UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

x	Quarterly report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934
	For the quarter ended September 30, 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 November 9, 2013, there were issued and outstanding 114,470,223 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 Unaudited Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 4.	Controls and Procedures	30
Part II – OTHER INFORMATION
Item 1.	Legal Proceedings	31
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31
Item 6.	Exhibits	31

PART I. FINANCIAL INFORMATION

ITEM 1.      Financial Statements

CARBON NATURAL GAS COMPANY

Consolidated Balance Sheets

	September 30, 2013			December 31, 2012
(in thousands)	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	1,177		$	328
Accounts receivable:
Revenue		1,674			2,665
Joint interest billings and other		918			344
Firm transportation contract obligations (note 12)		276			836
Due from related parties (note 13)		-			446
Prepaid expense, deposits and other current assets		150			114
Total current assets		4,195			4,733
Property and equipment, at cost (note 4)
Oil and gas properties, full cost method of accounting:
Proved, net		37,939			32,186
Unevaluated		1,944			1,126
Other property and equipment, net		290			242
		40,173			33,554
Investments in affiliates (note 5)		1,015			1,217
Other long-term assets		749			874
Total assets	$	46,132		$	40,378
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	7,543		$	5,404
Firm transportation contract obligations (note 12)		725			2,200
Derivative liabilities		101			87
Total current liabilities		8,369			7,691
Non-current liabilities:
Asset retirement obligation (note 2)		2,622			2,321
Firm transportation contract obligations (note 12)		1,478			1,896
Notes payable (note 6)		12,988			11,088
Total non-current liabilities		17,088			15,305
Commitments (note 12)
Stockholders’ equity:
Preferred stock, $0.01 par value; authorized 1,000,000  shares, no shares issued and outstanding at September 30, 2013 and December 31, 2012		-			-
Common stock, $0.01 par value; authorized  200,000,000 shares, 114,470,223 and 115,795,405 shares issued and outstanding at September 30, 2013 and December 31, 2012, respectively		1,145			1,158
Additional paid-in capital		54,757			54,195
Non-controlling interests		3,042			3,088
Accumulated deficit		(38,269	)		(41,059	)
Total stockholders’ equity		20,675			17,382
Total liabilities and stockholders’ equity	$	46,132		$	40,378

See accompanying notes to unaudited consolidated financial statements.

2

CARBON NATURAL GAS COMPANY

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands except per share amounts)	2013			2012			2013			2012
Revenue:
Oil and gas	$	5,122		$	2,692		$	13,143		$	7,909
Commodity derivative loss		(265	)		(149	)		(190	)		(8	)
Other income		92			142			325			250
Total revenue		4,949			2,685			13,278			8,151
Expenses:
Lease operating expenses		662			490			1,914			1,584
Transportation costs		400			350			1,162			1,294
Production and property taxes		369			205			965			554
General and administrative		1,266			1,033			3,760			3,310
Depreciation, depletion and amortization		767			588			2,069			2,450
Accretion of asset retirement obligations		36			24			103			76
Impairment of oil and gas properties		-			-			-			15,407
Total expenses		3,500			2,690			9,973			24,675
Operating income (loss)		1,449			( 5	)		3,305			(16,524	)
Other income and (expense):
Interest expense		(157	)		(276	)		(470	)		(599	)
Equity investment income (loss)		2			(29	)		(77	)		(1	)
Total other income and (expense)		( 155	)		( 305	)		( 547	)		( 600	)
Income (loss) before income taxes		1,294			( 310	)		2,758			(17,124	)
Provision for income taxes		-			-			-			-
Net income (loss) before non-controlling interests		1,294			( 310	)		2,758			(17,124	)
Net income (loss) attributable to non-controlling interests		(20	)		(58	)		(32	)		(1,742	)
Net income (loss) attributable to controlling interest	$	1,314		$	( 252	)	$	2,790		$	(15,382	)
Net income (loss) per common share:
Basic	$	0.01		$	(0.00	)	$	0.02		$	(0.14	)
Diluted	$	0.01		$	(0.00	)	$	0.02		$	(0.14	)
Weighted average common shares outstanding:
Basic		112,513			112,228			112,468			112,228
Diluted		120,334			112,228			120,270			112,228

See accompanying notes to unaudited 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, 2012		115,795		$	1,158		$	54,195		$	3,088		$	(41,059	)	$	17,382
Stock based compensation		-			-			641			-			-			641
Restricted stock		(1,325	)		(13	)		(79	)		-			-			( 92	)
Other		-			-			-			(7	)		-			( 7	)
Non-controlling interests distributions		-			-			-			(7	)		-			( 7	)
Net income (loss)		-			-			-			(32	)		2,790			2,758
Balances, September 30, 2013		114,470		$	1,145		$	54,757		$	3,042		$	(38,269	)	$	20,675

See accompanying notes to unaudited consolidated financial statements.

4

CARBON NATURAL GAS COMPANY

Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended
	September 30,
(in thousands)	2013			2012
Cash flows from operating activities:
Net income (loss)	$	2,758		$	(17,124	)
Items not involving cash:
Depreciation, depletion and amortization		2,069			2,450
Accretion of asset retirement obligations		103			76
Impairment of oil and gas properties		-			15,407
Unrealized derivative loss		14			438
Stock-based compensation expense		641			328
Equity investment loss		77			1
Net change in:
Accounts receivable		1,119			717
Prepaid expenses, deposits and other current assets		(35	)		(66	)
Accounts payable, accrued liabilities and firm transportation contracts		(2,094	)		(2,464	)
Due from related parties		446			(315	)
Net cash provided by (used in) operating activities		5,098			( 552	)
Cash flows from investing activities:
Development of properties and equipment		(6,140	)		(5,562	)
Proceeds from participation agreement		-			3,655
Equity method distributions (investment)		125			(87	)
Other long-term assets		(35	)		147
Net cash used in investing activities		(6,050	)		(1,847	)
Cash flows from financing activities:
Purchase of common stock		(92	)		-
Proceeds from notes payable		2,300			5,030
Payments on notes payable		(400	)		-
Other		-			(11	)
Distributions to non-controlling interests		(7	)		(36	)
Net cash provided by financing activities		1,801			4,983
Net increase in cash and cash equivalents		849			2,584
Cash and cash equivalents, beginning of period		328			473
Cash and cash equivalents, end of period	$	1,177		$	3,057

See accompanying notes to unaudited consolidated financial statements.

