UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

 

Washington, D.C. 20549

 

FORM 10-Q

 

x Quarterly report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarter ended September 30, 2014 or
o 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  x                      NO  o

 

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  x                     NO  o   

 

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 o	Accelerated filer o	Non-accelerated filer o	Smaller reporting company x
		(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  o                NO  x

 

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, 2014, there were 106,875,447 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	18
Item 4.	Controls and Procedures	29
Part II – OTHER INFORMATION
Item 1.	Legal Proceedings	30
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	30
Item 5.	Other Information	30
Item 6.	Exhibits	31

  

 

PART I. FINANCIAL INFORMATION

 

ITEM 1. Financial Statements

 

CARBON NATURAL GAS COMPANY

Consolidated Balance Sheets

 

		September 30,				December 31,
(in thousands)		2014				2013
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	514			$	243
Accounts receivable:
Revenue			2,779				2,551
Joint interest billings and other			498				627
Derivative asset			147				-
Prepaid expense, deposits and other current assets			159				95
Total current assets			4,097				3,516
Property and equipment (note 4):
Oil and gas properties, full cost method of accounting:
Proved, net			41,471				39,033
Unevaluated			3,439				2,235
Other property and equipment, net			252				287
			45,162				41,555
Investments in affiliates (note 5)			1,009				1,002
Other long-term assets			519				688
Total assets		$	50,787			$	46,761
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities		$	7,318			$	6,605
Firm transportation contract obligations (note 12)			512				556
Derivative liabilities			-				226
Total current liabilities			7,830				7,387
Non-current liabilities:
Derivative liability			-				100
Asset retirement obligations (note 2)			2,921				2,699
Firm transportation contract obligations (note 12)			965				1,340
Notes payable (note 6)			13,888				12,789
Total non-current liabilities			17,774				16,928
Commitments (note 12)
Stockholders’ equity:
Preferred stock, $0.01 par value; authorized 1,000,000 shares, no shares issued and outstanding at September 30, 2014 and December 31, 2013			-				-
Common stock, $0.01 par value; authorized 200,000,000 shares, 106,875,447 and 114,470,223 shares issued and outstanding at September 30, 2014 and December 31, 2013, respectively			1,069				1,145
Additional paid-in capital			52,770				55,029
Non-controlling interests			3,015				3,045
Accumulated deficit			(31,671	)			(36,773	)
Total stockholders’ equity			25,183				22,446
Total liabilities and stockholders’ equity		$	50,787			$	46,761

 

See 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)		2014				2013				2014				2013
Revenue:
Oil and gas		$	5,664			$	5,122			$	17,710			$	13,143
Commodity derivative gain (loss)			689				(265	)			(79	)			(190	)
Other income			82				92				254				325
Total revenue			6,435				4,949				17,885				13,278
Expenses:
Lease operating expenses			786				662				2,523				1,914
Transportation costs			450				400				1,341				1,162
Production and property taxes			481				369				1,350				965
General and administrative			1,698				1,266				4,617				3,760
Depreciation, depletion and amortization			815				767				2,307				2,069
Accretion of asset retirement obligations			29				36				87				103
Total expenses			4,259				3,500				12,225				9,973
Operating income			2,176				1,449				5,660				3,305
Other income and (expense):
Interest expense			(116	)			(157	)			(362	)			(470	)
Equity investment income (loss)			2				2				7				(77	)
Total other income and (expense)			(114	)			(155	)			(355	)			(547	)
Income before income taxes			2,062				1,294				5,305				2,758
Provision for income taxes			-				-				-				-
Net income before non-controlling interests			2,062				1,294				5,305				2,758
Net income (loss) attributable to non-controlling interests			49				(20	)			203				(32	)
Net income attributable to controlling interest		$	2,013			$	1,314			$	5,102			$	2,790
Net income per common share:
Basic		$	0.02			$	0.01			$	0.05			$	0.02
Diluted		$	0.02			$	0.01			$	0.04			$	0.02
Weighted average common shares outstanding:
Basic			105,683				112,513				110,196				112,468
Diluted			110,808				120,334				115,292				120,270

 

See Notes to Consolidated Financial Statements.

 

 

CARBON NATURAL GAS COMPANY

Consolidated Statements 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, 2013			114,470			$	1,145			$	55,029			$	3,045			$	(36,773	)		$	22,446
Purchase of common stock			(8,154	)			(82	)			(3,179	)			-				-				(3,261	)
Stock-based compensation			-				-				1,101				-				-				1,101
Restricted stock activity including vesting and shares exchanged for tax withholding			559				6				(181	)			-				-				(175	)
Non-controlling interests distributions, net			-				-				-				(233	)			-				(233	)
Net income			-				-				-				203				5,102				5,305
Balances, September 30, 2014			106,875			$	1,069			$	52,770			$	3,015			$	(31,671	)		$	25,183

 

See Notes to Consolidated Financial Statements.

 

 

CARBON NATURAL GAS COMPANY 

Consolidated Statements of Cash Flows

(Unaudited) 

 

		Nine Months Ended September 30,
(in thousands)		2014				2013
Cash flows from operating activities:
Net income		$	5,305			$	2,758
Items not involving cash:
Depreciation, depletion and amortization			2,307				2,069
Accretion of asset retirement obligations			87				103
Unrealized derivative (gain) loss			(477	)			14
Stock-based compensation expense			1,101				641
Equity investment (income) loss			(7	)			77
Net change in:
Accounts receivable			38				1,119
Prepaid expenses, deposits and other current assets			(64	)			(35	)
Accounts payable, accrued liabilities and firm transportation obligations			576				(2,094	)
Due from related parties			-				446
Net cash provided by operating activities			8,866				5,098
Cash flows from investing activities:
Development and acquisition of properties and equipment			(8,855	)			(6,140	)
Proceeds from disposition of assets			2,800				-
Equity method distributions			-				125
Other long-term assets			30				(35	)
Net cash used in investing activities			(6,025	)			(6,050	)
Cash flows from financing activities:
Purchase of common stock			(3,437	)			(92	)
Proceeds from notes payable			5,200				2,300
Payments on notes payable			(4,100	)			(400	)
Distributions to non-controlling interests			(233	)			(7	)
Net cash (used in) provided by financing activities			(2,570	)			1,801
Net increase in cash and cash equivalents			271				849
Cash and cash equivalents, beginning of period			243				328
Cash and cash equivalents, end of period		$	514			$	1,177

 

See Notes to Consolidated Financial Statements.

 

 

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 conduct 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 – 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, 2014, the Company’s results of operations for the three and nine months ended September 30, 2014 and 2013 and the Company’s cash flows for the nine months ended September 30, 2014 and 2013. Operating results for the three and nine months ended September 30, 2014 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 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, 2013 filed on Form 10-K with the Securities and Exchange Commission (“SEC”).

