Carbon Energy Corp - FORM 10-Q

Attached files

file	filename
EXCEL - IDEA: XBRL DOCUMENT - Carbon Energy Corp	Financial_Report.xls
EX-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. - Carbon Energy Corp	f10q0313ex32i_carbonnatural.htm
EX-31.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13A-15(E) / RULE 15D-15(E). - Carbon Energy Corp	f10q0313ex31i_carbonnatural.htm
EX-31.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO RULE 13A-14(A) / RULE 15(E)/15D-15(E). - Carbon Energy Corp	f10q0313ex31ii_carbonnatural.htm
EX-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. - Carbon Energy Corp	f10q0313ex32ii_carbonnatural.htm

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 March 31, 2013 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 May 10, 2013, there were issued and outstanding 117,395,405 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	16

Item 4. Controls and Procedures	25

Part II – OTHER INFORMATION

Item 1. Legal Proceedings	26

Item 2. Unregistered Sale of Securities	26

Item 6. Exhibits	26

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

CARBON NATURAL GAS COMPANY

Consolidated Balance Sheets

	March 31, 2013			December 31, 2012
(in thousands)	(Unaudited)
ASSETS

Current assets:
Cash and cash equivalents	$	1,623		$	328
Accounts receivable:
Revenue		2,348			2,665
Joint interest billings and other		414			344
Firm transportation contract obligations (note 12)		649			836
Due from related parties (note 13)		-			446
Prepaid expense, deposits and other current assets		165			114
Total current assets		5,199			4,733

Property and equipment, at cost (note 4)
Oil and gas properties, full cost method of accounting:
Proved, net		32,864			32,186
Unevaluated		1,403			1,126
Other property and equipment, net		286			242
		34,553			33,554

Investments in affiliates (note 5)		1,087			1,217
Other long-term assets		811			874

Total assets	$	41,650		$	40,378

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable and accrued liabilities	$	6,443		$	5,404
Firm transportation contract obligations (note 12)		1,708			2,200
Derivative liability		418			87
Total current liabilities		8,569			7,691

Non-current liabilities:
Asset retirement obligation (note 2)		2,386			2,321
Firm transportation contract obligations (note 12)		1,757			1,896
Notes payable (note 6)		11,488			11,088
Total non-current liabilities		15,631			15,305

Commitments (note 12)

Stockholders’ equity:
Preferred stock, $0.01 par value; authorized 1,000,000 shares, no shares issued and outstanding at March 31, 2013 and December 31, 2012
		-			-
Common stock, $0.01 par value; authorized 200,000,000 shares, 115,795,405 shares issued and outstanding at March 31, 2013 and December 31, 2012		1,158			1,158
Additional paid-in capital		54,270			54,195
Non-controlling interests		3,035			3,088
Accumulated deficit		(41,013	)		(41,059	)
Total stockholders’ equity		17,450			17,382

Total liabilities and stockholders’ equity	$	41,650		$	40,378

See Notes to Consolidated Financial Statements.

CARBON NATURAL GAS COMPANY

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended
	March 31,
(in thousands, except per share amounts)	2013			2012

Revenue:
Oil and gas	$	3,519		$	2,807
Commodity derivative (loss) gain		(378	)		111
Other income		143			53
Total revenue		3,284			2,971

Expenses:
Lease operating expenses		599			601
Transportation costs		369			467
Production and property taxes		267			220
General and administrative		1,234			1,272
Depreciation, depletion and amortization		630			1,011
Accretion of asset retirement obligations		32			26
Impairment of oil and gas properties		-			5,498
Total expenses		3,131			9,095

Operating income (loss)		153			(6,124	)

Other income and (expense):
Interest expense		(155	)		(148	)
Equity investment (loss) income		(5	)		1
Total other income and (expense)		( 160	)		( 147	)

Loss before income taxes		(7	)		(6,271	)

Provision for income taxes		-			-

Net loss before non-controlling interests		(7	)		(6,271	)

Net loss attributable to non-controlling interests		53			435

Net income (loss) attributable to controlling interest	$	46		$	(5,836	)

Net income (loss) per common share:
Basic	$	0.00		$	(0.05	)
Diluted	$	0.00		$	(0.05	)
Weighted average common shares outstanding:
Basic		112,228			112,228
Diluted		116,532			112,228

See Notes to Consolidated Financial Statements.

CARBON NATURAL GAS COMPANY

Consolidated Statements of Stockholders’ Equity

(Unaudited)

(in thousands)

										(Accumulated
					Additional		Non-			Deficit) /			Total
	Common Stock				Paid-in		Controlling			Retained			Stockholders’
	Shares		Amount		Capital		Interests			Earnings			Equity

Balances, December 31, 2012		115,795	$	1,158	$	54,195	$	3,088		$	(41,059	)	$	17,382

Stock-based compensation		-		-		75		-			-			75

Net income (loss)		-		-		-		(53	)		46			(7	)

Balances, March 31, 2013		115,795	$	1,158	$	54,270	$	3,035		$	(41,013	)	$	17,450

See Notes to Consolidated Financial Statements.

