- Quarterly Report (10-Q)

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, 2012 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, 2012, there were issued and outstanding 115,795,405 shares of the Company’s common stock, $0.01 par value.

Carbon Natural Gas Company

TABLE OF CONTENTS

Part I – FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements

	Consolidated Balance Sheets (unaudited)	3

	Consolidated Statements of Operations (unaudited)	4

	Consolidated Statements of Stockholders’ Equity (unaudited)	5

	Consolidated Statements of Cash Flows (unaudited)	6

	Notes to the Consolidated Financial Statements (unaudited)	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

Item 4.	Controls and Procedures	33

Part II – OTHER INFORMATION

Item 1.	Legal Proceedings	34

Item 2.	Unregistered Sales of Equity Securities & Proceeds	34

Item 6.	Exhibits	34

PART I. FINANCIAL INFORMATION

ITEM 1.

Financial Statements

CARBON NATURAL GAS COMPANY

Consolidated Balance Sheets

	September 30, 2012			December 31, 2011
(in thousands)	(Unaudited)
ASSETS

Current assets:
Cash and cash equivalents	$	3,057		$	473
Accounts receivable:
Revenue		1,971			1,815
Joint interest billings and other		609			713
Firm transportation contract obligations (note 13)		969			1,019
Due from related parties (note 14)		543			228
Prepaid expense, deposits and other current assets		151			85
Derivative assets		-			308
Total current assets		7,300			4,641

Property and equipment, at cost (note 5)
Oil and gas properties, full cost method of accounting:
Proved, net		32,038			48,890
Unevaluated		948			1,369
Other property and equipment, net		264			287
		33,250			50,546

Investments in affiliates (note 6)		1,213			1,126
Other long-term assets		1,002			1,869

Total assets	$	42,765		$	58,182

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable and accrued liabilities	$	4,015		$	5,856
Firm transportation contract obligations (note 13)		2,550			2,681
Derivative liability		130			-
		6,695			8,537

Non-current liabilities:
Asset retirement obligation (note 2)		2,280			2,149
Firm transportation contract obligations (note 13)		2,203			4,096
Notes payable (note 7)		13,788			8,758
Total non-current liabilities		18,271			15,003

Commitments (note 13)

Stockholders’ equity:
Preferred stock, $0.01 par value; authorized 1,000,000 shares,
no shares issued and outstanding at September 30, 2012 and December 31, 2011		-			-
Common stock, $0.01 par value; authorized 200,000,000 shares, 115,795,405
and 114,185,405 shares issued and outstanding at September 30, 2012 and December 31, 2011, respectively		1,142			1,142
Additional paid-in capital		54,239			53,922
Non-controlling interests		3,106			4,884
Accumulated deficit		(40,688	)		(25,306	)
Total stockholders’ equity		17,799			34,642

Total liabilities and stockholders’ equity	$	42,765		$	58,182

See accompanying notes to consolidated financial statements.

CARBON NATURAL GAS COMPANY

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands except per share amounts)	2012			2011			2012			2011

Revenue:
Oil and gas	$	2,692		$	3,387		$	7,909		$	5,894
Commodity derivative gain (loss)		(149	)		156			(8	)		281
Other income		142			290			250			480
Total revenue		2,685			3,833			8,151			6,655

Expenses:
Lease operating expenses		490			625			1,584			1,314
Transportation costs		350			469			1,294			742
Production and property taxes		205			213			554			410
General and administrative		1,033			1,182			3,310			3,771
Depreciation, depletion and amortization		588			914			2,450			1,661
Accretion of asset retirement obligations		24			60			76			71
Impairment of oil and gas properties		-			3,825			15,407			12,204
Total expenses		2,690			7,288			24,675			20,173

Operating loss		(5	)		(3,455	)		(16,524	)		(13,518	)

Other income and (expense):
Interest expense		(276	)		(131	)		(599	)		(323	)
Loss on disposition of fixed asset		-			-			-			(12	)
Equity investment (loss) income		(29	)		(36	)		(1	)		4
Other expenses		-			(450	)		-			(450	)
Total other income and (expense)		(305	)		(617	)		(600	)		(781	)

Loss before income taxes		(310	)		(4,072	)		(17,124	)		(14,299	)