5

CARBON NATURAL GAS COMPANY

NOTES TO UNAUDITED

CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Organization

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

Note 2 – Summary of Significant Accounting Policies

Basis of Presentation

The accompanying unaudited consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information.  Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements.  In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of September 30, 2013, the Company’s results of operations for the three and nine months ended September 30, 2013 and 2012 and the Company’s cash flows for the nine months ended September 30, 2013 and 2012.   Operating results for the three and nine months ended September 30, 2013 and 2012 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 consolidated financial statements and the notes thereto should be read in conjunction with the Company’s audited consolidated financial statements for the year ended December 31, 2012 filed on Form 10-K with the Securities and Exchange Commission (“SEC”).

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

Principles of Consolidation

The consolidated financial statements include the accounts of Carbon, Nytis USA and its consolidated subsidiary.  The Company owns 100% of Nytis USA.  Nytis USA owns approximately 99% of Nytis LLC.  Nytis LLC also holds an interest in various oil and gas partnerships.

For partnerships where the Company has a controlling interest, the partnerships are consolidated.  The Company is currently consolidating on a pro-rata basis 46 partnerships.  In these instances, the Company reflects the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on its consolidated combined statements of operations and also reflects the non-controlling ownership interest 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

6

Note 2 – Summary of Significant Accounting Policies (continued)

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.

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 September 30, 2013, based on oil prices of $95.04 per barrel and gas prices of $3.61 per Mcf, the Company’s full cost pool did not exceed the ceiling limitation.  In addition, as of June 30, 2013 and March 31, 2013, the Company’s full cost pool did not exceed the ceiling limitations.  For the three and nine months ended September 30, 2012, the Company recorded a non-cash impairment expense of approximately nil and $15.4 million, respectively.

7

Note 2 – Summary of Significant Accounting Policies (continued)

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% voting interest 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 a 20% and 50% 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 statements of operations.  The Company reviews equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred.  The amount of the impairment is based on quoted market prices, where available, or other valuation techniques.

Asset Retirement Obligations

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

part of the full cost pool.  Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability.

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

The following table is a reconciliation of the ARO for the nine months ended September 30, 2013 and 2012:

	Nine Months Ended September 30,
(in thousands)	2013		2012
Balance at beginning of period	$	2,321	$	2,149
Accretion expense		103		76
Additions assumed with consolidated partnerships		34		-
Additions during period		164		55
Balance at end of period	$	2,622	$	2,280

8

Note 2 – Summary of Significant Accounting Policies (continued)

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 and nine months ended September 30, 2013, the diluted income per common share calculation excludes the dilutive effect of approximately 2.7 million and approximately 2.9 million common stock equivalents, respectively, that were out-of-the-money.  For each of the three and nine months ended September 30, 2012, the diluted loss per common share calculation excludes the dilutive effect of approximately 2.6 million common stock equivalents due to the loss.

Note 3– Acquisitions and Dispositions

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 allowed 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 an initial payment of approximately $3.7 million in 2012.  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 carried 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 September 30, 2013, Liberty participated in the first 20 wells on the basis described above.  Prospectively, the parties will pay their respective costs on an unpromoted basis.

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.

Acquisitions

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

The purchase of these assets qualified as a business combination and, as such, the Company estimated the fair value of the assets acquired and liabilities assumed as of the acquisition date (the date on which the Company obtained control of the properties.)  The purchases of these assets were recorded as an investment in the Company’s oil and gas properties.  There was no significant difference between the fair value of the assets and the purchase price.

During the nine months ended September 30, 2013, for nominal cash and assumption of nominal partner liabilities, the Company acquired additional partnership interests from other partners.

9

Note 4 – Property and Equipment

Net property and equipment as of September 30, 2013 and December 31, 2012 consists of the following:

(in thousands)	September 30,  2013			December 31, 2012
Oil and gas properties:
Proved oil and gas properties	$	98,860		$	91,132
Unproved properties not subject to depletion		1,944			1,126
Accumulated depreciation, depletion, amortization and impairment		(60,921	)		(58,946	)
Net oil and gas properties		39,883			33,312
Furniture and fixtures, computer hardware and software, and other equipment		924			782
Accumulated depreciation and amortization		(634	)		(540	)
Net other property and equipment		290			242
Total net property and equipment	$	40,173		$	333,554

As of September 30, 2013 and December 31, 2012, the Company had approximately $1.9 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.  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 $347,000 and $400,000 for the nine months ended September 30, 2013 and 2012, respectively.

Depletion expense related to oil and gas properties for the three and nine months ended September 30, 2013 was approximately $732,000, or $1.01 per equivalent Mcfe, and approximately $2.0 million, or $0.94 per equivalent Mcfe, respectively.  For the three and nine months ended September 30, 2012, depletion expense was  approximately $562,000 or $0.85 per equivalent Mcfe, and approximately $2.4 million or $1.19 per equivalent Mcfe, respectively.