 

In the course of preparing the unaudited 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 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 46 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.

 

In accordance with established practice in the oil and gas industry, the Company’s Consolidated Financial Statements also include its pro-rata share of assets, liabilities, income and lease operating 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 Consolidated Financial Statements.

 

 

Note 2 – Summary of Significant Accounting Policies (continued)

 

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 and nine months ended September 30, 2014 and 2013, the Company did not recognize a ceiling test impairment as the Company’s full cost pool did not exceed the ceiling limitations.

 

Investments in Affiliates

 

Investments in non-consolidated affiliates are accounted for under either the 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 of a partnership or limited liability company and exercises significant influence or control, the equity method of accounting is used to account for the investment. The Company’s investment in an affiliate that is 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. For the three and nine months ended September 30, 2014 and 2013, no impairment has been recognized on the Company’s investments in affiliates.

 

  

Note 2 – Summary of Significant Accounting Policies (continued)

  

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 asset retirement obligation 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, 2014 and 2013:

 

		Nine Months Ended September 30,
(in thousands)		2014				2013
Balance at beginning of period		$	2,699			$	$2,321
Accretion expense			87				103
Additions assumed with consolidated partnerships			4				34
Additions during period			131				164
Balance at end of period		$	2,921			$	2,622

  

Earnings Per Common Share

 

Basic earnings (loss) per common share is computed by dividing the net income (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 (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).

 

For the three months ended September 30, 2014 and 2013, the diluted income per common share calculation excludes the dilutive effect of approximately 250,000 and 2.7 million common stock equivalents, respectively, that were out-of-the-money and approximately 4.7 million and 3.1 million restricted performance units, respectively, subject to future contingencies. For the nine months ended September 30, 2014 and 2013, the diluted income per common share calculation excludes the dilutive effect of approximately 250,000 and 2.9 million common stock equivalents, respectively, that were out-of-the-money and approximately 4.7 million and 3.1 million restricted performance units, respectively, subject to future contingencies.

 

 

Note 3– Acquisitions and Dispositions

 

Liberty Participation Agreement

 

On February 25, 2014, Nytis LLC entered into a participation agreement (the “Participation Agreement”) with Liberty Energy LLC (“Liberty”) that allows Liberty to participate with Nytis LLC in the drilling and completion of wells on certain of Nytis LLC’s leases located in Kentucky.

 

Pursuant to the Participation Agreement, Liberty paid Nytis LLC approximately $1.7 million. Upon receipt of this payment, Nytis LLC assigned to Liberty a 40% working interest in the covered leases. In accordance with the agreement, Liberty will pay a disproportionate percentage of the costs associated with drilling and completing 20 wells on the covered leases. In addition, pursuant to the Participation Agreement, as of September 30, 2014, Liberty purchased a 40% interest in additional acreage for approximately $1.1 million.

 

The Participation Agreement also provided for the reservation by Nytis LLC of an overriding royalty interest with respect to the covered leases, subject to an agreed upon minimum net revenue interest.

 

Following the drilling of these 20 wells, Nytis LLC and Liberty will pay their respective costs on a basis proportionate to their working interests.

 

As the transaction did not significantly alter the relationship between capitalized costs and proved reserves, the Company did not recognize a gain or loss. The proceeds from the Participation Agreement were recorded as a reduction of the Company’s investment in its unproved and proved oil and gas properties.

 

Note 4 – Property and Equipment

 

Net property and equipment as of September 30, 2014 and December 31, 2013 consists of the following:

 

(in thousands)		September 30, 2014				December 31, 2013
Oil and gas properties:
Proved oil and gas properties		$	105,400			$	100,769
Unproved properties not subject to depletion			3,439				2,235
Accumulated depreciation, depletion, amortization and impairment			(63,929	)			(61,736	)
Net oil and gas properties			44,910				41,268
Furniture and fixtures, computer hardware and software, and other equipment			1,039				960
Accumulated depreciation and amortization			(787	)			(673	)
Net other property and equipment			252				287
Total net property and equipment		$	45,162			$	41,555

 

As of September 30, 2014 and December 31, 2013, the Company had approximately $3.4 million and $2.2 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, 2014 and 2013, the Company capitalized general and administrative expenses applicable to development and exploration activities of approximately $121,000 and $113,000, respectively. During the nine months ended September 30, 2014 and 2013, the Company capitalized general and administrative expenses applicable to development and exploration activities of approximately $379,000 and $347,000, respectively.

 

 

Note 4 – Property and Equipment (continued)

 

Depletion expense related to oil and gas properties for the three and nine months ended September 30, 2014 was approximately $779,000, or $1.05 per Mcfe, and approximately $2.2 million, or $1.00 per Mcfe, respectively. For the three and nine months ended September 30, 2013, depletion expense was approximately $732,000, or $1.01 per Mcfe, and approximately $2.0 million, or $0.94 per Mcfe, respectively.

 

Depreciation and amortization expense related to furniture and fixtures, computer hardware and software and other equipment for the three and nine months ended September 30, 2014 was approximately $36,000 and $114,000, respectively, and for the three and nine months ended September 30, 2013 was approximately $35,000 and $94,000, 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. During the nine month periods ended September 30, 2014 and 2013, the Company recorded equity method income of approximately $7,000 and a loss of $77,000, respectively, related to this investment.

 

Note 6 – Bank Credit Facility

 

Nytis LLC’s credit facility with Bank of Oklahoma, which matures in May 2017, has a borrowing base of $20.0 million and a maximum line of credit available under hedging arrangements of $9.5 million. Carbon and Nytis USA are guarantors of Nytis LLC’s obligations under its credit facility.

 

No repayments of principal are required until maturity, except to the extent that outstanding balances exceed the borrowing base then in effect; however, the Company has the right both to repay principal at any time and to reborrow. Subject to the agreement between the Company and the lender, the size of the credit facility may be increased up to $50.0 million. The borrowing base is redetermined semi-annually, and the available borrowing amount could be increased or decreased as a result of such redeterminations. Under certain circumstances the lender may request an interim redetermination. The facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base. Interest rates are based on either an Alternate Base Rate or LIBOR. The portion of the loan based on an “Alternate Base Rate” is determined by the rate per annum equal to 1.5% plus the greatest of the following: (a) the Federal Funds Rate for such day plus one-half of one percentage point, (b) the Prime Rate for such day or (c) LIBOR for a one-month LIBOR Interest Period plus one percentage point. The portion based on LIBOR is determined by the rate per annum equal to LIBOR plus between 2.5% and 3.25% for each LIBOR tranche. The credit facility includes a hedging component that provides a line of credit under commodity swap, exchange, collar, cap and fixed price agreements in addition to agreements designated to protect the Company against changes in interest and currency exchange rates.