Provision for income taxes		-			-			-			-

Net loss before non-controlling interests		(310	)		(4,072	)		(17,124	)		(14,299	)

Net loss attributable to non-controlling interests		58			844			1,742			947

Net loss attributable to controlling interest	$	(252	)	$	(3,228	)	$	(15,382	)	$	(13,352	)

Net loss per common share:
Basic	$	(0.00	)	$	(0.03	)	$	(0.14	)	$	(0.20	)
Diluted	$	(0.00	)	$	(0.03	)	$	(0.14	)	$	(0.20	)
Weighted average common shares outstanding:
Basic		112,228			107,880			112,228			66,643
Diluted		112,228			107,880			112,228			66,643

See accompanying notes to consolidated financial statements.

CARBON NATURAL GAS COMPANY

Consolidated Statement of Stockholders’ Equity

(Unaudited)

(in thousands)


					Additional			Non-						Total
	Common Stock				Paid-in			Controlling			Accumulated			Stockholders’
	Shares		Amount		Capital			Interests			Deficit			Equity

Balances, December 31, 2011		114,185	$	1,142	$	53,922		$	4,884		$	(25,306	)	$	34,642

Stock based compensation		-		-		328			-			-			328

Restricted stock issued		1,610		-		-			-			-			-

Other		-		-		(11	)		-			-			( 11	)

Non-controlling interests
distributions		-		-		-			(36	)		-			( 36	)

Net loss		-		-		-			(1,742	)		(15,382	)		(17,124	)


Balances, September 30, 2012		115,795	$	1,142	$	54,239		$	3,106		$	(40,688	)	$	17,799

See accompanying notes to consolidated financial statements.

CARBON NATURAL GAS COMPANY

Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended
	September 30,
(in thousands)	2012			2011

Cash flows from operating activities:
Net loss	$	(17,124	)	$	(14,299	)
Items not involving cash:
Depreciation, depletion and amortization		2,450			1,661
Accretion of asset retirement obligations		76			71
Loss on disposition of fixed asset		-			12
Impairment of oil and gas properties		15,407			12,204
Unrealized derivative loss (gain)		438			(47	)
Stock-based compensation expense		328			-
Equity investment loss (income)		1			(4	)
Net change in:
Accounts receivable		717			(2,201	)
Prepaid expenses, deposits and other current assets		(66	)		(55	)
Accounts payable, accrued liabilities and firm transportation contracts		(2,464	)		2,865
Due from related parties		(315	)		(3,090	)
Net cash used in operating activities		( 552	)		(2,883	)

Cash flows from investing activities:
Development of properties and equipment		(5,562	)		(3,078	)
Proceeds from participation agreement		3,655			-
Cash paid for acquired properties		-			(27,058	)
Equity method investment		(87	)		(48	)
Other long-term assets		147			(48	)
Net cash used in investing activities		(1,847	)		(30,232	)

Cash flows from financing activities:
Issue common stock		-			30,000
Offering costs		(11	)		(1,808	)
Treasury share purchase		-			(152	)
Proceeds from notes payable		5,030			12,192
Payments on notes payable		-			(6,800	)
Distributions to non-controlling interests		(36	)		-
Net cash provided by financing activities		4,983			33,432

Net increase in cash and cash equivalents		2,584			314

Cash and cash equivalents, beginning of period		473			845

Cash and cash equivalents, end of period	$	3,057		$	1,159

See accompanying notes to consolidated financial statements.

CARBON NATURAL GAS COMPANY

NOTES TO UNAUDITED

CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Organization

Carbon Natural Gas Company (“Carbon”) is an independent oil and gas company engaged in the exploration, development and production of oil and natural gas in the United States. The Company was formed as the result of a merger with St. Lawrence Seaway Corporation (“SLSC”) and Nytis Exploration (USA) Inc. (“Nytis USA”) in February 2011. The Company’s business is comprised of the assets and properties of Nytis USA and its subsidiaries Nytis Exploration Company LLC (“Nytis LLC”) and Nytis Exploration of Pennsylvania LLC (“Nytis Pennsylvania”) which conduct the Company’s operations in the Appalachian and Illinois Basins. Subsequent to the merger, the Company believed that the continued use of the name St. Lawrence Seaway Corporation might result in market confusion regarding the Company’s current planned operations and business objectives. The Company believed the name “Carbon Natural Gas Company” was more descriptive of the business operations in which the Company engages. This action was implemented by filing an Amended and Restated Certificate of Incorporation with the State of Delaware which became effective May 2, 2011. Collectively, SLSC, Carbon, Nytis USA, Nytis LLC and Nytis Pennsylvania are referred to as the Company.