For the three and nine months ended September 30, 2013, the Company did not recognize an oil and natural gas property ceiling test impairment.  For the three and nine months ended September 30, 2012, the Company recognized a non-cash ceiling test impairment of nil and $15.4 million, respectively.   Depreciation and amortization expense related to furniture and fixtures, computer hardware and software and other equipment for the nine months ended September 30, 2013 and 2012 was approximately $94,000 and $74,000, respectively.

Note 5 – Equity Method Investment

The Company has a 50% interest in Crawford County Gas Gathering Company, LLC (“CCGGC”) which owns and operates pipelines and related gathering and treating facilities.  The Company’s gas production located in Illinois is gathered and transported on CCGGC’s gathering facilities.  The Company’s investment in CCGGC is accounted for under the equity method of accounting, and its share of the income or loss is recognized.  During the nine month period ended September 30, 2013 and 2012, the Company recorded an equity method loss of approximately $77,000 and $1,000 respectively, related to this investment.

10

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 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.  Prior to July 2013, for all debt outstanding regardless if the loan was based on the Alternative Base Rate or LIBOR, there was a minimum floor of 4.5% per annum.  On June 28, 2013, the Company and Bank of Oklahoma amended the credit agreement whereby the Company’s loans under the credit agreement are no longer subject to the minimum interest rate floor of 4.5% per annum for LIBOR tranches commencing after July 25, 2013 and loan amounts subject to the Alternate Base Rate after July 31, 2013.  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 September 30, 2013, there were approximately $13.0 million in outstanding borrowings and approximately $7.0 million of additional borrowing capacity available under the credit facility.  The Company’s effective borrowing rate at September 30, 2013 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 current ratio (the ratio of current assets (including borrowing base capacity) to current liabilities as defined) of 1.0 to 1.0 and a maximum funded debt ratio (the ratio of the outstanding balance of all interest bearing indebtedness to the sum of EBITDAX (net income plus interest expense, income taxes, depreciation, depletion, amortization, exploration and impairment expenses and other non-cash charges) for the most recently completed fiscal quarter times four) of 4.25 to 1.0 as of the end of any fiscal quarter.

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

The Company has determined that no current tax liability should be recorded since the Company has sufficient net operating loss carryforwards and other deferred tax assets sufficient to offset any current year taxable income for both regular and alternative minimum tax purpose.  At September 30, 2013, the Company continues to maintain a full valuation allowance against the balance of net deferred tax assets.

11

Note 8 – Stockholders’ Equity

Authorized and Issued Capital Stock

As of September 30, 2013, the Company had 200,000,000 shares of common stock, par value of $0.01 per share, authorized, 114,470,223 shares of common stock issued and outstanding and 1.0 million shares of preferred stock, par value of $0.01 per share, of which none were issued and outstanding.  During the first nine months of 2013, changes in the Company’s issued and outstanding common stock reflect a reduction of restricted stock whose terms were amended such that they were no longer considered issued and outstanding, partially offset by a net increase for restricted stock that vested and was issued during the period.

Equity Plans Prior to Merger

In 2011, pursuant to an Agreement and Plan of Merger by and among St. Lawrence Seaway Corporation (“SLSC”), St. Lawrence Merger Sub, Inc. (“Merger Co”) and Nytis USA, Merger Co. merged with and into Nytis USA with Nytis USA remaining as the surviving subsidiary of SLSC.

Pursuant to the merger, all options, warrants and restricted stock were adjusted to reflect the conversion ratio used in the merger.  As of September 30, 2013, 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 September 30, 2013, 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.

On June 25, 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 and nine months ended September 30, 2013.  As of September 30, 2013, there was approximately $1.1 million of unrecognized compensation costs related to these restricted stock grants which the Company expects will be recognized ratably over the next 3.3 years.

Carbon Stock Incentive Plan

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

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 nine months ended September 30, 2013, 1,600,000 shares of restricted stock were granted under the terms of the Carbon Plan in addition to 1,610,000 shares granted during the year ended December 31, 2012.  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

12

Note 8 – Stockholders’ Equity (continued)

awards (based on a market survey of the average tenure of directors among U.S. public companies).  As of September 30, 2013, approximately 430,000 of these restricted stock grants have vested.

Compensation costs recognized for these restricted stock grants were approximately $150,000 and $112,000 for the three months ended September 30, 2013 and 2012, respectively, and approximately $376,000 and $328,000 for the nine months ended September 30, 2013 and 2012, respectively.  As of September 30, 2013, there was approximately $1.3 million of unrecognized compensation costs related to these restricted stock grants.  This cost is expected to be recognized over the next 6.5 years.  In addition, during the nine months ending September 30, 2013, the Company modified certain rights related to these shares that eliminated voting and dividend rights until the shares vest, resulting in unvested shares no longer considered issued and outstanding.

Restricted Performance Units

During the nine months ended September 30, 2013, 1,920,000 shares of restricted performance units were granted under the terms of the Carbon Plan in addition to 1,290,000 performance units granted during the year ended December 31, 2012.  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 September 30, 2013.

The Company accounts for the performance units granted during 2012 at their fair value, revaluated 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 September 30, 2013, 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 September 30, 2013, 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 $933,000.

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 and nine months ended September 30, 2013, compensation costs of approximately $91,000 and $182,000 respectively, were recognized related to the performance units granted in 2013.  As of September 30, 2013, there was approximately $908,000 of unrecognized compensation costs related to performance units granted in 2013.  These costs are expected to be recognized over the next 2.5 years.

