30, 2015 to approximately $140,000 for the nine months ended September 30, 2016. This decrease is primarily attributed to lower credit facility commitment fees as a result of the Company’s lender under its former credit facility reducing the Company’s borrowing base in May 2016.

 

Liquidity and Capital Resources

 

Our exploration, development, and acquisition activities require us to make operating and capital expenditures. Historically, we have used cash flow from operations and our bank credit facility as our primary sources of liquidity, and, on occasion, we have engaged in asset monetization transactions.

 

Changes in the market prices for oil and natural gas directly impact our level of cash flow generated from operations. We employ a commodity hedging strategy in an attempt to moderate the effects of commodity price fluctuations on our cash flow.

 

On September 30, 2016, the Company terminated its credit facility with Bank of Oklahoma. In connection with the termination of the credit facility, the Company closed all its open commodity derivative financial instruments in which Bank of Oklahoma was the counterparty.

 

In connection with the closing of the EXCO Acquisition and entering into the Credit Facility with LegacyTexas Bank, the Company has entered into swap derivative agreements to hedge certain of its oil and natural gas production for 2016 through 2019.

 

The following table reflects the Company’s outstanding derivative hedges as of November 10, 2016:

 

		Natural Gas								Oil
Year		MMBtu				Weighted Average Price (a)				Bbl				Weighted Average Price (b)
Oct – Dec 2016			930,000			$	3.20				12,000			$	50.73
2017			3,360,000			$	3.30				48,000			$	52.83
2018			3,120,000			$	3.01				36,000			$	54.25
2019			1,320,000			$	2.85				24,000			$	54.85

 

(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.

 

 

This level of hedging will provide a measure of certainty of the cash flow that we will receive for a portion of our production through 2019. However, future hedging activities may result in reduced income or even financial losses to us. See “Risk Factors— The use of derivative instruments used in hedging arrangements could result in financial losses or reduce income,” in our Annual Report on Form 10-K for further details of the risks associated with our hedging activities. In the future, we may determine to increase or decrease our hedging positions.

 

The primary source of liquidity historically has been our credit facility (described below). On October 3, 2016, the Company entered into a four-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank with an initial borrowing base of $17.0 million. See—“Bank Credit Facility” below for further details.

 

Our ability to access the debt and equity capital markets on economical terms is affected by general economic conditions, the domestic and global financial markets, our operational and financial performance, the value of our equity securities, prevailing commodity prices, and other macroeconomic factors outside of our control.

 

After closing the EXCO Acquisition and entering into the Credit Facility with LegacyTexas Bank, we believe that we are well positioned for the current economic environment due to our projected cash flow, access to undrawn debt capacity, our large inventory of drilling locations and acreage position and minimal capital expenditure obligations. The Company has and will continue its cost reduction initiatives especially in regard to its general and administrative and lease operating expenses.

 

Based on our current outlook of commodity prices and our estimated production for the remainder of 2016 and 2017, we expect to fund our future activities primarily with cash flow from operations, our new credit facility, sales of properties or the issuance of additional equity or debt. Such transactions, if any, will depend on general economic conditions, the domestic and global financial markets, the Company’s operational and financial performance, the value of our equity securities, prevailing commodity prices, and other macroeconomic factors outside of our control. Current market conditions may limit our ability to source attractive acquisition opportunities and to issue new debt or equity securities in the public or private markets. The ability of oil and gas companies to access the equity and high yield debt markets has been limited since the significant decline in commodity prices throughout 2015 and 2016. We expect that our net cash provided by operating activities will be adversely affected by continued low commodity prices. We believe that our expected future cash flows provided by operating activities will be sufficient to fund our normal recurring activities (other than the potential acquisition of additional oil and natural gas properties), and our contractual obligations. If low commodity prices continue, we may elect to continue to defer our planned capital expenditures. See “Risk Factors,” in our Annual Report filed on Form 10-K with the SEC for a discussion of the risks and uncertainties that affect our business and financial and operating results.

 

Bank Credit Facility

 

On September 30, 2016, the Company terminated its credit facility with Bank of Oklahoma. On October 3, 2016, in connection with and concurrently with the closing of the EXCO Acquisition, Carbon 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 $0.5 million 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 is $17.0 million.

 

The Credit Facility is guaranteed by each existing and future direct or indirect subsidiary of Carbon (subject to certain exceptions). The obligations of Carbon and the subsidiary guarantors under the Credit Facility are secured by pledges of the equity of Nytis USA held by Carbon and the equity of Nytis LLC held by Nytis USA and by essentially all tangible and intangible personal and real property of the Company (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 Carbon’s option. The actual margin percentage is dependent on the Credit Facility utilization percentage. Carbon is obligated to pay certain fees and expenses in connection with the Credit Facility, including a commitment fee for any unused amounts of 0.50% and an origination fee of 0.75%.