CARBON NATURAL GAS COMPANY

Consolidated Statements of Cash Flows

(Unaudited)

	Three Months Ended
	March 31,
(in thousands)	2013			2012

Cash flows from operating activities:
Net loss	$	(7	)	$	(6,271	)
Items not involving cash:
Depreciation, depletion and amortization		630			1,011
Accretion of asset retirement obligations		32			26
Impairment of oil and gas properties		-			5,498
Unrealized derivative loss		332			23
Stock-based compensation expense		75			105
Equity investment loss (income)		5			(1	)
Net change in:
Accounts receivable		486			537
Prepaid expenses, deposits and other current assets		(50	)		(27	)
Accounts payable, accrued liabilities and firm
transportation contracts		189			(661	)
Due to/from related parties		446			(339	)
Net cash provided by (used in) operating activities		2,138			( 99	)

Cash flows from investing activities:
Development of properties and equipment		(1,378	)		(2,222	)
Equity method distributions (investment)		125			(87	)
Other long-term assets		10			67
Net cash used in investing activities		(1,243	)		(2,242	)

Cash flows from financing activities:
Proceeds from notes payable		400			2,050
Distributions to non-controlling interests		-			(34	)
Net cash provided by financing activities		400			2,016

Net increase (decrease) in cash and cash equivalents		1,295			(325	)

Cash and cash equivalents, beginning of period		328			473

Cash and cash equivalents, end of period	$	1,623		$	148

See Notes to Consolidated Financial Statements.

Note 1 – Organization

Carbon Natural Gas Company (“Carbon”) is an independent oil and gas company engaged in the exploration, development and production of oil and natural gas in the United States. The Company’s business is comprised of the assets and properties of Nytis USA and its subsidiaries Nytis Exploration Company LLC (“Nytis LLC”) and Nytis Exploration of Pennsylvania LLC (“Nytis Pennsylvania”) which conduct the Company’s operations in the Appalachian and Illinois Basins. Collectively, Carbon, Nytis USA, Nytis LLC and Nytis Pennsylvania 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 March 31, 2013 and the Company’s results of operations and cash flows for the three months ended March 31, 2013 and 2012. Operating results for the three months ended March 31, 2013 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 natural gas and oil, 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, 2012 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 subsidiaries. The Company owns 100% of Nytis USA. Nytis USA owns 85% of Nytis Pennsylvania, which is currently being dissolved, and approximately 98% 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 42 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 gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil. Depletion is calculated using the 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 current prices, 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.

As of March 31, 2013, based on oil prices of $92.63 per barrel and gas prices of $2.95 per Mcf, the Company’s full cost pool did not exceed the ceiling limitations. An impairment expense of $5.5 million was recorded during the three months ended March 31, 2012.

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 a 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 5% 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, would increase or decrease by the Company’s share of the affiliate’s profits or losses and such profits or losses would be recognized in the Company’s 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.

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

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

The following table is a reconciliation of the ARO for the three months ended March 31, 2013 and 2012:

(in thousands)	Three Months Ended March 31,
	2013		2012
Balance at beginning of period	$	2,321	$	2,149
Accretion expense		32		26
Additions during period		33		-

Balance at end of period	$	2,386	$	2,175

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 March 31, 2013, the diluted income per common share calculation excludes the dilutive effect of approximately 2.9 million common stock equivalents that were out-of-the-money. For the three months ended March 31, 2012, the diluted loss per common share calculation excludes the dilutive effect of approximately 7.7 common stock equivalents due to the loss.

Note 3– Dispositions and Acquisitions

Liberty Participation Agreement

On September 17, 2012, Nytis LLC entered into a Participation Agreement (the “Participation Agreement”) with Liberty Energy LLC (“Liberty”), a Massachusetts limited liability company 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 to Nytis LLC an initial payment of approximately $3.7 million. Upon receiving this initial payment, Nytis LLC assigned to Liberty a forty (40%) working interest in the covered leases. In addition to the initial payment, Liberty will carry a greater percentage of the costs associated with the first 20 wells drilled under the Participation Agreement subject to a maximum cap for any individual well, in addition to a maximum cap for the first 20 wells in the aggregate. Liberty has committed to participate in the first ten (10) wells on the basis described above and may elect to participate in the following ten (10) wells in two groups of five (5) on that same basis. Following the drilling of the initial 20 wells, the parties will pay their respective costs on an unpromoted basis.

Should Liberty decide not to participate in all 20 of the initial wells on this basis, it will re-assign to Nytis LLC the 40% working interest for the properties in which it does not participate and will retain a 40% working interest in the approved spacing units associated with only those wells in which it did so participate. If Liberty does not participate fully in the first 20 wells then it will have no further re-assignment obligations and hold its 40% working interest in all of the leases and the parties will continue to develop these oil and gas interests on an unpromoted basis pursuant to an industry-standard join operating agreement.

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 oil and gas properties.