 

At September 30, 2014, there were approximately $13.9 million in outstanding borrowings and approximately $6.1 million of additional borrowing capacity available under the credit facility. The Company’s effective borrowing rate at September 30, 2014 was approximately 3.0%. The credit facility is collateralized by substantially all of the Company’s oil and gas assets. The credit facility includes terms that place limitations on certain types of activities and the payment of dividends, and requires satisfaction of a minimum current ratio (the ratio of current assets (including borrowing base capacity) to current liabilities as defined) of 1.0 to 1.0 and a maximum funded debt ratio (the ratio of the outstanding balance of all interest bearing indebtedness to the sum of EBITDAX (net income plus interest expense, income taxes, depreciation, depletion, amortization, exploration and impairment expenses and other non-cash charges) for the most recently completed fiscal quarter times four) of 4.25 to 1.0 as of the end of any fiscal quarter.

 

The Company is in compliance with all covenants associated with the credit agreement as of September 30, 2014.

 

 

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, 2014, 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, 2014, the Company had 200,000,000 shares of common stock authorized with a par value of $0.01 per share, of which 106,875,447 were issued and outstanding and 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 2014, increases in the Company’s issued and outstanding common stock reflect restricted stock, net of shares exchanged for payroll tax obligations paid by the Company, that vested during the period. In addition, pursuant to a Stock Purchase Agreement dated June 9, 2014, the Company purchased approximately 8.2 million shares of the Company’s common stock from a shareholder for a purchase price of $0.40 per share. This purchase represented 100% of the shareholder’s holdings of the Company’s common stock. These shares were canceled and returned to the Company's authorized stock and reduced the number of shares issued and outstanding.

 

Equity Plans Prior to Merger

 

Pursuant to the merger of Nytis USA with and into the Company (formerly known as St. Lawrence Seaway Corporation (“SLSC”)) in 2011, all options, warrants and restricted stock were adjusted to reflect the conversion ratio used in the merger. As of September 30, 2014, the Company has 163,076 options outstanding and exercisable, 2,696,133 warrants (including 250,000 warrants granted by SLSC prior to the merger) outstanding and exercisable and 1,468,181 shares of common stock outstanding that are subject to restricted stock agreements.

 

Nytis USA Restricted Stock Plan

 

As of September 30, 2014, there were 1,468,181 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, 2014 and 2013 and $251,000 and $84,000 respectively, for the nine months ended September 30, 2014 and 2013. As of September 30, 2014, there was approximately $755,000 of unrecognized compensation costs related to these restricted stock grants which the Company expects will be recognized ratably over the next 2.3 years.

 

Carbon Stock Incentive Plan

 

In 2011, the stockholders of Carbon approved the adoption of Carbon’s 2011 Stock Incentive Plan (“Carbon Plan”), under which 12,600,000 shares of common stock were authorized for issuance to Carbon officers, directors, employees or consultants eligible to receive awards under the Carbon Plan.

 

 

Note 8 – Stockholders’ Equity (continued)

 

The Carbon Plan provides 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, 2014, 1,600,000 shares of restricted stock were granted under the terms of the Carbon Plan in addition to 3,210,000 shares granted during previous years. For employees, these restricted stock awards vest ratably over a three-year service period and 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, 2014, approximately 1.3 million of these restricted stock grants have vested.

 

Compensation costs recognized for these restricted stock grants were approximately $220,000 and $150,000 for the three months ended September 30, 2014 and 2013, respectively and approximately $591,000 and $376,000 for the nine months ended September 30, 2014 and 2013, respectively. As of September 30, 2014, there was approximately $1.5 million of unrecognized compensation costs related to these restricted stock grants. This cost is expected to be recognized over the next 6.5 years.

 

Restricted Performance Units

 

As of September 30, 2014, 4,810,000 shares of restricted performance units have been granted under the terms of the Carbon Plan. 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 the price of the Company’s stock, net asset value per share, net production per share and Adjusted EBITDA (defined as net income (loss) before interest expense, taxes, depreciation, depletion, amortization, accretion of asset retirement obligations, ceiling test write downs of oil and gas properties and the gain or loss on sold investments or properties) per share relative to a defined peer group and 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, 4,686,160 of the restricted performance units are outstanding as of September 30, 2014.

 

The Company accounts for the performance units granted during 2012 and 2014 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, 2014, the Company estimated that none of the performance units granted in 2012 and 2014 would vest due to change in control and other performance provisions and accordingly, no compensation cost has been recorded. As of September 30, 2014, if change in control and other performance provisions pursuant to the terms and conditions of these agreements are met in full, the estimated unrecognized compensation cost related to the performance units granted in 2012 and 2014 would be approximately $2.2 million.

 

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 earning requirements compared to the performance units granted in 2012 and 2014, 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 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 approximately $86,000 and $91,000 for the three months ended September 30, 2014 and 2013, respectively, and approximately $259,000 and $182,000 for the nine months ended September 30, 2014 and 2013, respectively. As of September 30, 2014, there was approximately $559,000 of unrecognized compensation costs related to performance units granted in 2013. These costs are expected to be recognized over the next 1.5 years.

 

 

Note 9 – Accounts Payable and Accrued Liabilities

 

Accounts payable and accrued liabilities at September 30, 2014 and December 31, 2013 consist of the following:

 

		September 30,				December 31,
(in thousands)		2014				2013
Accounts payable		$	1,530			$	2,151
Oil and gas revenue payable to oil and gas property owners			686				1,307
Production taxes payable			148				165
Drilling advances received from joint venture partner			2,473				740
Accrued drilling costs			198				162
Accrued lease operating costs			58				42
Accrued ad valorem taxes			1,101				681
Accrued general and administrative expenses			902				1,146
Other accrued liabilities			222				211
Total accounts payable and accrued liabilities		$	7,318			$	6,605

 

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 developed 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 developed 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, 2014 and December 31, 2013 by level within the fair value hierarchy:

 

		Fair Value Measurements Using
(in thousands)		Level 1				Level 2				Level 3				Total
September 30, 2014
Assets:
Commodity derivatives		$	-			$	151			$	-			$	151
December 31, 2013
Liabilities:
Commodity derivatives		$	-			$	326			$	-			$	326

 

As of September 30, 2014, the Company’s commodity derivative financial instruments are comprised of ten natural gas swap agreements and five oil swap agreements. The fair values of the swap agreements are determined under the income valuation technique using a discounted cash flow model. The valuation model requires 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. The counterparty in all of the Company’s commodity derivative financial instruments is the lender in the Company’s bank credit facility.

 

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, 2014 and 2013, the Company recorded asset retirement obligations for additions of approximately $135,000 and $198,000, respectively. See Note 2 for additional information.