Note 2 – Summary of Significant Accounting Policies

Basis of Presentation

The accompanying unaudited consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of September 30, 2012, and the Company’s results of operations for the three and nine months ended September 30, 2012 and 2011, and the Company’s cash flows for the nine months ended September 30, 2012 and 2011. Operating results for the three and nine months ended September 30, 2012 and 2011 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, 2011 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 subsidiaries. The Company owns 100% of Nytis USA. Nytis USA owns 85% of Nytis Pennsylvania and approximately 98% of Nytis LLC. Nytis LLC also holds an interest in various oil and gas partnerships.

For partnerships where the Company has a controlling interest, the partnerships are consolidated. The Company 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 costs and expenses of the oil and gas partnerships in which the Company has a non-controlling interest. The Company is currently consolidating on a pro-rata basis 42 partnerships.

Note 2 – Summary of Significant Accounting Policies (continued)

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 equity method 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, 2012, based on oil prices of $91.97 per barrel and gas prices of $2.80 per Mcf, the Company’s full cost pool did not exceed the ceiling limitation. For the nine month period ended September 30, 2012, a non-cash impairment expense of approximately $15.4 million was recognized. During the nine months ended September 30, 2012, there was a reduction in oil and natural gas prices utilized in calculating the present value of future revenues from the Company’s proved gas reserves. The negative effects of the price declines were partially offset by additional proved undeveloped oil reserves booked during the same period. For the three and nine months ended September 30, 2011, the Company recorded a non-cash impairment expense of approximately $3.8 million and $12.2 million, respectively.

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 20% of the voting interests of a corporate affiliate or less than 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 the investment is made annually to determine if a decline in the fair value of the investment, other than temporary, has occurred. A permanent impairment is recognized if a decline in the fair value occurs. If the Company holds between 20% and 50% of the voting interest in non-consolidated corporate affiliates or greater than 5% of a partnership or limited liability company and exercises significant influence or control, the equity method of accounting is used to account for the investment. The Company’s investment in an affiliate that is accounted for using the equity method of accounting 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.

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, 2012 and 2011:


	Nine Months Ended September 30,
(in thousands)	2012		2011
Balance at beginning of period	$	2,149	$	352
Accretion expense		76		71
Additions assumed with acquired properties		-		1,581
Additions during period		55		121

Balance at end of period	$	2,280	$	2,125

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). As a result of the reverse merger with SLSC on February 14, 2011, the number of common shares outstanding from the beginning of the periods presented in the accompanying consolidated financial statements to the merger date were computed on the basis of the weighted-average number of common shares of Nytis USA outstanding during the respective periods multiplied by the exchange ratio established in the merger agreement, which was approximately 1,631 common shares of SLSC for each common share of Nytis USA. The weighted average number of shares used in the earnings per share calculations were based on historical weighted-average number of common shares outstanding multiplied by the exchange ratio. The number of common shares outstanding from the merger date to September 30, 2012 is the actual number of common shares of the Company outstanding during that period.

At September 30, 2012 and 2011, the Company had common stock equivalents of 4,856,912 and 2,134,257 respectively, which are excluded from the calculation of diluted loss per share as the effect would be anti-dilutive.

Note 3 – Reverse Merger

On February 14, 2011, pursuant to an Agreement and Plan of Merger ("Merger Agreement") by and among 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. Per the terms of the Merger Agreement, in exchange for all the outstanding common shares of Nytis USA, SLSC issued 47,000,003 shares of common stock of SLSC (restricted under SEC Rule 144) which represented an exchange ratio of approximately 1,631 shares of SLSC for each share of Nytis USA.

For accounting purposes, the business combination was considered a "reverse merger" in which Nytis USA was considered the accounting acquirer. The combination was recorded as a recapitalization under which SLSC issued shares in exchange for the net assets of Nytis USA. The assets of Nytis USA were recorded at their respective book value and were not adjusted to their estimated fair value. No goodwill or other intangible assets were recorded in the transaction.