Note 4 – Property and Equipment

Net property and equipment as of March 31, 2013 and December 31, 2012 consists of the following:

(in thousands)	March 31, 2013			December 31, 2012

Oil and gas properties
Proved oil and gas properties	$	92,412		$	91,132
Unproved properties not subject to depletion		1,403			1,126
Accumulated depreciation, depletion, amortization and impairment		(59,548	)		(58,946	)
Net oil and gas properties		34,267			33,312

Furniture and fixtures, computer hardware and software, and other equipment		854			782
Accumulated depreciation and amortization		(568	)		(540	)
Net other property and equipment		286			242

Total net property and equipment	$	34,553		$	33,554

As of March 31, 2013 and December 31, 2012, the Company had approximately $1.4 million and $1.1 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.

Note 4 – Property and Equipment (continued)

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.

The Company capitalized overhead applicable to acquisition, development and exploration activities of approximately $108,000 and $129,000 for the three months ended March 31, 2013 and 2012, respectively.

Depletion expense related to oil and gas properties for the three months ended March 31, 2013 and 2012 was approximately $602,000, or $0.91 per equivalent Mcfe, and $987,000, or $1.44 per equivalent Mcfe, respectively. An oil and natural gas property ceiling test impairment of approximately $5.5 million was recognized for the three months ended March 31, 2012. Depreciation and amortization expense related to furniture and fixtures, computer hardware and software and other equipment for the three months ended March 31, 2013 and 2012 was approximately $28,000 and $24,000, 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 three month period ended March 31, 2013 and 2012, the Company recorded equity method loss of approximately $5,000 and income of approximately $1,000, respectively, related to this investment.

Note 6 – Bank Credit Facility

Nytis LLC’s credit facility with Bank of Oklahoma which matures on May 2014 has a borrowing base of $20.0 million and a maximum line of credit available under hedging arrangements of $8.0 million. Carbon is a guarantor 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 of 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. For all debt outstanding regardless if the loan is based on the Alternative Base Rate or LIBOR, there is a minimum floor of 4.5% per annum. 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.

At March 31, 2013, there were approximately $11.5 million in outstanding borrowings and approximately $8.5 million of additional borrowing capacity available under the credit facility. The Company’s effective borrowing rate at March 31, 2013 was 4.75%. 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 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.

Note 6 – Bank Credit Facility (continued)

Effective June 1, 2012, the Company and Bank of Oklahoma amended the credit agreement whereby Bank of Oklahoma agreed to waive the funded debit ratio covenant during the remainder of 2012. From July 1, 2012 through March 31, 2013 the minimum interest rate was increased by 25 basis points (from 4.5% to 4.75% per annum). Other applicable credit spreads under the facility also increased by 25 basis points during this period.

The Company is in compliance with all covenants associated with the credit agreement as of March 31, 2013.

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. We have net operating loss carryforwards available in certain jurisdictions to reduce future taxable income. Future tax benefits for net operating loss carryforwards are recognized to the extent that realization of these benefits is considered more likely than not. To the extent that available evidence raises doubt about the realization of a deferred income tax asset, a valuation allowance is established.

At March 31, 2013, 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 March 31, 2013, the Company had 200,000,000 shares of common stock, par value of $0.01 per share, authorized and 115,795,405 shares of common stock issued and outstanding and one million shares of preferred stock, par value of $0.01 per share, authorized and no shares of preferred stock issued and outstanding.

Carbon 2011 Stock Incentive Plan

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

The 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, director or consultant.

Restricted Stock

During 2012, 1,610,000 shares of restricted stock were granted and were outstanding as of December 31, 2012. Restricted stock awards for employees vest ratably over a three-year service period and for non-employee directors 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 restricted stock 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 March 31, 2013, approximately 430,000 of the restricted stock grants have vested.

Compensation cost recognized for restricted stock grants was approximately $75,000 and $105,000 for the three months ended March 31, 2013 and 2012, respectively. As of March 31, 2013, there was approximately $622,000 of total unrecognized compensation costs related to restricted stock. This cost is expected to be recognized over the next 6.2 years.

Note 8 – Stockholders’ Equity (continued)

Restricted Performance Units

For the year ended December 31, 2012, the Company granted 1,290,000 restricted performance units. 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 agreement including the achievement of the price of the Company’s stock relative to a defined peer group and the lapse of forfeiture restrictions pursuant to the terms and conditions of the agreement, including the requirement of continuous employment by the grantee prior to a change in control of the Company. Based on the relative achievement of performance, 1,166,160 of the restricted performance units are outstanding as of March 31, 2013 and if all performance goals are achieved and forfeiture restrictions pursuant to the terms and conditions of the agreement are met, estimated unrecognized compensation cost could potentially be approximately $758,000.

Note 9 – Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities at March 31, 2013 and December 31, 2012 consist of the following:

(in thousands)	March 31, 2013		December 31, 2012

Accounts payable	$	1,743	$	790
Oil and gas revenue payable to oil and gas property owners		1,761		1,886
Production taxes payable		123		123
Drilling advances received from joint venture partner		581		537
Accrued drilling costs		155		75
Accrued lease operating costs		21		61
Accrued ad valorem taxes		709		596
Accrued general and administrative expenses		1,194		1,083
Other accrued liabilities		156		253

Total accounts payable and accrued liabilities	$	6,443	$	5,404

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.

