Carbon Energy (CRBO) 10-Q 2014 Q1 Quarterly report

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, 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  xNO  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  xNO  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 smallerreporting company)

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

YES  oNO  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, 2014, there were issued and outstanding 115,326,890 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		27
Part II – OTHER INFORMATION
Item 1. Legal Proceedings		28
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		28
Item 6.  Exhibits		28

1

PART I. FINANCIAL INFORMATION

ITEM 1.   Financial Statements

CARBON NATURAL GAS COMPANY

Consolidated Balance Sheets

(in thousands, except share and per share data)	March 31,  2014			December 31, 2013
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	2,163		$	243
Accounts receivable:
Revenue		3,144			2,551
Joint interest billings and other		827			627
Prepaid expense, deposits and other current assets		170			95
Total current assets		6,304			3,516
Property and equipment (note 4):
Oil and gas properties, full cost method of accounting:
Proved, net		37,229			39,033
Unevaluated		2,433			2,235
Other property and equipment, net		291			287
Total property and equipment, net		39,953			41,555
Investments in affiliates (note 5)		1,005			1,002
Other long-term assets		623			688
Total assets	$	47,885		$	46,761
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	6,846		$	6,605
Firm transportation contract obligations (note 12)		551			556
Derivative liability		537			226
Total current liabilities		7,934			7,387
Non-current liabilities:
Derivative liability		21			100
Firm transportation contract obligations (note 12)		1,206			1,340
Asset retirement obligation (note 2)		2,747			2,699
Notes payable (note 6)		11,893			12,789
Total non-current liabilities		15,867			16,928
Commitments (note 12)
Stockholders’ equity:
Preferred stock, $0.01 par value; authorized 1,000,000 shares, no shares issued and outstanding at March 31, 2014 and December 31, 2013		-			-
Common stock, $0.01 par value; authorized 200,000,000 shares, 114,900,223 and 114,470,223 shares issued and outstanding at March 31, 2014 and December 31, 2013, respectively		1,149			1,145
Additional paid-in capital		55,346			55,029
Non-controlling interests		3,079			3,045
Accumulated deficit		(35,490	)		(36,773	)
Total stockholders’ equity		24,084			22,446
Total liabilities and stockholders’ equity	$	47,885		$	46,761

See Notes to Consolidated Financial Statements.

2

CARBON NATURAL GAS COMPANY

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended
	March 31,
(in thousands, except per share amounts)	2014			2013
Revenue:
Oil and gas	$	6,096		$	3,519
Commodity derivative loss		(490	)		(378	)
Other income		91			143
Total revenue		5,697			3,284
Expenses:
Lease operating expenses		897			599
Transportation costs		484			369
Production and property taxes		444			267
General and administrative		1,589			1,234
Depreciation, depletion and amortization		764			630
Accretion of asset retirement obligations		29			32
Total expenses		4,207			3,131
Operating income		1,490			153
Other income and (expense):
Interest expense		(119	)		(155	)
Equity investment income (loss)		3			(5	)
Total other income and (expense)		(116	)		( 160	)
Income (loss) before income taxes		1,374			(7	)
Provision for income taxes		-			-
Net income (loss) before non-controlling interests		1,374			(7	)
Net income (loss) attributable to non-controlling interests		91			(53	)
Net income attributable to controlling interest	$	1,283		$	46
Net income per common share:
Basic	$	0.01		$	0.00
Diluted	$	0.01		$	0.00
Weighted average common shares outstanding:
Basic		113,021			112,228
Diluted		118,485			116,532

See Notes to Consolidated Financial Statements.

3

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
Stock-based compensation		-		-		321			-			-			321
Restricted stock vested		430		4		(4	)		-			-			-
Non-controlling interest distributions, net		-		-		-			(57	)		-			(57	)
Net income		-		-		-			91			1,283			1,374
Balances, March 31, 2014		114,900	$	1,149	$	55,346		$	3,079		$	(35,490	)	$	24,084

See Notes to Consolidated Financial Statements.