 

The Credit Facility contains certain affirmative and negative covenants that, among other things, limit the Company’s ability to (i) incur additional debt; (ii) incur additional liens; (iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distributions on, or repurchases of, equity; (vi) make certain investments; (vii) enter into certain transactions with its affiliates; (viii) enter into sales-leaseback transactions; (ix) make optional or voluntary payment of debt; (x) change the nature of its business; (xi) change its 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 certain basket amounts and acceptable transaction levels. In addition, the Credit Facility requires Carbon’s compliance, on a consolidated basis, with (i) a maximum funded Debt/EBITDA ratio of 3.5 to 1.0 and (ii) a minimum current ratio of 1.0 to 1.0, commencing with the quarter ended March 31, 2017.

 

Carbon may at any time repay the loans under the Credit Facility, in whole or in part, without penalty. Carbon must pay down borrowings under the 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.

 

As required under the terms of the Credit Facility, the Company has agreed to establish pricing for a certain percentage of its production through the use of derivative contracts. To that end, the Company has entered into an ISDA Master Agreement with BP Energy Company that establishes standard terms for the derivative contracts and an inter-creditor agreement with LegacyTexas Bank and BP Energy Company whereby any credit exposure related to the derivative contracts entered into by the Company and BP Energy Company is secured by the collateral and backed by the guarantees supporting the Credit Facility.

 

Initial borrowings under the Credit Facility were used (1) to pay off and terminate Nytis LLC’s existing credit facility with Bank of Oklahoma, (ii) to pay the purchase price of the EXCO Acquisition, (iii) to pay costs and expenses associated with the EXCO Acquisition and (iv) to provide working capital for the Company. As of November 10, 2016, there was approximately $13.5 million in borrowings under the Credit Facility. The Company’s effective borrowing rate as of November 10, 2016 was approximately 5.0%.

 

Historical Cash Flow

 

Net cash provided by or used in operating, investing and financing activities for the nine months ended September 30, 2016 and 2015 were as follows:

 

		Nine Months Ended
		September 30,
(in thousands)		2016				2015
Net cash (used in) provided by operating activities		$	(693	)		$	879
Net cash provided by (used in) investing activities		$	12			$	(2,121	)
Net cash provided by financing activities		$	504			$	877

 

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. Net cash provided by or used in operating activities decreased approximately $1.6 million for the nine months ended September 30, 2016 as compared to the nine months ended September 30, 2015, primarily due to a 25% and 22% decrease in oil and natural gas prices, respectively, and a 30% decrease in oil production, partially offset by lower lease operating expenses and lower cash based general and administrative expenses.

 

Net cash provided by or used in investing activities is primarily comprised of expenditures related to acquisition, exploration and development of oil and natural gas properties, net of dispositions. Net cash from investing activities increased approximately $2.1 million for the nine months ended September 30, 2016 as compared to the nine months ended September 30, 2015. Due to low oil and natural gas prices, the Company continued to scale down its drilling and development program during the first nine months of 2016, resulting in an approximate $2.3 million decrease of capital expenditures during the nine months ended September 30, 2016 as compared to the same period in 2015.

 

The decrease in financing cash flows of approximately $373,000 for the nine months ended September 30, 2016 as compared to the same period in 2015 was primarily due to a reduction in the Company’s net borrowings from its former credit facility with the Bank of Oklahoma.

 

 

Capital Expenditures

 

Capital expenditures incurred for the nine months ended September 30, 2016 and 2015 are summarized in the following table:

 

		Nine Months Ended September 30,
(in thousands)		2016				2015
Unevaluated property acquisitions		$	95			$	291
Drilling and development			192				1,746
Other			41				611
Total capital expenditures		$	328			$	2,648

 

Due to the higher rate of return on invested capital on oil wells versus natural gas wells, the Company’s capital expenditure program has, since 2012, focused principally on the development of its oil prospects. In addition, we managed our capital expenditures by keeping our exploration and development capital spending near our cash flows. We have been able to expand our oil drilling program by entering into two separate drilling programs with Liberty Energy LLC, the latter of which was entered into in 2014. Other factors impacting the level of our capital expenditures include oil and natural gas prices, the volatility in these prices, the cost and availability of oil field services, general economic and market conditions, and weather disruptions. Due to low commodity prices, the Company, since 2015, has curtailed its drilling programs and has focused on expanding its gathering facilities, thereby providing greater flexibility in moving certain of the Company’s natural gas to markets with more favorable pricing.

 

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, 2016, the off-balance sheet arrangements and transactions that we have entered into include (i) operating lease agreements and (ii) contractual obligations, such as natural gas transportation contracts, for which the ultimate settlement amounts are not fixed and determinable 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.

 

Reconciliation of Non-GAAP Measures

 

EBITDA and Adjusted EBITDA

 

“EBITDA” and “Adjusted EBITDA” are non-GAAP financial measures. We define EBITDA as net income or loss before interest expense, taxes, depreciation, depletion and amortization. We define Adjusted EBITDA as EBITDA prior to accretion of asset retirement obligations, ceiling test write downs of oil and gas properties, non-cash stock based compensation expense and the gain or loss on sold investments or properties. EBITDA and Adjusted EBITDA is consolidated including non-controlling interests and as used and defined by us, may not be comparable to similarly titled measures employed by other companies and are not measures of performance calculated in accordance with GAAP. EBITDA and Adjusted EBITDA should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by or used in operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. EBITDA and Adjusted EBITDA provide no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. EBITDA and Adjusted EBITDA do not represent funds available for discretionary use because those funds are required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration and development expenses, and other commitments and obligations. However, our management believes EBITDA and Adjusted EBITDA are useful to an investor in evaluating our operating performance because these measures:

 

●

are widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors; and

 

 

●

help investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and are used by our management for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting and by our lenders pursuant to a covenant under the Company’s credit facility.