Note 10 – Fair Value Measurements (continued)

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.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2013 and December 31, 2012 by level within the fair value hierarchy:

(in thousands)	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Total
March 31, 2013
Liabilities:
Commodity derivatives	$	-	$	418	$	-	$	418

December 31, 2012
Liabilities:
Commodity derivatives	$	-	$	87	$	-	$	87

As of March 31, 2013, the Company’s commodity derivative financial instruments are comprised of six natural gas swap agreements and four oil swap agreements. As of December 31, 2012, the Company’s commodity derivative financial instruments were comprised of two natural gas swap agreements and two 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 result 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 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. Accordingly, the fair value is based on unobservable pricing inputs and therefore, is included within the Level 3 fair value hierarchy.

Note 11 – Physical Delivery Contracts and Gas Derivatives

The Company has historically used commodity-based derivative contracts to manage exposures to commodity price on certain of its natural gas and oil production. The Company does not hold or issue derivative financial instruments for speculative or trading purposes. The Company also enters into gas physical delivery contracts to effectively provide gas price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded at fair value in the consolidated financial statements.

At March 31, 2013, the Company has fixed price contracts requiring physical deliveries for approximately 1,500 Mcf/day at an average price of $3.27 per Mcf from April 2013 through October 2013; approximately 900 Mcf/day at an average sales price of $3.50 per Mcf from November 2013 through December 2013; and approximately 250 Mcf/day at an average sales price of $4.13 from January 2014 through March 2014.

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

At March 31, 2013, other than the above mentioned contracts, the Company’s other gas sales contracts approximate index prices.

The Company’s swap agreements as of March 31, 2013 are summarized in the table below:

Agreement	Remaining		Fixed Price	Floating Price
Type	Term	Quantity	Counterparty Payer	Nytis USA Payer
Swap	4/13 - 12/13	10,000 MMBtu/month	$3.715/ MMBtu	(a)
Swap	4/13 - 3/14	10,000 MMBtu/month	$3.840/ MMBtu	(a)
Swap	4/13 - 2/15	20,000 MMBtu/month	$3.830/ MMBtu	(a)
Swap	4/13 - 3/14	10,000 MMBtu/month	$4.030/ MMBtu	(a)
Swap	11/13 - 10/14	10,000 MMBtu/month	$4.125/ MMBtu	(a)
Swap	1/14 - 12/14	10,000 MMBtu/month	$4.105/ MMBtu	(a)
Swap	4/13 - 12/13	500 Bbl/month	$87.70/ Bbl	(b)
Swap	4/13 - 12/13	1,000 Bbl/month	$91.30/ Bbl	(b)
Swap	4/13 - 12/13	500 Bbl/month	$93.20/ Bbl	(b)
Swap	1/14 - 12/14	500 Bbl/month	$91.50/ Bbl	(b)

(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)		March 31, 2013				December 31, 2012
Natural gas derivative contracts: Current liabilities		$	418			$	87

The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the three months ended March 31, 2013 and 2012. These realized and unrealized gains and losses are recorded and included in commodity derivative (loss) gain in the accompanying consolidated statements of operations.

(in thousands)		Three Months Ended March 31,
		2013			2012
Commodity derivative contracts: Realized (losses) gains	$	(46	)	$	134
Unrealized losses		(332	)		(23	)

Total realized and unrealized (losses) gains, net	$	(378	)	$	111

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

Realized gains and/or losses are included in cash flows from operating activities in the Company’s consolidated statements of cash flows.

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 gas assets.

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

Note 12 – Commitments

The Company has long-term firm transportation contracts. Firm transportation volumes and the related demand charges for the remaining term of the contracts at March 31, 2013 are (i) for the remainder of 2013; approximately 8,700 dekatherms per day capacity with demand charges ranging between $0.22 and $1.40 per dekatherm, (ii) for 2014 through May 2015; 4,450 dekatherms per day with demand charges ranging between $0.22 and $0.65, (iii) for June 2015 through 2017; 3,300 dekatherms per day with demand charges of $0.65 per dekatherm and for 2018 through April 2036; 1,000 dekatherms per day with demand charges of $0.22 per dekatherm. A liability of approximately $3.5 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 sheets as of March 31, 2013.

Note 13 – Related Party Transactions

Pursuant to a service agreement entered into in 2011 between the Company and a related entity, the Company managed, directed and supervised the operations and business of the related entity for a monthly fee of $15,000. Effective June 30, 2012, the agreement was terminated.