4

CARBON NATURAL GAS COMPANY

Consolidated Statements of Cash Flows

(Unaudited)

	Three Months Ended
	March 31,
(in thousands)	2014			2013
Cash flows from operating activities:
Net income (loss)	$	1,374		$	(7	)
Items not involving cash:
Depreciation, depletion and amortization		764			630
Accretion of asset retirement obligations		29			32
Unrealized derivative loss		233			332
Stock-based compensation expense		321			75
Equity investment (income) loss		(3	)		5
Net change in:
Accounts receivable		(391	)		486
Prepaid expenses, deposits and other current assets		(75	)		(50	)
Accounts payable, accrued liabilities and firm transportation contracts		836			189
Due to/from related parties		-			446
Net cash provided by operating activities		3,088			2,138
Cash flows from investing activities:
Development of properties and equipment		(2,216	)		(1,378	)
Proceeds from disposition of assets		1,988			-
Equity method distributions (investment)		-			125
Other long-term assets		13			10
Net cash used in investing activities		(215	)		(1,243	)
Cash flows from financing activities:
Proceeds from notes payable		500			400
Payments on notes payable		(1,396	)		-
Distributions to non-controlling interests		(57	)		-
Net cash (used in) provided by financing activities		(953	)		400
Net increase in cash and cash equivalents		1,920			1,295
Cash and cash equivalents, beginning of period		243			328
Cash and cash equivalents, end of period	$	2,163		$	1,623

See Notes to Consolidated Financial Statements.

5

Note 1 – Organization

Carbon Natural Gas Company (“Carbon” or the “Company”) is an independent oil and gas company engaged in the exploration, development and production of oil and natural gas in the United States.  The Company’s business is comprised of the assets and properties of Nytis Exploration (USA) Inc. (“Nytis USA”) and its subsidiary Nytis Exploration Company LLC (“Nytis LLC”) which conducts the Company’s operations in the Appalachian and Illinois Basins.  Collectively, Carbon, Nytis USA and Nytis LLC are referred to as the Company.

Note 2 – 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, 2014 and the Company’s results of operations and cash flows for the three months ended March 31, 2014 and 2013.  Operating results for the three months ended March 31, 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 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.

6

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 months ended March 31, 2014 and 2013, the Company did not recognize a ceiling test impairment as the Company’s full cost pool did not exceed the ceiling limitation.

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.

7

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 three months ended March 31, 2014 and 2013:

	Three Months Ended March 31,
(in thousands)	2014		2013
Balance at beginning of period	$	2,699	$	2,321
Accretion expense		29		32
Additions during period		19		33
Balance at end of period	$	2,747	$	2,386

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, directors 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, 2014, the diluted income per common share calculation excludes the dilutive effect of approximately 250,000 common stock equivalents that were out-of-the-money and approximately 3.1 million restricted performance units subject to future contingencies.  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 and approximately 1.2 million restricted performance units subject to future contingencies.

8

Note 3– Dispositions and Acquisitions

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 forty percent (40%) working interest in the covered leases.  According to the agreement, Liberty will pay a disproportionate percentage of the costs associated with drilling and completing up to 20 wells on the covered leases.  Nytis LLC has the right to provide additional net mineral acres prior to the later of (a) December 31, 2014 or (b) the date that is nine (9) months after the date that the last well was spud in the covered area and, upon delivery of a maximum amount of additional net mineral acres, Nytis LLC will be entitled to additional payments up to a maximum of $1.1 million.  Pursuant to this right, in March 2014, Nytis LLC offered and Liberty purchased a forty percent interest in additional acreage for approximately $238,000.Liberty has committed to participate on the basis described above in one (1) well per 1,000 net mineral acres associated with the covered leases, up to a maximum of 20 wells.  Following the drilling of these wells, the parties will pay their respective costs on a basis proportionate to their working interest.

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

Should Liberty decide not to participate in all of the initial wells on the basis described above, it will re-assign 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 those wells in which it did participate.  If Liberty does participate in the initial wells, then it will have no further re-assignment obligations and will hold its 40% working interest in all of the covered leases and the parties will continue to develop these oil and gas interests on a basis proportionate to their working interest pursuant to an industry standard joint 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 unproved and proved oil and gas properties.