 

Note 11 – Physical Delivery Contracts and Commodity Derivatives

 

The Company at times enters into oil and gas physical delivery contracts to effectively provide pricing hedges. At September 30, 2014, the Company has a fixed price contract requiring physical delivery of approximately 1,000 Bbl/day at an average price of $96.70 per Bbl for October 2014 through August 2015. Because this contract is not expected to be net cash settled, it is considered to be a normal sales contract and not a derivative. Therefore, this contract is not recorded at fair value in the Consolidated Financial Statements. Other than the above mentioned contract, the Company’s other oil and gas sales contracts approximate index prices.

 

The Company has historically used commodity-based derivative contracts to manage exposure to commodity prices on certain of its oil and natural gas production. The Company does not hold or issue derivative financial instruments for speculative or trading purposes.

 

 

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

 

The Company’s swap agreements as of September 30, 2014 are summarized in the table below:

 

		Natural Gas								Oil
						Weighted								Weighted
						Average								Average
Period		MMBtu				Price (a)				Bbl				Price (b)
Oct - Dec 2014			250,000			$	4.16				12,000			$	93.79
Jan - Mar 2015			220,000			$	4.06				5,000			$	94.52
Apr - Jun 2015			170,000			$	4.04				3,000			$	94.80
Jul - Sep 2015			180,000			$	4.05				2,000			$	94.80
Oct - Dec 2015			180,000			$	4.05				-				-
Jan - Mar 2016			30,000			$	4.20				-				-
Apr - Jun 2016			10,000			$	4.20				-				-

 

(a)

NYMEX Henry Hub Natural Gas futures contract for the respective delivery month.

(b)

NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective delivery month.

 

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, 2014				December 31, 2013
Commodity derivative contracts:
Current assets		$	147			$	-
Non-current assets		$	4			$	-
Current liabilities		$	-			$	226
Non-current liabilities		$	-			$	100

 

The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the three and nine months ended September 30, 2014 and 2013. These realized and unrealized losses are recorded and included in commodity derivative gain or loss in the accompanying Consolidated Statements of Operations.

 

		Three Months Ended September 30,								Nine Months Ended September 30,
(in thousands)		2014				2013				2014				2013
Commodity derivative contracts:
Realized losses		$	(54	)		$	(79	)		$	(556	)		$	(176	)
Unrealized gains (losses)			743				(186	)			477				(14	)
Total realized and unrealized gains (losses), net		$	689			$	(265	)		$	(79	)		$	(190	)

 

Realized losses are included in cash flows from operating activities in the Company’s Consolidated Statements of Cash Flows.

 

 

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

 

The counterparty in all of the Company’s derivative instruments is the lender in the Company’s bank credit facility; accordingly, the Company is not required to post collateral since the bank is secured by the Company’s oil and natural 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, 2014, as well as the gross recognized derivative assets, liabilities and amounts offset in the Consolidated Balance Sheet:

 

										Net
		Gross								Recognized
		Recognized				Gross				Fair Value
		Assets/				Amounts				Assets/
Balance Sheet Classification (in thousands)		Liabilities				Offset				Liabilities
Commodity derivative assets:
Current derivative asset		$	215			$	(68	)		$	147
Other long-term assets			14				(10	)			4
Total derivative assets		$	229			$	(78	)		$	151
Commodity derivative liabilities:
Current derivative liability			68				(68	)			-
Non-current derivative liability			10				(10	)			-
Total derivative liabilities		$	78			$	(78	)		$	-

 

Due to the volatility of oil and natural gas prices, the estimated fair value of the Company’s 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, 2014 are summarized in the table below. 

 

Period		Dekatherms per day				Demand Charges
Oct 2014			6,450			$0.20 - $0.67
Nov 2014 - May 2015			4,450			$0.20 - $0.67
Jun 2015 - Dec 2017			3,300			$0.22 - $0.67
Jan 2018 - May 2036			1,000			$0.22

 

A liability of approximately $1.5 million related to firm transportation contracts assumed in a 2011 asset acquisition, which represents the remaining commitment, is reflected on the Company’s Consolidated Balance Sheet as of September 30, 2014. 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, 2014 and 2013 are presented below:

 

		Nine Months Ended September 30,
(in thousands)		2014				2013
Cash paid during the period for:
Interest payments		$	328			$	453
Non-cash transactions:
Increase in net asset retirement obligations		$	135			$	198
(Decrease) increase in accounts payable and accrued liabilities included in oil  and gas properties		$	(277	)		$	2,340
Receivables due from partners assumed in acquisition of partnership interests		$	2			$	10

 

Note 14 – Subsequent Event

 

On October 15, 2014, the Company, together with Liberty, (the “Sellers”) entered into a Purchase and Sale Agreement (the “PSA”) for the sale of a portion of the Company’s interest in rights below the base of the Clinton Formation (the “Deep Rights”) underlying certain oil and gas leases located in Kentucky and West Virginia (the “Leases”).

 

Pursuant to the PSA, the Sellers will reserve (i) a minority working interest in the Deep Rights, (ii) an overriding royalty interest in certain of the Deep Rights and (iii) all rights from the surface to the base of the Clinton formation underlying the Leases. In consideration of the conveyance of the Deep Rights, at closing, the Company’s share of the cash proceeds from the sale will be approximately $12 million.

 

The closing of the PSA transaction is subject to due diligence by the buyer. The PSA contains customary representations, warranties and covenants by the parties. The PSA may be terminated by the Sellers or the buyer: (i) if the downward adjustments to the Purchase Price attributable to title defects or adverse environmental conditions exceed certain thresholds; (ii) if the representations and warranties by either party fail to be materially correct at closing; or (iii) if either party fails to perform or satisfy covenants required for closing. The PSA provides for a closing date no later than 60 days from the date of the PSA.

 

 

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 2013 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, 2014, our proved developed reserves were comprised of 12% oil and 88% natural gas. Our financial results are sensitive to fluctuations in oil and natural gas prices. Our current capital expenditure program is focused on the development of our oil reserves. We believe that our drilling inventory and our 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 growth plan is centered on the following activities:

 

·

Development of the Company’s oil reserves;

·

Development of oil and natural gas projects that we believe will generate attractive risk adjusted rates of return;

·

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

·

Property and land acquisitions that complement our core producing areas.

Our revenue, profitability and future growth rate depend on many factors which are beyond our control, such as economic, political and regulatory developments and competition from other industry participants. Oil and gas prices historically have been volatile and may fluctuate widely in the future. The following table highlights the quarterly average of NYMEX price trends for oil and natural gas prices for the last eight calendar quarters:

 

		2012				2013																2014
		Q4				Q1				Q2				Q3				Q4				Q1				Q2				Q3
Oil (Bbl)		$	88.20			$	94.34			$	94.23			$	105.82			$	97.50			$	98.62			$	102.98			$	97.21
Natural Gas (MMBtu)		$	3.41			$	3.34			$	4.10			$	3.58			$	3.60			$	4.93			$	4.68			$	4.07

 

Lower oil and natural gas prices may not only decrease our revenues, but may also reduce the amount of oil and natural gas that the Company can produce economically and thus 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. Lower 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.