Note 14 – Supplemental Cash Flow Disclosure

Supplemental cash flow disclosures for the three months ended March 31, 2013 and 2012 are presented below:

	Three Months Ended March 31,
(in thousands)	2013		2012

Cash paid during the period for:
Interest payments	$	167	$	151

Non-cash transactions:
Increase (decrease) in net asset retirement obligations	$	33	$	-
Increase (decrease) in accounts payable and accrued liabilities included in oil and gas properties	$	218	$	(1,314	)

Note 15 – Subsequent Event

Subsequent to March 31, 2013, the Company issued 1,600,000 restricted shares and 1,920,000 restricted performance units pursuant to the Carbon 2011 Stock Incentive Plan.

In April 2013, Liberty elected to participate in five additional wells under terms pursuant to the Participation Agreement. In total, Liberty has committed to participate in 15 wells under the agreement and may elect to participate in the following five wells on that same basis.

In May 2013, in two separate transactions, the Company acquired proved producing oil and gas properties and additional interests in partnerships with proved producing oil and gas properties located in Kentucky and West Virginia for a total purchase price of approximately $517,000.

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 2012 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 natural gas and oil company engaged in the acquisition, exploration, development and production of natural gas and oil properties located in the Appalachian and the Illinois Basin of the United States. The Company focuses on the development of its inventory of mineral rights including oil reservoirs, shale gas, tight gas sands and coalbed methane. Our corporate offices are located in Denver, Colorado and Lexington, Kentucky.

At December 31, 2012, 86% of our estimated proved reserves were natural gas and, as a result, our financial results will be more sensitive to fluctuations in natural gas prices. However as demonstrated by our current capital expenditure programs, the Company is increasingly focused on developing its oil reserves while continuing to pursue acquisitions that complement our existing core programs. We believe that our drilling inventory, combined with our operating expense and cost structure, provides us with meaningful growth opportunities. Our growth plan is centered on the following activities:

●	Development of oil production projects;

●	Pursuing the development of projects that we believe will generate attractive rates of return;

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

●	Continuing to seek property and land acquisitions that complement our core 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 sources of energy. 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:

		2011						2012							2013
		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1

Oil (Bbl)	$	102.55	$	89.81	$	94.02	$	102.94	$	93.51	$	92.19	$	88.20	$	94.34
Natural Gas (MMBtu)	$	4.32	$	4.20	$	3.54	$	2.72	$	2.22	$	2.81	$	3.41	$	3.34

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 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.

Recent Developments

Liberty Participation Agreement

On September 17, 2012, Nytis LLC entered into a Participation Agreement (the “Participation Agreement”) with Liberty Energy LLC (“Liberty”), a Massachusetts limited liability company that will permit 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 to Nytis LLC an initial payment of approximately $3.7 million. Upon receiving this initial payment, Nytis LLC assigned to Liberty a forty percent (40%) working interest in the covered leases. In addition to the initial payment, Liberty will carry a greater percentage of the costs associated with the first 20 wells drilled under the Participation Agreement subject to a maximum cap for any individual well, in addition to a maximum cap for the first 20 wells in the aggregate. As of April 2013, Liberty has committed to participate in the first 15 wells on the basis described above and may elect to participate in the following five (5) on that same basis. Following the drilling of the initial 20 wells, the parties will pay their respective costs on an unpromoted basis.

Should Liberty decide not to participate in all 20 of the initial wells on this basis, it will re-assign to Nytis LLC the 40% working interest for the properties in which it does not participate and will retain a 40% working interest in the approved spacing units associated with only those wells in which it did so participate. If Liberty does participate fully in the first 20 wells then it will have no further re-assignment obligations and hold its 40% working interest in all of the leases and the parties will continue to develop these oil and gas interests on an unpromoted basis pursuant to an industry-standard join operating agreement.

As of March 31, 2013, Liberty has participated with the Company in the drilling and completion of eight (8) oil wells which are either producing or will commence production in the second quarter of 2013. An additional two (2) oil wells have been spud and are works-in-progress.

Acquisitions

In May 2013, in two separate transactions, the Company required proved producing oil and gas properties and additional interests in partnerships with proved producing oil and gas properties located in Kentucky and West Virginia for a total purchase price of approximately $517,000.

Results of Operations

Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012.

The following discussion and analysis relates to items that have affected our results of operations for the three months ended March 31, 2013 and 2012. The following table sets forth, for the periods presented, selected historical statements of operations data.

	Three Months Ended
	March 31,						Percent
(in thousands, except production and per unit data)	2013			2012			Change
Revenue:
Oil and natural gas revenues	$	3,519		$	2,807			25	%
Commodity derivative (loss) gain		(378	)		111			(441	%)
Other income		143			53			170	%
Total revenues		3,284			2,971			11	%

Expenses:
Lease operating expenses		599			601			(0	%)
Transportation costs		369			467			(21	%)
Production and property taxes		267			220			21	%
General and administrative		1,234			1,272			(3	%)
Depreciation, depletion and amortization		630			1,011			(38	%)
Accretion of asset retirement obligations		32			26			23	%
Impairment of oil and gas properties		-			5,498			*
Total expenses		3,131			9,095			(66	%)

Operating income (loss)	$	153		$	(6,124	)		102	%

Other income and (expenses):
Interest expense	$	(155	)	$	(148	)		5	%
Equity investment (loss) income		(5	)		1			*
Total other income and (expenses)	$	(160	)	$	(147	)		9	%