All share amounts, including those for which any securities are exercisable or convertible, have been adjusted to reflect the conversion ratio used in the merger. In addition, stockholders’ equity and earnings per share have been retroactively restated to reflect the number of shares of SLSC common stock received by Nytis USA stockholders in the merger. The financial results prior to the merger were those of Nytis USA. Also, as a result of the completion of the merger, SLSC amended its bylaws to change the fiscal year of the Company from March 31 to December 31.

Note 4– Acquisitions and Divestitures

On September 17, 2012, Nytis LLC entered into a Participation Agreement (the “Participation Agreement”) with Liberty Energy LLC (“Liberty”), a Massachusetts limited liability company that will permit Liberty to participate with Nytis LLC in the drilling and completion of wells on certain of Nytis LLC’s leases located in Kentucky.

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

Note 4– Acquisitions and Divestitures (continued)

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

As the transaction did not significantly alter the relationship between capitalized costs and proved reserves, the Company did not recognize a gain or loss. The proceeds from the Participation Agreement were recorded as a reduction of the Company's investment in its oil and gas properties and were used to reduce outstanding borrowings under the Company's bank credit facility (see Note 7).

ING Asset Acquisition

On April 22 and June 29, 2011, Nytis LLC effected an initial and subsequent close, respectively, under a February 14, 2011 Asset Purchase Agreement, as amended (the “ING APA”) with The Interstate Natural Gas Company, LLC and certain related parties, as seller (hereafter collectively referred to as “ING”), of certain gas and oil assets (the “ING Assets”). The initial closing was held on April 22, 2011 for the purchase of approximately 45 natural gas wells for approximately $1.5 million. The subsequent closing was held on June 29, 2011 for the purchase of the remaining assets consisting of interests in approximately 385 producing wells (total 430 producing wells), natural gas gathering and compression facilities and other related assets, for approximately $23.2 million. The Company paid a total of approximately $25.9 million cash for the ING Assets which included additional purchase price adjustments and $600,000 consideration for extending the date of the final closing.

The Company acquired these assets to obtain proved developed producing reserves that were proximate and complimentary to the Company’s then current production and reserve base. The ING Assets consisted of certain natural gas properties, natural gas gathering and compression facilities and other related assets located in eastern Kentucky and four counties in West Virginia. Specifically, the ING Assets included (i) some but not all of ING’s leases and interests in natural gas and oil leases, wells and wellbores and related natural gas production equipment; (ii) partnership interests in various general partnerships that own comparable natural gas and oil assets as to which ING was the managing general partner and where Nytis LLC succeeded to ING’s position as managing general partner, (iii) partnership interests in other general partnerships in which ING owned partnership interests but was not the managing general partner; (iv) natural gas gathering and compression facilities related only to the acquired properties; and (v) various other contracts, and insignificant amounts of vehicles, equipment, easements and rights-of-way relating to or used in connection with the ownership and operation of the ING assets.

Nytis LLC assumed certain obligations to transport gas from wells that are owned by ING (or its affiliates) that Nytis LLC did not acquire, as well as obligations under other contracts and agreements that Nytis LLC acquired at the final closing.

The ING acquisition 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).

ING Asset Acquisition Pro Forma

As stated above, on June 29, 2011, the Company completed an acquisition of oil and gas properties from ING. Below are consolidated results of operations for the nine months ended September 30, 2011 as though the ING acquisition had been completed as of January 1, 2011.

The unaudited pro forma consolidated results reflect significant pro forma adjustments related to funding the acquisition through the issuance of common stock, additional depreciation expense, costs directly attributable to the acquisition and costs incurred as a result of the merger with SLSC.

Note 4– Acquisitions and Divestitures (continued)

	Unaudited Pro Forma Consolidated Results
	For Nine Months Ended
	September 30, 2011
(in thousands, except share data)

Revenue	$	11,453

Net loss before non-controlling interests	$	(11,559	)

Net income attributable to non-controlling interests	$	499

Net loss attributable to controlling interests	$	(11,060	)

Net loss per share (basic)	$	(0.17	)
Net loss per share (diluted)	$	(0.17	)

Alerion Drilling I, LLC Asset Acquisition

Prior to the final closing of the ING APA, a portion of the ING Assets acquired by Nytis LLC from ING were held in the Alerion Partnership. ING’s interest in the Alerion Partnership was fifty percent (50%) and the remaining interest of the Alerion Partnership was owned by Alerion Drilling. Immediately prior to the ING final closing, ING and Alerion Drilling distributed all the assets of the Alerion Partnership to ING and Alerion Drilling, including the portion thereof (the “Alerion Partnership Assets”) that Nytis LLC purchased from ING under the ING APA.