 

  

Operational Highlights

 

At September 30, 2014, we had over 278,000 net acres of mineral leases located in the Appalachian and Illinois Basins of the United States. Approximately 50% of this acreage is held by production and of the remaining acreage, approximately 39% have lease terms of greater than five years remaining in the primary term or contractual extension periods. For the nine months ended September 30, 2014, we participated in the drilling of 17 oil wells in the Berea Sandstone, of which 12 wells have commenced production as of the end of the period and the remaining five wells are in various stages of drilling or completion. Sixteen of the drilled wells were part of the two Liberty drilling programs, three of which were drilled on a promoted basis.

 

The principal focus of our leasing, drilling and completion activities is directed towards a Berea Sandstone horizontal oil drilling program in eastern Kentucky and western West Virginia. At September 30, 2014, we have over 40,000 net mineral acres in the region. Since 2010, we have drilled over 51 gross horizontal wells in the drilling program. During the program, we have developed expertise in the development of the reserves and 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.

 

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 15, 2014, the Company, together with Liberty, (the “Sellers”) entered into a Purchase and Sale Agreement (the “PSA”) for the sale of a portion of the Company’s interest in rights below the base of the Clinton Formation (the “Deep Rights”) underlying certain oil and gas leases located in Kentucky and West Virginia (the “Leases”).

 

Pursuant to the PSA, the Sellers will reserve (i) a minority working interest in the Deep Rights, (ii) an overriding royalty interest in certain of the Deep Rights and (iii) all rights from the surface to the base of the Clinton formation underlying the Leases. In consideration of the conveyance of the Deep Rights, at closing, the Company’s share of the cash proceeds from the sale will be approximately $12 million.

 

The closing of the PSA transaction is subject to due diligence by the buyer. The PSA contains customary representations, warranties and covenants by the parties. The PSA may be terminated by the Sellers or the buyer: (i) if the downward adjustments to the Purchase Price attributable to title defects or adverse environmental conditions exceed certain thresholds; (ii) if the representations and warranties by either party fail to be materially correct at closing; or (iii) if either party fails to perform or satisfy covenants required for closing. The PSA provides for a closing date no later than 60 days from the date of the PSA.

 

Pursuant to a Stock Purchase Agreement dated June 9, 2014, the Company purchased approximately 8.2 million shares of the Company’s common stock from a shareholder for a purchase price of $0.40 per share. This purchase represented 100% of the shareholder’s holdings of the Company’s common stock. These shares were canceled and returned to the Company’s authorized stock and reduced the number of shares issued and outstanding.

 

On February 25, 2014, Nytis LLC entered into a Participation Agreement with Liberty that allows Liberty to participate with Nytis LLC in the drilling and completion of wells on certain of Nytis LLC’s leases located in Kentucky.

 

Pursuant to the Participation Agreement, Liberty paid Nytis LLC approximately $1.7 million. Upon receipt of this payment, Nytis LLC assigned to Liberty a 40% working interest in the covered leases. In accordance with the agreement, Liberty will pay a disproportionate percentage of the costs associated with drilling and completing 20 wells on the covered leases. In addition, pursuant to the agreement, as of September 30, 2014, Liberty purchased a 40% interest in additional acreage for approximately $1.1 million. As of September 30, 2014, Liberty has participated in four wells, three of which were drilled on a promoted basis, pursuant to this agreement.

 

The Participation Agreement also provides for the reservation by Nytis LLC of an overriding royalty interest with respect to the covered leases, subject to an agreed upon minimum net revenue interest.

 

Following the drilling of these 20 wells, Nytis LLC and Liberty will pay their respective costs on a basis proportionate to their working interest.

 

 

Results of Operations

 

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013

 

The following discussion and analysis relates to items that have affected our results of operations for the three months ended September 30, 2014 and 2013. 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)		2014				2013				Change
Revenue:
Oil and natural gas revenues		$	5,664			$	5,122				11	%
Commodity derivative gain (loss)			689				(265	)			*
Other income			82				92				(11	%)
Total revenues			6,435				4,949				30	%
Expenses:
Lease operating expenses			786				662				19	%
Transportation costs			450				400				13	%
Production and property taxes			481				369				30	%
General and administrative			1,698				1,266				34	%
Depreciation, depletion and amortization			815				767				6	%
Accretion of asset retirement obligations			29				36				(19	%)
Total expenses			4,259				3,500				22	%
Operating income		$	2,176			$	1,449				50	%
Other income and (expense):
Interest expense			(116	)			(157	)			(26	%)
Equity investment income			2				2				*
Total other income and (expense)		$	(114	)		$	(155	)			(26	%)
Production data:
Natural gas (Mcf)			539,369				533,080				1	%
Oil (Bbl)			33,863				31,386				8	%
Combined (Mcfe)			742,547				721,396				3	%
Average prices before effects of hedges:
Natural gas (per Mcf)		$	4.49			$	3.55				26	%
Oil (per Bbl)		$	95.72			$	102.86				(7	%)
Combined (per Mcfe)		$	7.63			$	7.10				7	%
Average prices after effects of hedges**:
Natural gas (per Mcf)		$	5.18			$	3.65				42	%
Oil (per Bbl)		$	105.06			$	92.70				13	%
Combined (per Mcfe)		$	8.56			$	6.73				27	%
Average costs (per Mcfe):
Lease operating expenses		$	1.06			$	0.92				15	%
Transportation costs		$	0.61			$	0.55				11	%
Production and property taxes		$	0.65			$	0.51				27	%
Depreciation, depletion and amortization		$	1.10			$	1.06				4	%

 

*   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 increased to approximately $5.7 million for the three months ended September 30, 2014 from approximately $5.1 million for the three months ended September 30, 2013, an increase of 11%. This increase was primarily attributed to a 28% increase in natural gas revenues. Natural gas prices in the third quarter of 2014 increased 26% over the third quarter of 2013 and production increased 1%. Oil revenues in the third quarter of 2014 were virtually unchanged as compared to the third quarter in 2013. Oil sales volumes increased 8% over the same period in 2013, but were offset by a 7% decrease in average oil prices from the same period in 2013.

 

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 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-markets 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 three months ended September 30, 2014, we had hedging gains of approximately $689,000 compared to hedging losses of approximately $265,000 for the three months ended September 30, 2013.