Note 4 – Property and Equipment

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

(in thousands)	March 31,  2014			December 31, 2013
Oil and gas properties:
Proved oil and gas properties	$	99,691		$	100,769
Unproved properties not subject to depletion		2,433			2,235
Accumulated depreciation, depletion, amortization and impairment		(62,462	)		(61,736	)
Net oil and gas properties		39,662			41,268
Furniture and fixtures, computer hardware and software, and other equipment		1,002			960
Accumulated depreciation and amortization		(711	)		(673	)
Net other property and equipment		291			287
Total net property and equipment	$	39,953		$	41,555

9

Note 4 – Property and Equipment (continued)

As of March 31, 2014 and December 31, 2013, the Company had approximately $2.4 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 March 31, 2014 and 2013, the Company capitalized general and administrative expenses applicable to development and exploration activities of approximately $122,000 and $108,000, respectively.

Depletion expense related to oil and gas properties for the three months ended March 31, 2014 and 2013 was approximately $726,000, or $0.96 per Mcfe, and $602,000, or $0.91 per Mcfe, respectively.  Depreciation and amortization expense related to furniture and fixtures, computer hardware and software and other equipment for the three months ended March 31, 2014 and 2013 was approximately $38,000 and $28,000, 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 treatment 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 income or loss is recognized.  During the three month periods ended March 31, 2014 and 2013, the Company recorded equity method income of approximately $3,000 and equity method loss of $5,000, 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 March 31, 2014, there were approximately $11.9 million in outstanding borrowings and approximately $8.1 million of additional borrowing capacity available under the credit facility.  The Company’s effective borrowing rate at March 31, 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 March 31, 2014.

10

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, 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 March 31, 2014, the Company had 200,000,000 shares of common stock authorized with a par value of $0.01 per share, of which 114,900,223 were issued and outstanding and 1.0 million shares of preferred stock authorized with a par value of $0.01 per share, none of which were issued and outstanding.  During the first three months of 2014, increases in the Company’s issued and outstanding common stock reflect restricted stock that vested during the period.

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 March 31, 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 1,956,907 shares of common stock outstanding that are subject to restricted stock agreements.

Nytis USA Restricted Stock Plan

As of March 31, 2014, there were 1,956,907 shares of restricted stock issued under the Nytis USA Restricted Stock Plan (“Nytis USA Plan”).  The Company accounted for these grants at their intrinsic value.  Historically, 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 March 31, 2014.  As of March 31, 2014, there was approximately $923,000 of unrecognized compensation costs related to these restricted stock grants which the Company expects will be recognized ratably over the next 2.8 years.

11

Note 8 – Stockholders’ Equity (continued)

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.

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, director or consultant.

Restricted Stock

During the three months ended March 31, 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 March 31, 2014, approximately 860,000 of these restricted stock grants have vested.

Compensation costs recognized for these restricted stock grants were approximately $150,000 and $75,000 for the three months ended March 31, 2014 and 2013, respectively. As of March 31, 2014, there was approximately $2.4 million of unrecognized compensation costs related to these restricted stock grants.  This cost is expected to be recognized over the next 7 years.

Restricted Performance Units

As of March 31, 2014, 3,210,000 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 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, 3,086,160 of the restricted performance units are outstanding as of March 31, 2014.

The Company accounts for the performance units granted during 2012 at their fair value, re-evaluated at each reporting period to determine if the performance criteria would be met.  The final measurement of compensation cost will be based on the performance units that ultimately vest and the market price on that date.  At March 31, 2014, the Company estimated that none of the performance units granted in 2012 would vest due to change in control provisions and accordingly, no compensation cost has been recorded.  As of March 31, 2014, if change in control provisions pursuant to the terms and conditions of the agreements are met, the estimated unrecognized compensation cost related to the performance units granted in 2012 would be approximately $991,000.

The performance units granted in 2013 contain specific vesting provisions and no change in control provision.  Due to different vesting requirements compared to the performance units granted in 2012, 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.  For the three months ended March 31, 2014 and 2013, compensation costs of approximately $86,000 and nil, respectively, were recognized related to the performance units granted in 2013.  As of March 31, 2014, there was approximately $732,000 of unrecognized compensation costs related to performance units granted in 2013.  These costs are expected to be recognized over the next 2 years.