On June 6, 2011, Nytis LLC entered into an Asset Purchase Agreement with Alerion Drilling to acquire Alerion Drilling’s fifty percent (50%) interest in the Alerion Partnership Assets. On July 27, 2011, Nytis LLC closed the acquisition of Alerion’s interest in the Alerion Partnership Assets under the Alerion APA and, as a consequence acquired the remaining interest in the Alerion Partnership Assets that it had acquired from ING at the final closing. The purchase price paid by Nytis LLC for Alerion Drilling’s share of such assets was approximately $1.2 million including purchase price adjustments.

Note 5 – Property and Equipment

Net property and equipment as of September 30, 2012 and December 31, 2011 consists of the following:


(in thousands)	September 30, 2012			December 31, 2011

Oil and gas properties
Proved oil and gas properties	$	90,323		$	89,392
Unproved properties not subject to depletion		948			1,369
Accumulated depreciation, depletion, amortization and impairment		(58,285	)		(40,502	)
Net oil and gas properties		32,986			50,259

Furniture and fixtures, computer hardware and software, and other equipment		779			728
Accumulated depreciation and amortization		(515	)		(441	)
Net other property and equipment		264			287

Total net property and equipment	$	33,250		$	50,546

Note 5 – Property and Equipment (continued)

As of September 30, 2012 and December 31, 2011, the Company had approximately $948,000 and $1.4 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 $400,000 and $341,000 for the nine months ended September 30, 2012 and 2011, respectively.

Depletion expense related to oil and gas properties for the three and nine months ended September 30, 2012 was approximately $562,000, or $0.85 per equivalent Mcfe, and approximately $2.4 million, or $1.19 per equivalent Mcfe, respectively, and approximately $900,000 or $1.34 per equivalent Mcfe, and approximately $1.6 million or $1.37 per equivalent Mcfe for the three and nine months ended September 30, 2011, respectively. Oil and natural gas property ceiling test impairments of approximately nil and $15.4 million were recognized for the three and nine months ended September 30, 2012, respectively, and approximately $3.8 million and $12.2 million for the three and nine months ended September 30, 2011, respectively. Depreciation and amortization expense related to furniture and fixtures, computer hardware and software and other equipment for the nine months ended September 30, 2012 and 2011 was approximately $74,000 and $32,000, respectively.

Note 6 – 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, 2012 and 2011, the Company recorded a loss of approximately $1,000 and income of $4,000 respectively, related to this investment.

In the fourth quarter of 2010, the Company acquired a 17.5% ownership in Sullivan Energy Ventures LLC (“Sullivan”). At that time, the Company determined that it had the ability to significantly influence the operating decisions of Sullivan and accounted for its ownership in Sullivan by recording the Company’s pro-rata share of Sullivan's financial results. During the second quarter of 2011, it became evident that the Company did not have the ability to significantly influence the decisions of Sullivan. As a result, the Company reclassified its investment in Sullivan to Investments in Affiliates in the accompanying consolidated balance sheets at the net investment value of approximately $463,000 and began to account for this investment using the cost method of accounting. The Company’s standardized reserve disclosures at December 31, 2010 included approximately $796,000 and 663,000 Mcf of reserves related to Sullivan. For the three months ended March 31, 2011, the Company would have recorded an additional oil and gas asset impairment expense of approximately $280,000 if the Sullivan reserves and related property balance had not been included in the ceiling test calculation. Because this was a new entity, revenues and expenses recorded related to Sullivan were deminimus during 2010 and the first quarter of 2011.

Note 7 – Bank Credit Facility

Nytis LLC’s credit facility with Bank of Oklahoma which matures on May 2014 has a borrowing base of $20.0 million and a maximum line of credit available under hedging arrangements of $8.0 million. Carbon is a guarantor of Nytis LLC’s obligations under its credit facility.