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Note 9– Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities at September 30, 2013 and December 31, 2012 consist of the following:

(in thousands)	September 30,  2013		December 31, 2012
Accounts payable	$	2,780	$	790
Oil and gas revenue payable to oil and gas property owners		1,498		1,886
Production taxes payable		146		123
Drilling advances received from joint venture partner		-		537
Accrued drilling costs		1,219		75
Accrued lease operating costs		42		61
Accrued ad valorem taxes		872		596
Accrued general and administrative expenses		771		1,083
Other accrued liabilities		215		253
Total accounts payable and accrued liabilities	$	7,543	$	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 in the circumstances.  The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

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

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

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

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.  The Company’s policy is to recognize transfers in or out of fair value hierarchies 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 September 30, 2013 and December 31, 2012 by level within the fair value hierarchy:

	Fair Value Measurements Using
(in thousands)	Level 1		Level 2		Level 3		Total
September 30, 2013
Liabilities:
Commodity derivatives	$	-	$	101	$	-	$	101
December 31, 2012
Liabilities:
Commodity derivatives	$	-	$	87	$	-	$	87

As of September 30, 2013, the Company’s commodity derivative financial instruments are comprised of seven natural gas swap agreements and nine 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 results 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 unobserverable pricing inputs and therefore, is included with the Level 3 fair value hierarchy.

Note 11 – Physical Delivery Contracts and Derivatives

The Company has historically used commodity-based derivative contracts to manage exposures to commodity price on certain of its gas production.  The Company does not hold or issue derivative financial instruments for speculative or trading purposes.  Nytis LLC also enters into physical delivery fixed price contracts for certain of its natural gas production 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 September 30, 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 for 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.

At September 30, 2013, other than the above mentioned contracts, the Company’s other gas sales contracts approximate index prices.

15

Note 11 – Physical Delivery Contracts and Derivatives (continued)

The Company’s swap agreements as of September 30, 2013 are summarized in the table below:

	Natural Gas				Oil
			Weighted				Weighted
			Average				Average
Period	MMBtu		Price (a)		BBLs		Price (b)
Oct – Dec 2013		170,000	$	3.89		15,000	$	94.27
Jan – Mar 2014		210,000	$	4.01		9,000	$	93.24
Apr – Jun 2014		150,000	$	4.04		9,000	$	93.24
Jul – Sep 2014		150,000	$	4.04		4,500	$	92.90
Oct – Dec 2014		130,000	$	4.03		4,500	$	92.90
Jan – Mar 2015		40,000	$	3.83		-	$	-
		850,000				42,000

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

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

For its swap instruments, the Company receives a fixed price for the hedged commodity and pays a floating price to the counterparty.  The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

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

(in thousands)	September 30,  2013		December 31, 2012
Derivative contracts:
Current liabilities	$	101	$	87

The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the three and nine months ended September 30, 2013 and 2012.  These realized and unrealized gains and losses are recorded and included in commodity derivative gain (loss) in the accompanying consolidated statements of operations.

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2013			2012			2013			2012
Commodity derivative contracts:
Realized (losses) gains	$	(79	)	$	112		$	(176	)	$	430
Unrealized losses		(186	)		(261	)		(14	)		(438	)
Total realized and unrealized losses, net	$	( 265	)	$	( 149	)	$	( 190	)	$	( 8	)

Realized gains and 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.

16

Note 11 – Physical Delivery Contracts and Derivatives (continued)

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 September 30, 2013 are (i) for the remainder of 2013; approximately 8,000 dekatherms per day capacity with demand charges ranging between $0.22 and $1.40 per dekatherm, (ii) for January through October 2014; approximately 6,700 dekatherms per day with demand charges ranging between $0.22 and $0.65, (iii) for November 2014 through May 2015; approximately 1,800 dekatherms per day with demand charges ranging between $0.22 and $0.65, (iv) 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 $2.2 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 September 30, 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 Disclosures

Supplemental cash flow disclosures for the nine months ended September 30, 2013 and 2012 are presented below:

	Nine Months Ended September 30,
	2013		2012
(in thousands)
Cash paid during the period for:
Interest payments	$	453	$	533
Non-cash transactions:
Increase in net asset retirement obligations due to additions	$	198	$	55
Partner liabilities assumed in acquisition of partnership interests (see Note 3)	$	10	$	-
Increase (decrease) in accounts payable and accrued liabilities included in oil and gas properties	$	2,340	$	(1,402	)

17

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 audited 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 Illinois Basins of the United States.    The Company focuses on the development of its mineral rights including conventional and unconventional oil and gas reserves.  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 investment program, the Company is focused on the development of its oil reserves while continuing to pursue oil and gas acquisitions that complement our existing core asset positions.  As a result of focusing on developing our oil reserves, approximately 63% of the Company’s oil and gas revenues were derived from oil sales for the three months ended September 30, 2013.  We believe that our drilling inventory, combined with our low 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 which we believe will generate attractive rates of return;

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

· Enhance the capital efficiency of our drilling and completion activities through application of technology, economics of scale and concentrated facilities and infrastructure; 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 ten calendar quarters:

	2011						2012								2013
	Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1		Q2		Q3
Oil (Bbl)	$	102.55	$	89.81	$	94.02	$	102.94	$	93.51	$	92.19	$	88.20	$	94.34	$	94.23	$	105.82
Natural Gas (MMBtu)	$	4.32	$	4.20	$	3.54	$	2.72	$	2.22	$	2.81	$	3.41	$	3.34	$	4.10	$	3.58

Lower oil and natural gas prices may not only result in decreased revenues, but may also reduce the amount of oil and natural gas that the Company can produce economically and thus potentially lower our oil and natural gas reserves.  A substantial or extended decline in oil or natural gas prices may result in future impairments of our proved reserves and may materially and adversely affect our future business, financial condition, cash flows, results of operations or liquidity.  Lower oil and natural gas prices may also reduce the amount of borrowing base under our bank credit facility, which is determined at the discretion of our lender.