 

Lease operating expenses- Lease operating expenses for the three months ended September 30, 2014 increased 19% compared to the three months ended September 30, 2013. On a per Mcfe basis, lease operating expenses increased from $0.92 per Mcfe for the three months ended September 30, 2013 to $1.06 per Mcfe for the three months ended September 30, 2014 primarily due to increased oil production relative to natural gas. Operating costs for oil producing properties are generally higher than for gas producing properties due to various factors including water disposal, well maintenance and other costs associated with oil producing properties.

 

Transportation costs- Transportation costs for the three months ended September 30, 2014 increased 13% compared to the three months ended September 30, 2013. On a per Mcfe basis, these expenses increased from $0.55 per Mcfe for the three months ended September 30, 2013 to $0.61 per Mcfe for the three months ended September 30, 2014. This increase is primarily due to new transportation contracts entered into during the fourth quarter of 2013.

 

Production and property taxes- Production and property taxes increased from approximately $369,000 for the three months ended September 30, 2013 to approximately $481,000 for the three months ended September 30, 2014. This increase is primarily attributed to increased production taxes as a result of increased natural gas sales revenues and an adjustment of estimated ad valorem tax rates on current year revenues. On a per Mcfe basis, these expenses increased from $0.51 per Mcfe for the three months ended September 30, 2013 to $0.65 per Mcfe for the three months ended September 30, 2014.

 

Depreciation, depletion and amortization (DD&A)- DD&A increased from approximately $767,000 for the three months ended September 30, 2013 to approximately $815,000 for the three months ended September 30, 2014 due to a 4% increase in the Company’s depletion rate and increased oil sales volumes. On a per Mcfe basis, these expenses increased from $1.06 per Mcfe for the three months ended September 30, 2013 to $1.10 per Mcfe for the three months ended September 30, 2014.

 

General and administrative expenses- General and administrative expenses for the three months ended September 30, 2014 increased 34% over the same period in 2013. The increase is primarily due to an increase in staff related costs, a reclassification of fees to lease operating expense and legal costs related to the potential sale of the Company’s Deep Rights underlying certain oil and gas leases located in Kentucky and West Virginia and stock-based compensation, a non-cash expense, in the third quarter of 2014 as compared to the third quarter of 2013 as shown in the table below.

 

(in thousands)		2014				2013				Increase
Stock-based compensation		$	390			$	325			$	65
Other general and administrative expenses			1,308				941				367
General and administrative expense, net		$	1,698			$	1,266			$	432

 

 

Interest expense- Interest expense decreased from approximately $157,000 for the three months ended September 30, 2013 to approximately $116,000 for the three months ended September 30, 2014 primarily due to lower average effective interest rates during the three months ended September 30, 2014 compared to the same period in 2013 as the Company negotiated the elimination of interest rate floors in its credit agreement in June 2013.

 

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

 

The following discussion and analysis relates to items that have affected our results of operations for the nine months ended September 30, 2014 and 2013. 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)		2014				2013				Change
Revenue:
Oil and natural gas revenues		$	17,710			$	13,143				35	%
Commodity derivative loss			(79	)			(190	)			(58	%)
Other income			254				325				(22	%)
Total revenues			17,885				13,278				35	%
Expenses:
Lease operating expenses			2,523				1,914				32	%
Transportation costs			1,341				1,162				15	%
Production and property taxes			1,350				965				40	%
General and administrative			4,617				3,760				23	%
Depreciation, depletion and amortization			2,307				2,069				12	%
Accretion of asset retirement obligations			87				103				(16	%)
Total expenses			12,225				9,973				23	%
Operating income		$	5,660			$	3,305				71	%
Other income and (expense):
Interest expense			(362	)			(470	)			(23	%)
Equity investment income (loss)			7				(77	)			*
Total other income and (expense)		$	(355	)		$	(547	)			(35	%)
Production data:
Natural gas (Mcf)			1,605,907				1,684,203				(5	%)
Oil (Bbl)			99,772				70,781				41	%
Combined (Mcfe)			2,204,539				2,108,889				5	%
Average prices before effects of hedges:
Natural gas (per Mcf)		$	4.96			$	3.77				32	%
Oil (per Bbl)		$	97.64			$	96.02				2	%
Combined (per Mcfe)		$	8.03			$	6.23				29	%
Average prices after effects of hedges**:
Natural gas (per Mcf)		$	4.93			$	3.86				28	%
Oil (per Bbl)		$	97.42			$	91.16				7	%
Combined (per Mcfe)		$	8.00			$	6.14				30	%
Average costs (per Mcfe):
Lease operating expenses		$	1.14			$	0.91				25	%
Transportation costs		$	0.61			$	0.55				11	%
Production and property taxes		$	0.61			$	0.46				33	%
Depreciation, depletion and amortization		$	1.05			$	0.98				7	%

  

*   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 increased 35% to approximately $17.7 million for the nine months ended September 30, 2014 from approximately $13.1 million for the nine months ended September 30, 2013. This increase was primarily due to a 43% increase in oil revenues attributed to the Company’s focus on developing its oil properties in the Berea Sandstone formation in the Appalachian Basin. Oil sales volumes and prices in the first nine months of 2014 increased 41% and 2%, respectively, over the first nine months of 2013. Natural gas revenues in the first nine months of 2014 increased 26% over the first nine months in 2013 due to a 32% increase in natural gas prices offset in part by a 5% decrease in natural gas sales volumes.

 

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 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-markets 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, 2014, we had hedging losses of approximately $79,000 compared to hedging losses of approximately $190,000 for the nine months ended September 30, 2013.

 

Lease operating expenses- Lease operating expenses for the nine months ended September 30, 2014 increased 32% in the first nine months of 2014 compared to the first nine months of 2013. On a per Mcfe basis, lease operating expenses increased from $0.91 per Mcfe for the nine months ended September 30, 2013 to $1.14 per Mcfe for the nine months ended September 30, 2014 primarily due to increased oil production relative to natural gas. Operating costs for oil producing properties are generally higher than for gas producing properties due to various factors including water disposal, well maintenance and other costs associated with oil producing properties. For the first nine months of 2014, the Company incurred additional lease operating expenses for lease maintenance associated with winter damage and costs associated with bringing new wells on production.

 

Transportation costs- Transportation costs for the nine months ended September 30, 2014 increased 15% compared to the nine months ended September 30, 2013. On a per Mcfe basis, these expenses increased from $0.55 per Mcfe for the nine months ended September 30, 2013 to $0.61 per Mcfe for the nine months ended September 30, 2014. This increase is primarily due to new transportation contracts entered into during the fourth quarter of 2013.