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Note 9 – Accounts Payable and Accrued Liabilities

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

(in thousands)	March 31, 2014		December 31, 2013
Accounts payable	$	1,414	$	2,151
Oil and gas revenue payable to oil and gas property owners		1,300		1,307
Production taxes payable		181		165
Drilling advances received from joint venture partner		1,472		740
Accrued drilling costs		12		162
Accrued lease operating costs		83		42
Accrued ad valorem taxes		845		681
Accrued general and administrative expenses		1,339		1,146
Other accrued liabilities		200		211
Total accounts payable and accrued liabilities	$	6,846	$	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.

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

(in thousands)	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Total
March 31, 2014
Liabilities:
Commodity derivatives	$	-	$	558	$	-	$	558
December 31, 2013
Liabilities:
Commodity derivatives	$	-	$	326	$	-	$	326

As of March 31, 2014, the Company’s commodity derivative financial instruments are comprised of nine natural gas swap agreements and seven 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 three months ended March 31, 2014 and 2013, the Company recorded asset retirement obligations for additions of approximately $19,000 and $33,000, respectively.  See Note 2 for additional information.

Note 11– Physical Delivery Contracts and Oil and Gas Derivatives

The Company 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, 2014, the Company’s gas sales contracts approximate index prices.

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

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

The Company’s swap agreements as of March 31, 2014 are summarized in the table below:

	Natural Gas				Oil
			Weighted				Weighted
			Average				Average
Period	MMBtu		Price (a)		Bbl		Price (b)
Apr - Jun 2014		270,000	$	4.16		14,000	$	94.10
Jul - Sep 2014		270,000	$	4.16		9,000	$	93.46
Oct - Dec 2014		250,000	$	4.16		9,000	$	93.46
Jan - Mar 2015		220,000	$	4.06		2,000	$	94.10
Apr - Jun 2015		150,000	$	4.02		-		-
Jul - Sep 2015		150,000	$	4.02		-		-
Oct - Dec 2015		150,000	$	4.02		-		-

(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, 2014		December 31, 2013
Commodity derivative contracts:
Current liabilities	$	537	$	226
Non-current liabilities	$	21	$	100

The table below summarizes the realized and unrealized losses related to the Company’s derivative instruments for the three months ended March 31, 2014 and 2013.  These realized and unrealized losses are recorded and included in commodity derivative loss in the accompanying Consolidated Statements of Operations.

(in thousands)	Three Months Ended March 31,
	2014		2013
Commodity derivative contracts:
Realized losses	$	257	$	46
Unrealized losses		233		332
Total realized and unrealized losses, net	$	490	$	378

Realized 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.  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

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

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 March 31, 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	Liabilities		Offset			Liabilities
Commodity derivative assets:
Current derivative asset	$	22	$	(22	)	$	-
Other long-term assets		4		(4	)		-
Total derivative assets	$	26	$	(26	)	$	-
Commodity derivative liabilities:
Current derivative liability		559		(22	)		537
Non-current derivative liability		25		(4	)		21
Total derivative liabilities	$	584	$	(26	)	$	558

Due to the volatility of oil and natural gas 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 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 March 31, 2014 are summarized in the table below.

Period	Dekatherms per day	Demand Charges
Apr - 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 $1.8 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, 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.

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Note 13 – Supplemental Cash Flow Disclosure

Supplemental cash flow disclosures for the three months ended March 31, 2014 and 2013 are presented below:

	Three Months Ended March 31,
(in thousands)	2014			2013
Cash paid during the period for:
Interest payments	$	115		$	167
Non-cash transactions:
Increase in net asset retirement obligations	$	19		$	33
(Decrease) increase in accounts payable and accrued liabilities included in oil  and gas properties	$	(735	)	$	218
Decrease in accounts receivable included in oil and gas property proceeds	$	350		$	-

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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 the Illinois Basin 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.

At December 31, 2013, approximately 88% of our proved developed reserves were natural gas, and, as a result, our financial results are sensitive to fluctuations in natural gas prices.  Our current capital expenditure program is focused on the development of our oil reserves.  We believe that our drilling inventory, 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
		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1
Oil (Bbl)	$	93.51	$	92.19	$	88.20	$	94.34	$	94.23	$	105.82	$	97.50	$	98.62
Natural Gas (MMBtu)	$	2.21	$	2.81	$	3.41	$	3.34	$	4.10	$	3.58	$	3.60	$	4.93

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.