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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 permits 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 an initial payment of approximately $3.7 million in 2012.  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 carried 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 participated in the first 20 wells on the basis described above.  Prospectively, the parties will pay their respective costs on an unpromoted basis.

Acquisitions

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.

The purchase of these assets qualified as a business combination and, as such, the Company estimated the fair value of the assets acquired and liabilities assumed as of the acquisition date (the date on which the Company obtained control of the properties.)  The purchases of these assets were recorded as an investment in the Company’s oil and gas properties.  There was no significant difference between the fair value of the assets and the purchase price.

During 2013, for nominal cash and assumption of partner liabilities, the Company acquired additional partnership interests from third party partners in a number of the existing partnerships.

Bank Credit Facility

In June 2013, the Company and Bank of Oklahoma amended the credit agreement by extending the maturity date from May 2014 to May 2017.  Also, the Company’s loans under the credit agreement are no longer subject to a minimum interest rate floor of 4.5% per annum for LIBOR tranches commencing after July 25, 2013 and loan amounts subject to the Alternative Base Rate after July 31, 2013.  In addition, the maximum line of credit available under hedging arrangements increased from $8.0 million to $9.5 million.

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Results of Operations

The following discussion and analysis relates to items that have affected our results of operations for the three and nine months ended September 30, 2013 and 2012.  The following tables set forth, for the periods presented, selected historical statements of operations data.  The information contained in the table below should be read in conjunction with the Company's consolidated financial statements and notes thereto and the information under "Forward Looking Statements" below.

Three Months Ended September 30, 2013 Compared to Three Months Ended September 30, 2012

	Three Months Ended
	September 30,						Percent
(in thousands except per unit data)	2013			2012			Change
Revenue:
Oil and natural gas sales	$	5,122		$	2,692			90	%
Commodity derivative loss		( 265	)		( 149	)		78	%
Other income		92			142			(35	%)
Total revenues		4,949			2,685			84	%
Expenses:
Lease operating expenses		662			490			35	%
Transportation costs		400			350			14	%
Production and property taxes		369			205			80	%
General and administrative		1,266			1,033			23	%
Depreciation, depletion and amortization		767			588			30	%
Accretion of asset retirement obligations		36			24			50	%
Total expenses		3,500			2,690			30	%
Operating income (loss)	$	1,449		$	(5	)		*
Other income and (expense):
Interest expense		( 157	)		( 276	)		43	%
Equity investment income (loss)		2			( 29	)		*
Total other income and (expense)	$	( 155	)	$	( 305	)		49	%
Production data:
Natural gas (Mcf)		533,080			595,386			(10	%)
Oil and liquids (Bbl)		31,386			11,273			178	%
Combined (Mcfe)		721,396			663,024			9	%
Average prices before effects of hedges:
Natural gas (per Mcf)	$	3.55		$	3.01			18	%
Oil and liquids (per Bbl)	$	102.86		$	79.87			29	%
Combined (per Mcfe)	$	7.10		$	4.06			75	%
Average prices after effects of hedges:**
Natural gas (per Mcf)	$	3.65		$	2.85			28	%
Oil and liquids (per Bbl)	$	92.70		$	75.20			23	%
Combined (per Mcfe)	$	6.73		$	3.84			75	%
Average costs (per Mcfe):
Lease operating expenses	$	0.92		$	0.74			24	%
Transportation costs	$	0.55		$	0.53			4	%
Production and property taxes	$	0.51		$	0.31			65	%
Depreciation, depletion and amortization	$	1.06		$	0.89			19	%
* Not meaningful or applicable
** Includes realized and unrealized commodity derivative gains and losses.

Oil and natural gas sales- Revenues from sales of natural gas and oil and liquids increased to approximately $5.1 million for the three months ended September 30, 2013 from approximately $2.7 million for the three months ended September 30, 2012, an increase of 90%.  This increase was primarily due to a 259% increase in oil revenues attributed to the Company’s focus on developing its oil properties.  Oil sales volumes and average oil prices in the third quarter of 2013 increased over the third quarter of 2012 178% and 29%, respectively.  Natural gas revenues in the third quarter of 2013 increased 6% over the third quarter of 2012 primarily due to an 18% increase in natural gas prices offset, in part, by a 10% decrease in gas volumes sold.

20

Commodity derivative gains (losses)- To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we enter into derivative contracts using fixed price swap contracts when our management believes that available futures prices for our natural gas and oil 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-market gains or losses, as well as realized gains or losses on the derivative instruments, are currently recognized in our results of operations.  The unrealized gains and losses represent the changes in the fair value of these swap agreements as natural gas and oil futures prices fluctuate relative to the fixed price we will receive from these swap agreements.  For the three months ended September 30, 2013 and 2012, we had hedging losses of approximately $265,000 and $149,000, respectively.

Lease operating expenses- Lease operating expenses for the three months ended September 30, 2013 increased 35% compared to the three months ended September 30, 2012.  On a per Mcfe basis, lease operating expenses increased from $0.74 per Mcfe for the three months ended September 30, 2012 to $0.92 per Mcfe for the three months ended September 30, 2013 primarily due to the increase in oil production relative to natural gas.  Operating costs for oil producing properties are generally higher than for gas producing properties due to various factors including water disposal, well maintenance and other costs associated with oil producing properties.

Transportation costs- Transportation costs increased from approximately $350,000 for the three months ended September 30, 2012 to approximately $400,000 for the three months ended September 30, 2013, a 14% increase.  On a per Mcfe basis, these expenses increased from $0.53 per Mcfe for the three months ended September 30, 2012 to $0.55 per Mcfe for the three months ended September 30, 2013.