Production data:
Natural gas (Mcf)		571,236			629,234			(9	%)
Oil and liquids (Bbl)		14,960			9,663			55	%
Combined (Mcfe)		660,996			687,212			(4	%)

Average prices before effects of hedges:
Natural gas (per Mcf)	$	3.83		$	2.99			28	%
Oil and liquids (per Bbl)	$	88.99		$	96.11			(7	%)
Combined (per Mcfe)	$	5.32		$	4.08			30	%

Average prices after effects of hedges**:
Natural gas (per Mcf)	$	3.31		$	3.20			3	%
Oil and liquids (per Bbl)	$	83.74		$	94.72			(12	%)
Combined (per Mcfe)	$	4.75		$	4.26			12	%

Average costs (per Mcfe):
Lease operating expenses	$	0.91		$	0.87			5	%
Transportation costs	$	0.56		$	0.68			(18	%)
Production and property taxes	$	0.40		$	0.32			25	%
Depreciation, depletion and amortization	$	0.95		$	1.47			(35	%)

* Not meaningful or applicable

** Includes realized and unrealized commodity derivative gains

Oil and natural gas revenues- Revenues from sales of natural gas and oil and liquids increased to $3.5 million for the three months ended March 31, 2013 from $2.8 million for the three months ended March 31, 2012, an increase of 25%. This increase was primarily due to a 43% increase in oil revenues attributed to the Company’s focus on developing its oil properties. Oil sales volumes in the first quarter of 2013 increased 55% over the first quarter of 2012; whereas oil prices for the first quarter of 2013 were 7% lower than oil prices in the first quarter of 2012. Natural gas sales in the first quarter of 2013 increased 16% over the first quarter in 2012 due to a 28% increase in natural gas prices which offset a 9% 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 or variable swap contracts when our management believes that favorable future sales prices for our natural gas and oil production can be secured. 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 swap agreements as the future strip prices fluctuate compared to the fixed price we will receive from these swap agreements. For the three months ended March 31, 2013 we had hedging losses of approximately $378,000 compared to hedging gains of approximately $111,000 for the three months ended March 31, 2012.

Lease operating expenses- Lease operating expenses for the three months ended March 31, 2013 decreased nominally compared to the three months ended March 31, 2012. On a per Mcfe basis, lease operating expenses increased from $0.87 per Mcfe for the three months ended March 31, 2012 to $0.91 per Mcfe for the three months ended March 31, 2013 due to increased oil production for the three months ended March 31, 2013 as compared to 2012.

Transportation costs- Transportation costs decreased from approximately $467,000 for the three months ended March 31, 2012 to approximately $369,000 for the three months ended March 31, 2013 primarily due to lower gas volumes sold. On a per Mcfe basis, these expenses decreased from $0.68 per Mcfe for the three months ended March 31, 2012 to $0.56 per Mcfe for the three months ended March 31, 2013. The Company incurs minimal transportation costs on its new oil production the effect of which reduces the Company’s overall average transportation costs per Mcf equivalent.

Production and property taxes- Production and property taxes increased from approximately $220,000 for the three months ended March 31, 2012 to approximately $267,000 for the three months ended March 31, 2013. This increase is attributed primarily to production and property taxes on increased revenue from the Company’s new oil production offset, in part, by a decrease in lower natural gas revenues. On a per Mcfe basis, these expenses increased from $0.32 per Mcfe for the three months ended March 31, 2012 to $0.40 per Mcfe for the three months ended March 31, 2013.

Depreciation, depletion and amortization (DD&A)- DD&A decreased from approximately $1.0 million for the three months ended March 31, 2012 to approximately $630,000 for the three months ended March 31, 2013 due to lower depletion rates. On a per Mcfe basis, these expenses decreased from $1.47 per Mcfe for the three months ended March 31, 2012 to $0.95 per Mcfe for the three months ended March 31, 2013. This decrease is primarily attributed to a reduction in the depletable asset base caused by oil and gas impairment expenses recognized in 2012.

Impairment of oil and gas properties- The Company did not recognize an impairment for the three months ended March 31, 2013. For the three months ended March 31, 2012, the Company recognized a non-cash impairment expense of approximately $5.5 million principally due to a decrease in natural gas prices.

General and administrative expenses- General and administrative expenses decreased from approximately $1.3 million for the three months ended March 31, 2012 to approximately $1.2 million for the three months ended March 31, 2013. The decrease is primarily due to lower stock-based compensation, a non-cash expense, in the first quarter of 2013 as compared to the first quarter of 2012 as shown in the table below.

	2013		2012		Decrease
(in thousands)
Stock-based compensation	$	75	$	105	$	(30	)
Other general and administrative expenses		1,159		1,167		(8	)
General and administrative expense, net	$	1,234	$	1,272	$	(38	)

Interest expense- Interest expense increased from approximately $148,000 for the three months ended March 31, 2012 to approximately $155,000 for the three months ended March 31, 2013 primarily due to higher average debt balances during the first quarter of 2013 compared to the first quarter in 2012.