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Operational Highlights

At March 31, 2014, we had over 270,000 net acres of mineral leases located in the Appalachian and Illinois Basins of the United States.  Approximately 50% of these leases are held by production and of the remaining leases, approximately 38% have lease terms of greater than five years remaining in the primary term or contractual extension periods.

The principal focus of our leasing, drilling and completion activities is directed at a Berea Sandstone horizontal drilling program in eastern Kentucky.  At March 31, 2014, we have over 32,000 net mineral acres in the region. Since 2010, we have drilled over 40 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 February 25, 2014, Nytis LLC entered into a Participation Agreement with Liberty Energy LLC 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 forty percent (40%) working interest in the covered leases.  According to the agreement, Liberty will pay a disproportionate percentage of the costs associated with drilling and completing up to 20 wells on the covered leases.  Nytis LLC has the right to provide additional net mineral acres prior to the later of (a) December 31, 2014 or (b) the date that is nine (9) months after the date that the last well was spud in the covered area and, upon delivery of a maximum amount of additional net mineral acres, Nytis LLC will be entitled to additional payments up to a maximum of $1.1 million.  Pursuant to this right, in March 2014, Nytis offered and Liberty purchased a forty percent interest in additional acreage for approximately $238,000.  Liberty has committed to participate on the basis described above in one (1) well per 1,000 net mineral acres associated with the covered leases, up to a maximum of 20 wells.  Following the drilling of these wells, Nytis LLC and Liberty will pay their respective costs on a basis proportionate to their working interest.

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.

Should Liberty decide not to participate in all of the initial wells on the basis described above, it will re-assign 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 those wells in which it did participate.  If Liberty does participate in the initial wells then it will have no further re-assignment obligations and will hold its 40% working interest in all of the covered leases and the parties will continue to develop these oil and gas interests on a basis proportionate to their working interest pursuant to an industry standard joint operating agreement.

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Results of Operations

Three Months Ended March 31, 2014 Compared to Three Months Ended March 31, 2013.

The following discussion and analysis relates to items that have affected our results of operations for the three months ended March 31, 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
	March 31,						Percent
(in thousands, except production and per unit data)	2014			2013			Change
Revenue:
Oil and natural gas revenues	$	6,096		$	3,519			73	%
Commodity derivative loss		(490	)		(378	)		30	%
Other income		91			143			(36	%)
Total revenues		5,697			3,284			73	%
Expenses:
Lease operating expenses		897			599			50	%
Transportation costs		484			369			31	%
Production and property taxes		444			267			66	%
General and administrative		1,589			1,234			29	%
Depreciation, depletion and amortization		764			630			21	%
Accretion of asset retirement obligations		29			32			(9	%)
Total expenses		4,207			3,131			34	%
Operating income	$	1,490		$	153			*
Other income and (expense):
Interest expense	$	(119	)	$	( 155	)		(23	%)
Equity investment income (loss)		3			( 5	)		*
Total other income and (expense)	$	(116	)	$	( 160	)		(28	%)
Production data:
Natural gas (Mcf)		557,950			571,236			(2	%)
Oil and liquids (Bbl)		32,621			14,960			118	%
Combined (Mcfe)		753,676			660,996			14	%
Average prices before effects of hedges:
Natural gas (per Mcf)	$	5.36		$	3.83			40	%
Oil and liquids (per Bbl)	$	95.22		$	88.99			7	%
Combined (per Mcfe)	$	8.09		$	5.32			52	%
Average prices after effects of hedges**:
Natural gas (per Mcf)	$	4.68		$	3.31			41	%
Oil and liquids (per Bbl)	$	91.73		$	83.74			10	%
Combined (per Mcfe)	$	7.44		$	4.75			57	%
Average costs (per Mcfe):
Lease operating expenses	$	1.19		$	0.91			31	%
Transportation costs	$	0.64		$	0.56			14	%
Production and property taxes	$	0.59		$	0.40			48	%
Depreciation, depletion and amortization	$	1.01		$	0.95			6	%

*	Not meaningful or applicable
**	Includes realized and unrealized commodity derivative gains

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Oil and natural gas revenues- Revenues from sales of oil and natural gas increased 73% to approximately $6.1 million for the three months ended March 31, 2014 from approximately $3.5 million for the three months ended March 31, 2013.  This increase was primarily due to a 133% 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 average oil prices for the quarter ended March 31, 2014 increased over the same period in 2013 by 118% and 7%, respectively.  Natural gas revenues in the first quarter of 2014 increased 37% over the first quarter in 2013 due to a 40% increase in natural gas prices offset, in part, by a 2% decrease in natural gas sales volumes sold.