Production and property taxes- Production and property taxes increased from approximately $205,000 for the three months ended September 30, 2012 to approximately $369,000 for the three months ended September 30, 2013.  The increase in production and property taxes are directly attributed to increased oil and natural gas revenues as these taxes are primarily based on oil and natural gas revenues generated.

Depreciation, depletion and amortization (DD&A)- DD&A increased from approximately $588,000 for the three months ended September 30, 2012 to approximately $767,000 for the three months ended September 30, 2013 primarily due to increased oil production and a 7% increase in depletion rates for the third quarter of 2013 compared to the same period in 2012.  On a per Mcfe basis, DD&A increased from $0.89 per Mcfe for the three months ended September 30, 2012 to $1.06 per Mcfe for the three months ended September 30, 2013.

Impairment of oil and gas properties- The Company did not recognize an impairment expense for the three months ended September 30, 2013 or 2012.

General and administrative expenses- General and administrative expenses for the three months ended September 30, 2013 increased 23% over the same period in 2013.  As shown in the table below, additional stock-based compensation, a non-cash expense, accounts for the majority of the increase in total general and administrative expenses.  The increase in stock-based compensation for the three months ended September 30, 2013 compared to the same period in 2012 is primarily due to restricted stock and restricted performance units granted during 2013.

	2013		2012		Increase
General and administrative expenses
(in thousands)
Stock-based compensation	$	325	$	112	$	213
Other general and administrative expenses		941		921		20
Total general and administrative expenses	$	1,266	$	1,033	$	233

21

Interest expense- Interest expense decreased from approximately $276,000 for the three months ended September 30, 2012 to approximately $157,000 for the three months ended September 30, 2013 primarily due to lower average debt balances and lower interest rates during the three months ended September 30, 2013 compared to the same period in 2012.

In the third quarter of 2013, the Company’s effective interest rate was reduced as a result of an amendment to its credit agreement whereby the Company’s loans under the credit agreement were no longer subject to the minimum interest floor of 4.5% per annum for LIBOR tranches commencing after July 25, 2013 and loan amounts subject to the Alternate Base Rate after July 31, 2013.

22

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

	Nine Months Ended
	September 30,						Percent
(in thousands except per unit data)	2013			2012			Change
Revenue:
Oil and natural gas sales	$	13,143		$	7,909			66	%
Commodity derivative loss		( 190	)		( 8	)		*
Other income		325			250			30	%
Total revenues		13,278			8,151			63	%
Expenses:
Lease operating expenses		1,914			1,584			21	%
Transportation costs		1,162			1,294			(10	%)
Production and property taxes		965			554			74	%
General and administrative		3,760			3,310			14	%
Depreciation, depletion and amortization		2,069			2,450			(16	%)
Accretion of asset retirement obligations		103			76			36	%
Impairment of oil and gas properties		-			15,407			*
Total expenses		9,973			24,675			(60	%)
Operating income (loss)	$	3,305		$	(16,524	)		(120	%)
Other income and (expense):
Interest expense		( 470	)		( 599	)		22	%
Equity investment loss		( 77	)		( 1	)		*
Total other income and (expense)	$	( 547	)	$	( 600	)		9	%
Production data:
Natural gas (Mcf)		1,684,203			1,800,111			(6	%)
Oil and liquids (Bbl)		70,781			32,180			120	%
Combined (Mcfe)		2,108,889			1,993,191			6	%
Average prices before effects of hedges:
Natural gas (per Mcf)	$	3.77		$	2.80			35	%
Oil and liquids (per Bbl)	$	96.02		$	89.21			8	%
Combined (per Mcfe)	$	6.23		$	3.97			57	%
Average prices after effects of hedges:**
Natural gas (per Mcf)	$	3.86		$	2.77			39	%
Oil and liquids (per Bbl)	$	91.16		$	90.83			0	%
Combined (per Mcfe)	$	6.14		$	3.96			55	%
Average costs (per Mcfe):
Lease operating expenses	$	0.91		$	0.79			15	%
Transportation costs	$	0.55		$	0.65			(15	%)
Production and property taxes	$	0.46		$	0.28			64	%
Depreciation, depletion and amortization	$	0.98		$	1.23			(20	%)
*Not meaningful or applicable
** Includes realized and unrealized commodity derivative gains and losses.

Oil and natural gas revenues- Revenues from sales of natural gas and oil and liquids increased 66% to approximately $13.1 million for the nine months ended September 30, 2013 from approximately $7.9 million for the nine months ended September 30, 2012.  This increase was primarily due to a 137% increase in oil revenues attributed to the Company’s focus on developing its oil properties.  Oil sales volumes and average oil prices for the first nine months of 2013 increased over the first nine months of 2012 120% and 8%, respectively.  Natural gas sales in the first nine months of 2013 increased 26% over the first nine months in 2012 due to a 35% increase in natural gas prices offset, in part, by a 6% decrease in natural gas sales volumes.

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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 natural gas and oil production are sufficient to warrant hedging to ensure predictable cash flows for certain of the Company’s production.  Because we do not designate these derivatives as cash flow hedges, they do not receive hedge accounting treatment and all mark-to-market gains or losses, as well as realized gains or losses on the derivative instruments, are currently recognized in our results of operations.  The unrealized gains and losses represent the changes in the fair value of these swap agreements as natural gas and oil futures prices fluctuate compared to the fixed price we will receive from these swap agreements.  For the nine months ended September 30, 2013 and 2012, we had hedging losses of approximately $190,000 and $8,000, respectively.