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. For the quarter ended March 31, 2013 and 2012, natural gas made up approximately 86% and 92%, respectively, of our hydrocarbon production and approximately 62% and 67%, respectively, of our oil and gas revenues. Oil and liquids made up approximately 14% and 8%, respectively, of our hydrocarbon production and approximately 38% and 33%, respectively, of our oil and gas revenues. As a result, our operations and cash flow are more sensitive to fluctuations in the market price for natural gas than to fluctuations in the market price for oil and liquids. We employ a commodity hedging strategy in an attempt to moderate the effects of wide fluctuations in commodity prices on our cash flow. As of March 31, 2013, we have outstanding natural gas hedges of 470,000 MMBtu for the remainder of 2013 at an average price of $3.86 per MMBtu, 520,000 MMBtu for 2014 at an average price of $3.96 per MMBtu and 40,000 MMBtu for 2015 at an average price of $3.83 per MMBtu in addition to oil hedges of 18,000 barrels for the remainder of 2013 at an average price of $90.88 per barrel and 6,000 barrels for 2014 at an average price of $91.50 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 2013 and 2014. However, future hedging activities may result in reduced income or even financial losses to us. See “Risk Factors— Future use of 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 March 31, 2013, our derivative counterparty was party to our credit facility, or its affiliates.

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 $8.5 million was available as of March 31, 2013. This facility is used to fund operations, capital programs and acquisitions and refinance debt, as needed and if available. The credit facility is secured by a portion of our assets and matures in May 2014. See—“Bank Credit Facility” below for further details. We had $11.5 million drawn on our credit facility as of March 31, 2013.

In addition, pursuant to the terms of the Participation Agreement between Liberty and the Company, Liberty will carry a greater percentage of the costs associated with the first 20 wells drilled under the Participation Agreement subject to a maximum cap for any individual well, in addition to a maximum cap for the first 20 wells in the aggregate. As of April 2013, Liberty has committed to participate in the first 15 wells on the basis described above and may elect to participate in the following five wells on the same basis.

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, cash flows provided by operating activities, and $8.5 million of funds available under our credit facility at March 31, 2013 will be sufficient to fund our normal recurring operating needs, anticipated capital expenditures (other than the potential acquisition of additional natural gas and oil 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 2014 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 March 31, 2013 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 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 May 2013. 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. For all debt outstanding regardless if the loan is based on an Alternative Base Rate or LIBOR, there is a minimum floor of 4.5% per annum.

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 held 100% of the total commitments. As of March 31, 2013 there was approximately $11.5 million in borrowings under the Credit Facility. The Company’s effective borrowing rate at March 31, 2013 was 4.75%.

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 $8.0 million.

Historical Cash Flow

Net cash provided by or used in operating, investing and financing activities for the three months ended March 31, 2013 and 2012 were as follows:

	Three Months Ended
	March 31,
(in thousands)	2013				2012

Net cash provided by (used in) operating activities		$	2,138			$	(99	)
Net cash used in investing activities		$	(1,243	)		$	(2,242	)
Net cash provided by financing activities		$	400			$	2,016

Net cash provided by or used in operating activities is primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and changes in working capital. The increase in operating cash flows of approximately $2.2 million for the three months ended March 31, 2013 as compared to the three months ended March 31, 2012 was primarily due to increased operating income generated from new oil production, increased natural gas prices, payments received from related parties and other positive working capital adjustments.

Cash used in investing activities decreased by approximately $1.0 million for the three months ended March 31, 2013 compared to the three months ended march 31, 2012. This decrease is principally due to lower capital expenditures associated with the development of our oil properties in the three months ended March 31, 2013. Pursuant to the Participation Agreement entered into with Liberty in September 2012, Liberty carried a greater percentage of the costs of the oil wells drilled in the first three months of 2013 which lowered our capital expenditure costs. See “Capital Expenditures” below for more detail on our capital expenditures.

The decrease in financing cash flows of approximately $1.6 million for the three months ended March 31, 2013 compared to the three months ended March 31, 2012 was primarily due to an increase in bank borrowings for the three months ended March 31, 2012 to fund capital expenditures associated with the development of the Company’s oil properties in that period.

Capital Expenditures

Capital expenditures for the three months ended March 31, 2013 and 2012 are summarized in the following table:

	Three Months Ended March 31,
(in thousands)	2013		2012

Acquisition of oil and gas properties:
Unevaluated properties	$	287	$	107
Proved producing properties		-		90
Drilling and development		1,018		1,869
Pipeline and gathering		-		126
Other		73		30
Total capital expenditures	$	1,378	$	2,222

Due to the downturn in the overall economy and its impact on the price for natural gas, we chose to reduce our capital expenditures and drilling activity for natural gas and to re-direct our capital expenditures to drilling oil properties for the three months ended March 31, 2013 and 2012. In addition, we managed 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 the last quarter of 2012 and the first quarter of 2013, by entering into a Participation Agreement with Liberty. Pursuant to this agreement, the Company received an initial payment of $3.7 million and the Company assigned Liberty a forty percent (40%) working interest in certain leases covered in the agreement. In addition to the initial payment, Liberty will carry a greater percentage of the costs associated with the first 20 wells drilled under the agreement subject to a maximum cap for any individual well, in addition to a maximum cap for the first 20 wells in the aggregate. Following the drilling of the initial 20 wells, the Company will pay its respective costs on an unpromoted basis. Primary factors impacting the level of our capital expenditures include natural gas and oil prices, the volatility in these prices, the cost and availability of oil field services and general economic and market conditions.