 

Production and property taxes- Production and property taxes increased from approximately $965,000 for the nine months ended September 30, 2013 to approximately $1.4 million for the nine months ended September 30, 2014. This increase is primarily attributed to increased production taxes as a result of increased oil and natural gas sales revenues. On a per Mcfe basis, these expenses increased from $0.46 per Mcfe for the nine months ended September 30, 2013 to $0.61 per Mcfe for the nine months ended September 30, 2014.

 

Depreciation, depletion and amortization (DD&A)- DD&A increased from approximately $2.1 million for the nine months ended September 30, 2013 to approximately $2.3 million for the nine months ended September 30, 2014 due to a 6% increase in the Company’s depletion rate and increased oil sales volumes. On a per Mcfe basis, these expenses increased from $0.98 per Mcfe for the nine months ended September 30, 2013 to $1.05 per Mcfe for the nine months ended September 30, 2014.

 

General and administrative expenses- General and administrative expenses for the nine months ended September 30, 2014 increased $857,000 or 23%, from the nine months ended September 30, 2013. The increase is primarily due to an increase in staff expenditures, legal costs related to the potential sale of the Company’s Deep Rights underlying certain oil and gas leases located in Kentucky and West Virginia and stock-based compensation, a non-cash expense as shown in the table below

 

(in thousands)		2014				2013				Increase
Stock-based compensation		$	1,101			$	641			$	460
Other general and administrative expenses			3,516				3,119				397
General and administrative expense, net		$	4,617			$	3,760			$	857

 

 

Interest expense- Interest expense decreased from approximately $470,000 for the nine months ended September 30, 2013 to approximately $362,000 for the nine months ended September 30, 2014 primarily due to lower average effective interest rates during the nine months ended September 30, 2014 compared to the same period in 2013 as the Company negotiated the elimination of interest rate floors in its credit agreement in June 2013.

 

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, as market conditions have permitted, 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 fluctuations in commodity prices on our cash flow. As of September 30, 2014, we have outstanding natural gas hedges of 250,000 MMBtu for the remainder of 2014 at an average price of $4.16 per MMBtu, 750,000 MMBtu for 2015 at an average price of $4.05 per MMBtu and 40,000 MMBtu for 2016 at an average price of $4.20 per MMBtu in addition to oil hedges of 12,000 barrels for the remainder of 2014 at an average price of $93.79 per barrel and 10,000 barrels for 2015 at an average price of $94.66 per barrel. This level of hedging will provide a measure of certainty of the cash flow that we will receive for a portion of our production in 2014 through 2016. 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. As of September 30, 2014, our derivative counterparty, or its affiliates, was party to our credit facility.

 

The other primary source of liquidity is our credit facility (described below), which had an aggregate borrowing base of $20.0 million of which approximately $6.1 million was available as of September 30, 2014. This facility is used to fund operations, capital programs and acquisitions and to refinance debt, as needed and if available. The credit facility is secured by substantially all of our assets and matures in May 2017. See—“Bank Credit Facility” below for further details. We had approximately $13.9 million drawn on our credit facility as of September 30, 2014.

 

In addition, pursuant to the terms of the Participation Agreement between Liberty and the Company entered into on February 25, 2014, Liberty paid Nytis LLC approximately $2.8 million for a 40% interest in the covered leases and will pay a disproportionate percentage of the costs associated with drilling and completing 20 wells on the covered leases. Following the drilling of these 20 wells, Nytis LLC and Liberty will pay their respective costs on a basis proportionate to their working interest. As of September 30, 2014, Liberty has participated in four wells, three of which were drilled on a promoted basis, pursuant to this agreement.

 

On October 15, 2014, the Company, together with Liberty, (the Sellers”) entered into a Purchase and Sale Agreement (the “PSA”) for the sale of a portion of the Company’s interest in rights below the base of the Clinton Formation (the “Deep Rights”) underlying certain oil and gas leases located in Kentucky and West Virginia.

 

The closing of the PSA transaction is subject to due diligence by the buyer. The PSA contains customary representations, warranties and covenants by the parties. The PSA may be terminated by the Sellers or the buyer: (i) if the downward adjustments to the Purchase Price attributable to title defects or adverse environmental conditions exceed certain thresholds; (ii) if the representations and warranties by either party fail to be materially correct at closing; or (iii) if either party fails to perform or satisfy covenants required for closing. The PSA provides for a closing date no later than 60 days from the date of the PSA. In consideration of the conveyance of the Deep Rights, at closing, the Company’s share of the cash proceeds from the sale will be approximately $12 million.

 

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.

 

 

We believe that our current cash and cash equivalents, expected future cash flows provided by operating activities, the $6.1 million of funds available under our credit facility at September 30, 2014, the additional liquidity provided under the terms of the Participation Agreement with Liberty and the proceeds from the sale of the Company's Deep Rights, if the transaction closes, will be sufficient to fund our normal recurring operating needs, anticipated capital expenditures (other than the potential acquisition of additional oil and natural gas properties), and our contractual obligations. However, if our revenue and cash flow decrease in the future as a result of deterioration in domestic and global economic conditions or a significant decline in commodity prices, we may elect to reduce our planned capital expenditures. We believe that this financial flexibility to adjust our spending levels will provide us with sufficient liquidity to meet our financial obligations should economic conditions deteriorate. 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

 

Nytis LLC has a bank credit facility which consists of a $50.0 million credit facility (the “Credit Facility”) with Bank of Oklahoma. The Credit Facility will mature in May 2017 and is guaranteed by Nytis USA and Carbon. Our availability under the Credit Facility is governed by a borrowing base (the “Borrowing Base”), which at September 30, 2014 was $20.0 million. The determination of the Borrowing Base is made by the lender in its sole discretion, on a semi-annual basis, taking into consideration the estimated value of our oil and natural gas properties in accordance with the lender’s customary practices for oil and natural gas loans. The available borrowing amount under the Credit Facility could increase or decrease based on such redetermination. The next redetermination of the Borrowing Base is expected to occur in November 2014. In addition to the semi-annual redeterminations, Nytis LLC and the lender each have discretion at any time, but not more often than once during a calendar year, to have the Borrowing Base redetermined.

 

A lowering of the Borrowing Base could require us to repay indebtedness in excess of the Borrowing Base in order to cover the deficiency.

 

The facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base. Interest rates are based on either an Alternate Base Rate or LIBOR. The portion of the loan based on an “Alternate Base Rate” is determined by the rate per annum equal to 1.5% plus the greatest of the following: (a) the Federal Funds Rate for such day plus one-half of one percentage point, (b) the Prime Rate for such day or (c) LIBOR for a one-month LIBOR Interest Period plus one percentage point. The portion based on LIBOR is determined by the rate per annum equal to LIBOR plus between 2.5% and 3.25% for each LIBOR tranche.