Lease operating expenses- Lease operating expenses for the nine months ended September 30, 2013 increased 21% in the first nine months of 2013 compared to the first nine months of 2012. On a per Mcfe basis, lease operating expenses increased from $0.79 per Mcfe for the nine months ended September 30, 2012 to $0.91 per Mcfe for the nine months ended September 30, 2013 primarily due to the increase in oil production relative to natural gas. Operating costs for oil producing properties are generally higher than for gas producing properties due to various factors including water disposal, well maintenance and other costs associated with oil producing properties.

Transportation costs- Transportation costs decreased from approximately $1.3 million for the nine months ended September 30, 2012 to approximately $1.2 million for the nine months ended September 30, 2013.  On a per Mcfe basis, these expenses decreased from $0.65 per Mcfe for the nine months ended September 30, 2012 to $0.55 per Mcfe for the nine months ended September 30, 2013.  Due to the close geographical proximity to delivery points, the Company incurs minimal transportation costs on its 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 $554,000 for the nine months ended September 30, 2012 to approximately $965,000 for the nine months ended September 30, 2013.  This increase is attributed primarily to increased revenue from the Company’s oil production and increased natural gas revenues due to an increase in natural gas prices.

Depreciation, depletion and amortization (DD&A)- DD&A decreased from approximately $2.5 million for the nine months ended September 30, 2012 to approximately $2.1 million for the nine months ended September 30, 2013 due to lower depletion rates.   On a per Mcfe basis, DD&A expenses decreased from $1.23 per Mcfe for the nine months ended September 30, 2012 to $0.98 per Mcfe for the nine months ended September 30, 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 expense for the nine months ended September 30, 2013.  For the nine months ended September 30, 2012, the Company recognized a non-cash impairment expense of approximately $15.4 million principally due to a decline in natural gas prices in 2012.

General and administrative expenses- General and administrative expenses for the nine months ended September 30, 2013 increased $450,000 or 14%, from the nine months ended September 30, 2013.  As shown in the table below, additional stock-based compensation, a non-cash expense, accounts for the majority of the increase in total general and administrative expenses.  The increase in stock-based compensation for the nine months ended September 30, 2013 compared to the same period in 2012 is primarily due to restricted stock and restricted performance units granted during 2013.

	2013		2012		Increase
(in thousands)
Stock-based compensation	$	641	$	328	$	313
Other general and administrative expenses		3,119		2,982		137
General and administrative expense, net	$	3,760	$	3,310	$	450

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Interest expense- Interest expense decreased from approximately $599,000 for the nine months ended September 30, 2012 to approximately $470,000 for the nine months ended September 30, 2013. This decrease is attributed to lower average debt balances and interest rates in the nine month period of 2013 as compared to the same period in 2012.

Liquidity and Capital Resources

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

Changes in the market prices for oil and natural gas directly impact our level of cash flow generated from operations.  For the nine months ended September 30, 2013 and 2012, natural gas made up approximately 80% and 90%, respectively, of our hydrocarbon production and approximately 48% and 64%, respectively, of our oil and gas revenues.  Oil and liquids made up approximately 20% and 10%, respectively, of our hydrocarbon production and approximately 52% and 36%, respectively, of our oil and gas revenues.

We employ a commodity hedging strategy in an attempt to moderate the effects of fluctuations in commodity prices on our cash flow. As of September 30, 2013, we have outstanding hedges of 170,000 MMbtu for the remainder of 2013 at an average price of $3.88 per MMbtu, 640,000 MMbtu for 2014 at an average price of $4.03 per MMbtu and 40,000 MMBtu for 2015 at an average price of $3.83 per MMBtu in addition to oil hedges of 15,000 barrels for the remainder of 2013 at an average price of $94.27 per barrel and 27,000 barrels for 2014 at an average price of $93.13 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 through 2015.  However, future hedging activities may result in reduced income or even financial losses to us. See “Risk Factors— Our 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 September 30, 2013, our derivative counterparty, or its affiliates, was party to our credit facility.
 

The other primary source of liquidity is our U.S. credit facility (described below), which had an aggregate borrowing base of $20.0 million at September 30, 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 substantially all of our assets and matures in May 2017. See—“Bank Credit Facility” below for further details. We had approximately $13.0 million drawn on our credit facility as of September 30, 2013.

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 and $7.0 million of funds available under our credit facility at September 30, 2013 will be sufficient to fund our normal recurring operating needs, anticipated capital expenditures (other than potential material acquisitions of additional natural gas and oil properties), and our contractual obligations.  However, if our revenue and cash flow decrease further in the future as a result of deterioration in domestic and globaleconomic 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.

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Bank Credit Facility

Nytis LLC has a bank credit facility which consists of a $50.0 million credit facility (the “Credit Facility”) with Bank of Oklahoma. The Credit Facility will mature in May 2017 and is guaranteed by Nytis USA and Carbon. Our availability under the Credit Facility is governed by a borrowing base (the “Borrowing Base”), which at September 30, 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 oil and natural gas properties in accordance with the lender’s customary practices for oil and natural gas loans. The available borrowing amount under the Credit Facility could increase or decrease based on such redetermination. The next redetermination of the Borrowing Base is expected to occur in November 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.  Prior to July 2013, for all outstanding debt, regardless if the loan was based on the Alternative Base Rate or LIBOR, there was a minimum floor of 4.5% per annum.  In June 2013, the Company and Bank of Oklahoma amended the credit agreement whereby the Company’s loans under the credit agreement were no longer subject to the minimum interest rate floor for LIBOR tranches commencing after July 25, 2013 and loan amounts subject to the Alternative Base Rate after July 31, 2013.