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 predicable 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 March 31, 2014 and 2013, we had hedging losses of approximately $490,000 and $378,000, respectively.

Lease operating expenses-  Lease operating expenses for the three months ended March 31, 2014 increased 50% compared to the three months ended March 31, 2013.  On a per Mcfe basis, lease operating expenses increased from $0.91 per Mcfe for the three months ended March 31, 2013 to $1.19 per Mcfe for the three months ended March 31, 2014 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.  In addition, during the quarter ended March 31, 2014, additional lease operating expenses were incurred for lease maintenance associated with winter damage and costs associated with bringing new wells on production.

Transportation costs-  Transportation costs for the three months ended March 31, 2014 increased 31% compared to the three months ended March 31, 2013.   On a per Mcfe basis, these expenses increased from $0.56 per Mcfe for the three months ended March 31, 2013 to $0.64 per Mcfe for the three months ended March 31, 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 $267,000 for the three months ended March 31, 2013 to approximately $444,000 for the three months ended March 31, 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 $0.40 per Mcfe for the three months ended March 31, 2013 to $0.59 per Mcfe for the three months ended March 31, 2014.

Depreciation, depletion and amortization (DD&A)-  DD&A increased from approximately $630,000 for the three months ended March 31, 2013 to approximately $764,000 for the three months ended March 31, 2014 primarily due to increased oil production.  On a per Mcfe basis, these expenses increased from $0.95 per Mcfe for the three months ended March 31, 2013 to $1.01 per Mcfe for the three months ended March 31, 2014.

21

General and administrative expenses- General and administrative expenses increased from approximately $1.2 million for the three months ended March 31, 2013 to approximately $1.6 million for the three months ended March 31, 2014.  The increase is primarily due to an increase in stock-based compensation, a non-cash expense, in the first quarter of 2014 as compared to the first quarter of 2013 as shown in the table below.

	Three Months Ended March 31,
(in thousands)	2014		2013		Increase
Stock-based compensation	$	321	$	75	$	246
Other general and administrative expenses		1,268		1,159		109
General and administrative expense, net	$	1,589	$	1,234	$	355

Interest expense- Interest expense decreased from approximately $155,000 for the three months ended March 31, 2013 to approximately $119,000 for the three months ended March 31, 2014 primarily due to lower interest rates.

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 wide fluctuations in commodity prices on our cash flow. As of March 31, 2014, we have outstanding natural gas hedges of 790,000 MMBtu for the remainder of 2014 at an average price of $4.16 per MMBtu and 670,000 MMBtu for 2015 at an average price of $4.03 per MMBtu in addition to oil hedges of 32,000 barrels for the remainder of 2014 at an average price of $93.74 per barrel and 2,000 barrels for 2015 at an average price of $94.10 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 and 2015.  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 March 31, 2014, 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 $8.1 million was available as of March 31, 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 $11.9 million drawn on our credit facility as of March 31, 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 $1.7 million for a 40% interest in the covered leases and  will pay a disproportionate percentage of the costs associated with drilling and completing up to 20 wells on the covered leases.  Nytis LLC has the right to provide additional net mineral acres prior to the later of (a) December 31, 2014 or (b) the date that is nine (9) months after the date that the last well was spud in the covered area and, upon delivery of a maximum amount of additional net mineral acres, Nytis LLC will be entitled to additional payments up to a maximum of $1.1 million.  Pursuant to the right, in March 2014, Nytis LLC offered and Liberty purchased a forty percent interest in additional acreage for approximately $238,000.  Liberty has committed to participate on the basis described above in one well per 1,000 net mineral acres associated with the covered leases, up to a maximum of 20 wells.  Following the drilling of these wells, Nytis LLC and Liberty will pay their respective costs on a basis proportionate to their working interest.

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.