No repayments of principal are required until maturity, except to the extent that outstanding balances exceed the borrowing base then in effect; however, the Company has the right both to repay principal at any time and to reborrow. Subject to the agreement of the Company and the lender, the size of the credit facility may be increased up to $50.0 million. The borrowing base is redetermined semi-annually, and the available borrowing amount could be increased or decreased as a result of such redeterminations. Under certain circumstances the lender may request an interim redetermination. The facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base. Interest rates are based on either an Alternate Base Rate or LIBOR. The portion of the loan based on an “Alternate Base Rate” is determined by the rate per annum equal to 1.5% plus the greatest of the following: (a) the Federal Funds Rate for such day plus one-half of one percentage point, (b) the Prime Rate for such day or (c) LIBOR for a one-month LIBOR Interest Period plus one percentage point. The portion based on LIBOR is determined by the rate per annum equal to LIBOR plus between 2.5% and 3.25% for each LIBOR tranche. For all debt outstanding regardless if the loan is based on the Alternative Base Rate or LIBOR, there is a minimum floor of 4.5% per annum. The credit facility includes a hedging component that provides a line of credit under commodity swap, exchange, collar, cap and fixed price agreements and agreements designated to protect the Company against changes in interest and currency exchange rates.

Note 7 – Bank Credit Facility (continued)

At September 30, 2012, there were approximately $13.8 million in outstanding borrowings and approximately $6.2 million of additional borrowing capacity available under the credit facility. The Company’s effective borrowing rate at September 30, 2012 was 4.75%. The credit facility is collateralized by substantially all of the Company’s oil and gas assets. The credit facility includes terms that place limitations on certain types of activities and the payment of dividends, and requires satisfaction of a current ratio (the ratio of current assets (including borrowing base capacity) to current liabilities as defined) of 1.0 to 1.0 and a maximum Funded Debt Ratio (the ratio of the outstanding balance of all interest bearing indebtedness to the sum of EBITDAX (net income plus interest expense, income taxes, depreciation, depletion, amortization, exploration and impairment expenses and other non-cash charges) for the most recently completed fiscal quarter times four) of 4.25 to 1.0 as of the end of any fiscal quarter.

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

The Company is in compliance with all covenants associated with the credit agreement as of September 30, 2012.

Note 8 – 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.

At September 30, 2012, the Company has established a full valuation allowance against the balance of net deferred tax assets.

Note 9 – Stockholders’ Equity

Authorized and Issued Capital Stock

As of September 30, 2012, the authorized capital stock of Carbon was 201,000,000 shares, consisting of 200,000,000 shares of common stock with a par value of $0.01 per share and 1,000,000 shares of preferred stock with a par value of $0.01 per share.

Pursuant to the merger (see Note 3), the Company assumed 236,460 options, 2,696,133 warrants and 1,956,912 shares of restricted stock outstanding that were granted by Nytis USA and SLSC prior to the merger.

Also pursuant to the merger, Nytis USA was authorized, as manager, of Nytis LLC, to offer to redeem all unvested, forfeitable restricted membership interests pursuant to the Nytis LLC restricted membership interest plan. All of the restricted membership interests were redeemed in February 2011 for $300,000 and recorded as a general and administrative expense in the first quarter of 2011.

Note 9 – Stockholders’ Equity (continued)

Stock Incentive Plan

On December 8, 2011, the stockholders of Carbon approved the adoption of Carbon’s 2011 Stock Incentive Plan ("2011 Plan"), under which 12,600,000 shares of common stock were authorized for issuance to Carbon officers, directors, employees and consultants eligible to receive awards under the 2011 Plan.

The plan provides for granting Director Stock Awards to Non-Employee Directors and for granting Incentive Stock Options, Non-qualified Stock Options, Restricted Stock Awards, Performance Awards and Phantom Stock Awards, or a combination of the foregoing as is best suited to the circumstances of the particular employee, officer, director or consultant.

Restricted Stock

The Company granted 1,610,000 shares of restricted stock for the nine months ended September 30, 2012. Restricted stock awards for employees vest ratably over a three-year service period and one-year for non-employee directors. Compensation for restricted shares is measured at the grant date based on the fair value of the awards, determined by the closing price of the Company’s common stock on the grant date and the fair value is recognized on a straight line basis over the requisite service period (generally the vesting period).