 

The Credit Facility includes terms that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers, and acquisitions, and requires satisfaction of a current ratio (the ratio of current assets (including borrowing base capacity) to current liabilities) of 1.0 to 1.0 and a maximum funded debt ratio (the ratio of the outstanding balance of all interest bearing indebtedness to the sum of EBITDAX (net income plus interest expense, income taxes, depreciation, depletion, amortization, exploration and impairment expenses and other non-cash charges)) of 4.25 to 1.0, for the most recently completed fiscal quarter times four. If we were to fail to perform our obligations under these covenants or other covenants and obligations, it could cause an event of default and the Credit Facility could be terminated and amounts outstanding could be declared immediately due and payable by the lenders, subject to notice and, in certain cases, cure periods. Such events of default include non-payment, breach of warranty, non-performance of financial covenants, default on other indebtedness, certain adverse judgments, change of control, and a failure of the liens securing the Credit Facility. In addition, bankruptcy and insolvency events with respect to Nytis LLC or certain of its subsidiaries will result in an automatic acceleration of the indebtedness under the Credit Facility.

 

Of the $50.0 million total nominal amount under the Credit Facility, Bank of Oklahoma holds 100% of the total commitments. As of September 30, 2014 there was approximately $13.9 million in borrowings under the Credit Facility. The Company’s effective borrowing rate at September 30, 2014 was approximately 3.0%.

 

In addition, the Credit Facility includes a hedging component that provides a line of credit under commodity swap, exchange, collar, cap and fixed price agreements and agreements designated to protect the Company against changes in interest and currency exchange rates. The maximum amount of credit on this line is $9.5 million.

 

 

Historical Cash Flow

 

Net cash provided by or (used in) operating, investing and financing activities for the nine months ended September 30, 2014 and 2013 were as follows:

 

		Nine Months Ended
		September 30,
(in thousands)		2014				2013
Net cash provided by operating activities		$	8,866			$	5,098
Net cash used in investing activities		$	(6,025	)		$	(6,050	)
Net cash (used in) provided by financing activities		$	(2,570	)		$	1,801

 

Net cash provided by operating activities is primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and changes in working capital. The increase in operating cash flows of approximately $3.8 million for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013 was primarily due to increased operating income attributed to a 41% increase in oil sales volumes and a 26% increase in natural gas revenues.

 

Net cash used in investing activities decreased by approximately $25,000 for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013. This decrease is attributed to $2.8 million received from the sale of oil and gas properties relating to the Participation Agreement with Liberty offset by an increase in capital expenditures of approximately $2.7 million and other long-term asset expenditures.

 

Financing cash flows decreased by approximately $4.4 million for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013 principally due to a purchase of approximately 8.2 million shares of the Company’s common stock for approximately $3.4 million, a decrease in proceeds, net of repayments, from our line of credit and an increase in distributions to non-controlling interests due to increased gas revenues.

 

Capital Expenditures

 

Capital expenditures incurred for the nine months ended September 30, 2014 and 2013 are summarized in the following table:

 

		Nine Months Ended September 30,
(in thousands)		2014				2013
Acquisition of oil and gas properties:
Unevaluated properties		$	1,502			$	836
Proved producing properties			99				563
Drilling and development			7,077				4,598
Other			177				143
Total capital expenditures		$	8,855			$	6,140

 

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 manage our capital expenditures by keeping our exploration and development capital spending near our cash flows which the Company can manage as it controls and operates substantially all the wells in which it has an interest. We were able to expand our oil drilling program in 2014 and 2013 by entering into two separate drilling programs with Liberty, one in 2012 and the other in 2014, in which Liberty has or will pay a disproportionate percentage of costs associated with the drilling and completion of 20 wells in each of the drilling programs. 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.

 

 

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, 2014, the off-balance sheet arrangements and transactions that we have entered into include (i) operating lease agreements and (ii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as natural gas transportation commitments and (iii) oil and 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 (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 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 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 our 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 earnings, the most directly comparable GAAP measure to EBITDA and Adjusted EBITDA for the three and nine months ended September 30, 2014 and 2013.

 

		Three Months Ended
		September 30,
(in thousands)		2014				2013
Net income		$	2,062			$	1,294
Adjustments:
Interest expense			116				157
Depreciation, depletion and amortization			815				767
EBITDA			2,993				2,218
Adjusted EBITDA
EBITDA			2,993				2,218
Adjustments:
Accretion of asset retirement obligations			29				36
Adjusted EBITDA		$	3,022			$	2,254

 

		Nine Months Ended
		September 30,
(in thousands)		2014				2013
Net income		$	5,305			$	2,758
Adjustments:
Interest expense			362				470
Depreciation, depletion and amortization			2,307				2,069
EBITDA			7,974				5,297
Adjusted EBITDA
EBITDA			7,974				5,297
Adjustments:
Accretion of asset retirement obligations			87				103
Adjusted EBITDA		$	8,061			$	5,400

 

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, 2014. 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, 2014 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, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

 

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

 

The Company is subject to legal claims and proceedings in the ordinary course of its oil and natural gas exploration and development business.  Management believes that none of the current pending proceedings would have a material adverse effect on the Company, should the matters be resolved against the Company.

 

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, 2014, have been previously reported in a quarterly report on Form 10-Q.

 

ITEM 5. Other Information

 

The Company has reviewed its previously filed exhibits and determined that certain exhibits should have been filed as Exhibit No. 2.2, 2.3 and 2.4 in its previously filed reports. Therefore, the Company is refiling these exhibits in this Form 10-Q to correctly categorize them as agreements involving the sale or disposition of assets. The sale of the assets described in these exhibits is not related to the Company’s core business of exploration, development and production of oil and natural gas properties.

 

 

ITEM 6. Exhibits

 

Exhibit No.		Description
2.2*^		Participation Agreement by and between the Company, Nytis Exploration Company LLC and Liberty Energy LLC, dated September 17, 2012.
2.3*^		Participation Agreement by and between the Company, Nytis Exploration Company LLC and Liberty Energy LLC, dated February 25, 2014.
2.4*^		Addendum to Participation Agreement by and between the Company, Nytis Exploration Company LLC and Liberty Energy LLC, dated February 26, 2014.
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 of St. Lawrence Seaway Corporation, incorporated by reference to exhibit 3(ii) to Form 8-K/A for St. Lawrence Seaway Corporation filed on March 31, 2011.
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.

 

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*

Filed herewith

^	The Company agrees to furnish supplementally to the Securities and Exchange Commission a copy of any omitted schedule and exhibits upon request.

†

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

 

  

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, 2014		By:	/s/ Patrick R. McDonald
			PATRICK R. MCDONALD,
			Chief Executive Officer
Date: November 14, 2014		By:	/s/ Kevin D. Struzeski
			KEVIN D. STRUZESKI
			Chief Financial Officer

 

 

 

32

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