22

We believe that our current cash and cash equivalents, expected future cash flows provided by operating activities, the $8.1 million of funds available under our credit facility at March 31, 2014 and the additional liquidity provided under the terms of the Participation Agreement with Liberty 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 March 31, 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 May 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 March 31, 2014 there was approximately $11.9 million in borrowings under the Credit Facility.  The Company’s effective borrowing rate at March 31, 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.

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Historical Cash Flow

Net cash provided by or (used in) operating, investing and financing activities for the three months ended March 31, 2014 and 2013 were as follows:

	Three Months Ended
	March 31,
(in thousands)	2014				2013
Net cash provided by operating activities		$	3,088			$	2,138
Net cash used in investing activities		$	(215	)		$	(1,243	)
Net cash (used in) provided by financing activities		$	(953	)		$	400

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 $950,000 for the three months ended March 31, 2014 compared to the three months ended March 31, 2013 was primarily due to increased operating income generated from new oil production and increased natural gas prices.

Cash used in investing activities decreased by approximately $1.0 million for the three months ended March 31, 2014 compared to the three months ended March 31, 2013.  This decrease is principally due to proceeds received of approximately $2.0 million relating to the Participation Agreement with Liberty offset, in part, by an increase of approximately $838,000 in capital expenditures in the three months ended March 31, 2014 as compared to the three months ended March 31, 2013.

The decrease in financing cash flows of approximately $1.4 million for the three months ended March 31, 2014 compared to the three months ended March 31, 2013 was primarily due to principal payments made to reduce the Company’s Credit Facility balance during the quarter ended March 31, 2014.

Capital Expenditures

Capital expenditures for the three months ended March 31, 2014 and 2013 are summarized in the following table:

	Three Months Ended March 31,
(in thousands)	2014		2013
Acquisition of oil and gas properties:
Unevaluated properties	$	428	$	287
Drilling and development		1,744		1,018
Other		44		73
Total capital expenditures	$	2,216	$	1,378

Due to the higher price of oil relative to natural gas, the Company’s capital expenditure program has focused principally on the development of its oil prospects since 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 2014 and 2013 by entering into two separate drilling programs with Liberty.  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.

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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, 2014, 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.

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 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 flow 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 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 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 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.

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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, 2014 and 2013.

	Three months ended March 31,
(in thousands)	2014		2013
Net income (loss)	$	1,374	$	(7	)
Adjustments:
Interest expense		119		155
Depreciation, depletion and amortization		764		630
EBITDA		2,257		778
Adjusted EBITDA
EBITDA		2,257		778
Adjustments:
Accretion of asset retirement obligations		29		32
Adjusted EBITDA	$	2,286	$	810

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.

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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, 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 March 31, 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 March 31, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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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, 2014 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 March 27, 2014, 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 these stock grants.

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	Participation Agreement by and between the Company, Nytis Exploration Company LLC and Liberty Energy LLC, dated February 25, 2014, incorporated by reference to exhibit 10.12 to Form 10-K for Carbon Natural Gas Company filed on March 31, 2014.
10.2	Addendum to Participation Agreement by and between the Company, Nytis Exploration Company LLC and Liberty Energy LLC, dated February 26, 2014, incorporated by reference to exhibit 10.13 to Form 10-K for Carbon Natural Gas Company filed on March 31, 2014.
10.3	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 2, 2014.
10.4	Form of Restricted Stock Agreement (Officer) pursuant to the Carbon Natural Gas Company 2011 Stock Incentive Plan, as amended, incorporated by reference to exhibit 10.2 to Form 8-K for Carbon Natural Gas Company filed on April 2, 2014.
10.5*	Carbon Natural Gas Company 2014 Annual Incentive Plan.
31.1*	Certification of Chief Executive Officer Pursuant to Rule 13a-15(e) / Rule 15d-15(e).
31.2*	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) / Rule 15(e)/15d-15(e).
32.1†	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2†	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
101*	Interactive data files pursuant to Rule 405 of Regulation S-T.

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

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

	CARBON NATURAL GAS COMPANY
	(Registrant)
Date: May 14, 2014	By:	/s/ Patrick R. McDonald
		PATRICK R. MCDONALD,
		Chief Executive Officer
Date: May 14, 2014	By:	/s/ Kevin D. Struzeski
		KEVIN D. STRUZESKI
		Chief Financial Officer

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