Compensation cost recognized for restricted stock grants was approximately $112,000 and $328,000 for the three and nine months ended September 30, 2012, respectively. As of September 30, 2012, there was approximately $669,000 of total unrecognized compensation costs related to restricted stock. This cost is expected to be recognized over the next 2.3 years.

Restricted Performance Units

For the nine months ended September 30, 2012, the Company granted 1,290,000 restricted performance units. The performance units represent a contractual right to receive one share of the Company’s common stock subject to the terms and conditions of the agreement including the relative achievement of the performance and the lapse of forfeiture restrictions pursuant to the terms and conditions of the agreement. The Company accounts for grants of restricted performance units at their fair value, re-measured at each reporting period. The final measurement of compensation costs is based on the performance units that ultimately vest and the market price at the date the performance criteria are met. At September 30, 2012, the Company estimated that none of the performance units would vest and accordingly, no compensation cost has been recorded. As of September 30, 2012, if all performance goals are achieved and forfeiture restrictions pursuant to the terms and conditions of the agreement are met, estimated unrecognized compensation cost would be approximately $593,000.

Note 10 – Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities at September 30, 2012 and December 31, 2011 consist of the following:


(in thousands)	September 30, 2012		December 31, 2011

Accounts payable	$	800	$	2,789
Oil and gas revenue payable to oil and gas property owners		1,647		964
Production taxes payable		94		43
Accrued drilling costs		283		190
Accrued lease operating costs		22		585
Accrued ad valorem taxes		457		395
Accrued general and administrative expenses		423		722
Other accrued liabilities		289		168

Total accounts payable and accrued liabilities	$	4,015	$	5,856

Note 11 – 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.

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, 2012 and December 31, 2011 by level within the fair value hierarchy:

	Fair Value Measurements Using
(in thousands)	Level 1		Level 2			Level 3		Total
September 30, 2012
Assets:
Commodity derivatives	$	-	$	105		$	-	$	105
Liabilities:
Commodity derivatives	$	-	$	235		$	-	$	235
Net asset (liability)	$	-	$	( 130	)	$	-	$	( 130	)

December 31, 2011
Assets:
Commodity derivatives	$	-	$	308		$	-	$	308

As of September 30, 2012, the Company’s commodity derivative financial instruments are comprised of three natural gas swap agreements and two oil swap agreements. The fair values of the swap agreements are determined under the income valuation technique using a discounted cash flow model. The valuation model requires a variety of inputs, including contractual terms, published forward prices, volatilities for options, and discount rates, as appropriate. The Company’s estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, the Company’s credit worthiness and the time value of money. The consideration of these factors 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.

Note 11 – Fair Value Measurements (continued)

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 12 – 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 gas physical delivery contracts to effectively provide gas price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded at fair value in the consolidated financial statements.

The Company has fixed price contracts requiring physical deliveries for October 2012 through October 2013 of approximately 37,500 MMBtu per month for an average sales price of $3.11 per MMBtu and for October and November 2013 of approximately 18,600 MMBtu per month for an average sales price of $3.24 per MMBtu.

At September 30, 2012, other than the above mentioned contracts, the Company’s other gas sales contracts approximate index prices.

The Company’s swap agreements as of September 30, 2012 are summarized in the table below:

Agreement Type	Remaining Term	Quantity	Fixed Price Counterparty Payer	Floating Price Nytis LLC Payer
Swap	10/12 - 12/12	10,000 MMBtu/month	$5.07/ MMBtu	(a)
Swap	10/12 - 3/13	40,000 MMBtu/month	$2.78/ MMBtu	(a)
Swap	1/13 – 12/13	10,000 MMBtu/month	$3.72/MMBtu	(a)
Swap	10/12 - 12/12	1,000 Bbl/month	$106.25/ Bbl	(b)
Swap	1/13 - 12/13	500 Bbl/month	$87.70/Bbl	(b)

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

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

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

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


(in thousands)	September 30, 2012			December 31, 2011
Derivative contracts:
Current assets	$	105		$	308
Current liabilities	$	235		$	-
Net derivative asset (liability)	$	( 130	)	$	308

Note 12 – Physical Delivery Contracts and Derivatives (continued)

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, 2012 and 2011. 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)	2012			2011		2012			2011
Commodity derivative contracts:
Realized gains	$	112		$	50	$	430		$	234
Unrealized (losses) gains		(261	)		106		(438	)		47

Total realized and unrealized (losses) gains, net	$	( 149	)	$	156	$	( 8	)	$	281

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

The counterparty in all of the Company’s derivative instruments is the lender in the Company’s bank credit facility; accordingly, the Company is not required to post collateral since the bank is secured by the Company’s oil and gas assets.