 

There are significant limitations to using EBITDA and Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating EBITDA and Adjusted EBITDA reported by different companies.

 

The following table represents a reconciliation of our net income or loss, the most directly comparable GAAP measure to EBITDA and Adjusted EBITDA for the three and nine months ended September 30, 2016 and 2015.

 

		Three Months Ended
		September 30,
(in thousands)		2016				2015
Net loss		$	(1,602	)		$	(967	)
Adjustments:
Interest expense			38				52
Depreciation, depletion and amortization			393				611
EBITDA			(1,171	)			(304	)
Adjusted EBITDA
EBITDA			(1,171	)			(304	)
Adjustments:
Non-cash stock-based compensation			1,373				371
Accretion of asset retirement obligations			35				32
Adjusted EBITDA		$	237			$	99

 

		Nine Months Ended
		September 30,
(in thousands)		2016				2015
Net loss		$	(9,479	)		$	(2,834	)
Adjustments:
Interest expense			141				149
Depreciation, depletion and amortization			1,332				1,952
EBITDA			(8,006	)			(733	)
Adjusted EBITDA
EBITDA			(8,006	)			(733	)
Adjustments:
Non-cash stock-based compensation			2,037				1,071
Impairment of oil and gas properties			4,299				-
Accretion of asset retirement obligations			105				95
Adjusted EBITDA		$	(1,565	)		$	433

 

 

Forward Looking Statements

 

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

 

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

 

●

estimates of our oil and natural gas reserves;

 

●

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

 

●

our future financial condition and results of operations;

 

●

our future revenues, cash flows, and expenses;

 

●

our access to capital and our anticipated liquidity;

 

●

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

 

●

our outlook on oil 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.

 

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 of 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 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 or incorporated in our Annual Report filed on Form 10-K with the SEC.

 

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 Form 10-Q and attributable to the Company 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 4.

Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures

 

We have established disclosure controls and procedures to ensure that material information related to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and the Board of Directors.

 

As required by Rule 13a - 15(b) under the Securities Exchange Act of 1934 as amended (the “Exchange Act”), we have evaluated under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rules 13a - 15(e) and 15d-15(e) under the Exchange Act as of September 30, 2016. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, as appropriate, to allow such persons to make timely decisions regarding required disclosures.

 

Our principal executive officer and principal financial officer have concluded that our current disclosure controls and procedures were effective as of September 30, 2016 at the reasonable assurance level.

 

Changes in Internal Control over Financial Reporting

 

There has not been any change in our internal control over financial reporting that occurred during our quarterly period ended September 30, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

 

PART II. OTHER INFORMATION

 

ITEM 2.

Unregistered Sales of Equity Securities and Use of Proceeds

 

All sales of unregistered equity securities that occurred during the period covered by this report, and through September 30, 2016, have been previously reported on a current report on Form 8-K or in a quarterly report on Form 10-Q.

 

ITEM 6.

Exhibits

 

Exhibit No.		Description
3(i)(a)		Amended and Restated Certificate of Incorporation of Carbon Natural Gas Company incorporated by reference to exhibit 3(i) to Form 8-K for Carbon Natural Gas Company filed on May 5, 2011.
3(i)(b)		Amended and Restated Certificate of Designation with respect to Series A Convertible Preferred Stock of Carbon Natural Gas Company, incorporated by reference to exhibit 3(i) to Form 8-K for Carbon Natural Gas Company filed July 6, 2011.
3(i)(c)		Certificate of Amendment to Certificate of Incorporation of Carbon Natural Gas Company, incorporated by reference to exhibit 3(i) to Form 8-K for Carbon Natural Gas Company filed on July 19, 2011.
3(ii)		Amended and Restated Bylaws incorporated by reference to exhibit 3(i) to Form 8-K filed on May 5, 2015.
31.1*		Certification of Chief Executive Officer Pursuant to Rule 13a-15(e) / Rule 15d-15(e).
31.2*		Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) / Rule 15(e)/15d-15(e).
32.1†		Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2†		Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
101*		Interactive data files pursuant to Rule 405 of Regulation S-T.

  

*

Filed herewith

†

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

  

 

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

 

	CARBON NATURAL GAS COMPANY
	(Registrant)
Date: November 14, 2016	By:	/s/ Patrick R. McDonald
		PATRICK R. MCDONALD
		Chief Executive Officer
Date: November 14, 2016	By:	/s/ Kevin D. Struzeski
		KEVIN D. STRUZESKI
		Chief Financial Officer

 

 

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