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 September 30, 2013 there was approximately $13.0 million in borrowings under the Credit Facility.  The Company’s effective borrowing rate at September 30, 2013 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.

In June 2013, the Company and Bank of Oklahoma amended the credit agreement (i) by extending the maturity date from May 2014 to May 2017, (ii) by removing the minimum interest rate floor of 4.5% per annum for LIBOR tranches commencing after July 25, 2013 and loan amounts subject to the Alternative Base Rate after July 31, 2013, and (iii) by increasing the maximum line of credit available under hedging arrangements from $8.0 million to $9.5 million.

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Historical Cash Flow

Net cash provided by or used in operating, investing and financing activities for the nine months ended September 30, 2013 and 2012 were as follows:

	Nine Months Ended
	September 30,
(in thousands)	2013				2012
Net cash provided by (used in) operating activities		$	5,098			$	( 552	)
Net cash (used in) investing activities		$	(6,050	)		$	(1,847	)
Net cash provided by financing activities		$	1,801			$	4,983

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 $5.6 million for the nine months ended September 30, 2013 as compared to the nine months ended September 30, 2012 was primarily due to increased operating income attributed to a 137% increase in oil revenues and increased natural gas prices.

Net cash used in investing activities increased by approximately $4.2 million for the nine months ended September 30, 2013 compared to the nine months ended September 30 2012.  This increase is the result of  higher capital expenditures in 2013.  During the third quarter of 2012, the Company received approximately $3.7 million in connection with the Liberty Participation Agreement which served to reduce the net cash used in investing activities during the nine months ended September 30, 2012.

The decrease in financing cash flows of approximately $3.2 million for the nine months ended September 30, 2013 as compared to the nine months ended September 30, 2012 was primarily due to lower borrowings required to fund the Company’s capital expenditures.  In the first nine months of 2013, the Company generated and utilized operating cash flows to fund a significant portion of its capital expenditures which, in turn, reduced the amount funded by debt.
 

Capital Expenditures

Capital expenditures for the nine months ended September 30, 2013 and 2012 are summarized in the following table:

	Nine Months Ended September 30,
(in thousands)	2013		2012
Acquisition of oil and gas properties:
Unevaluated properties	$	836	$	350
Proved producing properties		563		269
Drilling and development		4,598		4,665
Pipeline and gathering		-		227
Other		143		51
Total capital expenditures	$	6,140	$	5,562

Due to the Company’s focus on the development of its oil reserves and reduced natural gas prices since 2010, 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 nine months ended September 30, 2013 and 2012.  In addition, we managed our capital expenditures by keeping our exploration and development capital spending near our cash flows.  The Company has the ability to manage its capital expenditures as it controls and operates substantially all the wells in which it has an interest.  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.

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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 September 30, 2013, the off-balance sheet arrangements and transactions that we have entered into include (i) operating lease agreements and (ii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as natural gas transportation commitments and (iii) natural gas physical delivery contracts that are not expected to be net cash settled and are considered to be normal sales contracts and not derivatives. We do not believe that any of these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.

Non-GAAP Measures

EBITDA and Adjusted EBITDA

“EBTIDA” and “Adjusted EBITDA” are non-GAAP financial measures.  We define EBITDA as net income (loss) before interest expense, taxes, depreciation, depletion and amortization.  We define Adjusted EBITDA as EBITDA prior to accretion of asset retirement obligations, ceiling test write downs of oil and gas properties and the gain or loss on sold investments or properties.  EBITDA and Adjusted EBITDA is consolidated including non-controlling interests and as used and defined by us, may not be comparable to similarly titled measures employed by other companies and are not measures of performance calculated in accordance with GAAP.  EBITDA and Adjusted EBITDA should not be considered in isolation or as a substitute for operating income, net income or loss, cash flow 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 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 and nine months ended September 30, 2013 and 2012:

	Three Months Ended
	September 30,
(in thousands)	2013		2012
Net income (loss)	$	1,294	$	(310	)
Adjustments:
Interest expense		157		276
Depreciation, depletion and amortization		767		588
EBITDA		2,218		554
Adjusted EBITDA
EBITDA		2,218		554
Adjustments:
Accretion of asset retirement obligations		36		24
Adjusted EBITDA	$	2,254	$	578

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	Nine Months Ended
	September 30,
(in thousands)	2013		2012
Net income (loss)	$	2,758	$	(17,124	)
Adjustments:
Interest expense		470		599
Depreciation, depletion and amortization		2,069		2,450
EBITDA		5,297		(14,075	)
Adjusted EBITDA
EBITDA		5,297		(14,075	)
Adjustments:
Accretion of asset retirement obligations		103		76
Impairment of oil and gas properties		-		15,407
Adjusted EBITDA	$	5,400	$	1,408

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 and certain foreign locations where we conduct business operations.

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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 gas. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading "Risk Factors" included or incorporated in our Annual Report filed on Form 10-K with the SEC.

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

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

ITEM 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

As required by Rule 13a - 15(b) under the Securities Exchange Act of 1934 as amended (the "Exchange Act"), we have evaluated under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rules 13a - 15(e) and 15d-15(e) under the Exchange Act as of September 30, 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 September 30, 2013.

Changes in Internal Control over Financial Reporting

There has not been any change in our internal control over financial reporting that occurred during the three month period ended September 30, 2013 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 production 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 Proceeds

None.

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.
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

† Filed herewith, but 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: November 13, 2013	By:	/s/ Patrick R. McDonald
		PATRICK R. MCDONALD,
		Chief Executive Officer
Date: November 13, 2013	By:	/s/ Kevin D. Struzeski
		KEVIN D. STRUZESKI
		Chief Financial Officer

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