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 March 31, 2013, the off-balance sheet arrangements and transactions that we have entered into include (i) operating lease agreements, (ii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as natural gas transportation commitments and (iii) 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

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 onsold 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 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 team 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 natural gas and oil 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 team 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 (loss), the most directly comparable GAAP measure, to EBITDA and Adjusted EBITDA for the three months ended March 31, 2013 and 2012.

	Three Months			Three Months
	Ended			Ended
	March 31,			March 31,
(in thousands)	2013			2012

Net (loss) income	$	(7	)	$	(6,271	)

Adjustments:
Interest expense		155			148
Depreciation, depletion and amortization		630			1,011
EBITDA		778			(5,112	)


Adjusted EBITDA
EBITDA		778			(5,112	)
Adjustments:
Accretion of asset retirement obligations		32			26
Impairment of oil and gas properties		-			5,498
Adjusted EBITDA	$	810		$	412

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 natural gas and oil reserves;

●	estimates of our future natural gas and oil 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 natural gas and oil 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 March 31, 2013. 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 March 31, 2013 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 March 31, 2013 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 controversies be resolved against the Company.

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

The following sets forth the information with respect to the unregistered sale of equity securities that occurred during the quarter ended March 31, 2013 or subsequently, and have not been reported on a current report on Form 8-K or other report filed with the Securities and Exchange Commission.

On April 3, 2013, pursuant to its 2011 Stock Incentive Plan, the Company granted 1,600,000 restricted shares to its officers and staff. To the extent these stock grants constituted a sale of equity securities, the Company relied on Sections 4(a)(2) of the Securities Act of 1933 for these stock grants. No commissions or other remuneration were paid in connection with this stock grant.

ITEM 6. Exhibits

Exhibit No.		Description

3(i)(a)		Amended and Restated Certificate of Incorporation of Carbon Natural Gas Company incorporated by reference to exhibit 3(i) to Form 8-K for Carbon Natural Gas Company filed on May 5, 2011.
3(i)(b)		Amended and Restated Certificate of Designation with respect to Series A Convertible Preferred Stock of Carbon Natural Gas Company, incorporated by reference to exhibit 3(i) to Form 8-K for Carbon Natural Gas Company filed July 6, 2011.
3(i)(c)		Certificate of Amendment to Certificate of Incorporation of Carbon Natural Gas Company, Incorporated by reference to exhibit 3(i) to Form 8-K for Carbon Natural Gas Company filed on July 19, 2011.
3(ii)		Amended and Restated Bylaws 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.
10.1		Form of Restricted Stock Agreement (Non-Employee Director) pursuant to the Carbon Natural Gas Company 2011 Stock Incentive Plan, as amended, incorporated by reference to exhibit 10.1 to Form 8-K for Carbon Natural Gas Company filed on April 5, 2013.
10.2		Employment Agreement between the Company and Patrick McDonald, incorporated by reference to exhibit 10.2 to Form 8-K for Carbon Natural Gas Company filed on April 5, 2013.
10.3		Employment Agreement between the Company and Mark Pierce, incorporated by reference to exhibit 10.3 to Form 8-K for Carbon Natural Gas Company filed on April 5, 2013.
10.4		Employment Agreement between the Company and Kevin Struzeski, incorporated by reference to exhibit 10.4 to Form 8-K for Carbon Natural Gas Company filed on April 5, 2013.
10.5		Form of Restricted Stock Agreement (Officer) pursuant to the Carbon Natural Gas Company 2011 Stock Incentive Plan, as amended, incorporated by reference to exhibit 10.5 to Form 8-K for Carbon Natural Gas Company filed on April 5, 2013.
31.1*		Certification of Chief Executive Officer Pursuant to Rule 13a-15(e) / Rule 15d-15(e).
31.2*		Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) / Rule 15(e)/15d-15(e).
32.1†		Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2†		Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
101*		Interactive data files pursuant to Rule 405 of Regulation S-T.

*	Filed herewith

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

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

	CARBON NATURAL GAS COMPANY
	(Registrant)

Date: May 15, 2013	By:	/s/ Patrick R. McDonald
		PATRICK R. MCDONALD,
		Chief Executive Officer




Date: May 15, 2013	By:	/s/ Kevin D. Struzeski
		KEVIN D. STRUZESKI
		Chief Financial Officer

Attached files

Stock widget

Investing forum

Carbon Energy Corp Reports