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

Note 13 – Commitments

The Company assumed long-term firm transportation contracts in the ING Asset acquisition. Capacity levels and related demand charges for the remaining term of the contracts at September 30, 2012 are (i) for the remainder of 2012 through 2013; approximately 7,700 dekatherms per day capacity with demand charges ranging between $0.22 and $1.40 per dekatherm, (ii) for 2014 through May 2015; 3,450 dekatherms per day with demand charges ranging between $0.22 and $0.65 and (iii) for June 2015 through 2017; 2,300 dekatherms per day with demand charges of $0.65 per dekatherm. A liability of approximately $4.8 million related to firm transportation contracts assumed in the ING Asset acquisition, which represents the remaining commitment, is reflected on the Company’s consolidated balance sheets as of September 30, 2012 .

In addition to the contracts assumed in the ING Asset acquisition, the Company has other long-term firm transportation contracts. Capacity and related demand charges for the remaining term of these contracts at September 30, 2012 are (i) for the remainder of 2012 through March 2013; 1,300 dekatherms per day with demand charges ranging from $0.22 to $0.80 per dekatherm and (ii) 1,000 dekatherms per day with demand charges of $0.22 from April 2013 through April 2036.

Note 14 – Related Party Transactions

The Company previously engaged Nytis Exploration Company (“NEC”) to assist in the management, direction and supervision of the operations and business functions of the Company. A service agreement between the Company, NEC and other related entities provided for the compensation of NEC in performing these duties. For the three and nine months ended September 30, 2011, NEC charged the Company approximately nil and $673,000, respectively, for general and administrative expenses pursuant to this service agreement.

The services agreement was terminated on June 30, 2011. Effective July 1, 2011, the parties entered into a new agreement whereby the Company manages, directs and supervises the operations and business of NEC and other related entities. The new agreement’s initial term was for one year and the agreement was terminated effective June 30, 2012. For the nine month period ended September 30, 2012, pursuant to the new service agreement, the Company charged NEC $90,000.

Note 14 – Related Party Transactions (continued)

As of September 30, 2012, NEC and the other related entities owe the Company approximately $817,000. This receivable consists primarily of charges incurred under the service agreement, short-term advances and reimbursement of other general and administrative expenses paid by Carbon. This receivable is reflected in accounts receivable related parties and other on the Company’s consolidated balance sheets.

Note 15 – Supplemental Cash Flow Disclosure

Supplemental cash flow disclosures for the nine months ended September 30, 2012 and 2011 are presented below:


	Nine Months Ended September 30,
	2012			2011
(in thousands)

Cash paid during the period for:
Interest payments	$	533		$	274

Non-cash transactions:
Increase in net asset retirement obligations due to additions	$	55		$	121
Various assets acquired and liabilities assumed in
acquisition (see Note 4)	$	-		$	6,623
Decrease in accounts payable and accrued liabilities
included in oil and gas properties	$	(1,402	)	$	(170	)
Offering costs included in accounts payable	$	-		$	236
Net assets transferred from oil and gas properties to investment
in affiliate	$	-		$	463

Note 16 – Subsequent Events

On October 1, 2012, the Company reduced the outstanding balance of its credit facility with the Bank of Oklahoma by approximately $2.4 million with proceeds from the Liberty Participation Agreement (see Note 4).

ITEM 2.

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

General Overview

All expectations, forecasts, assumptions and beliefs about our future results, condition, operations and performance are forward-looking statements as described under the heading “ Forward Looking Statements ” at the end of this Item. Our actual results may differ materially because of a number of risks and uncertainties. The following discussion and analysis should be read in conjunction with the Company’s Consolidated Financial Statements and Notes thereto and the information included or incorporated by reference in the Company’s 2011 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 .”

The Company 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’s business is comprised of the assets and properties of Nytis USA and its subsidiaries Nytis LLC and Nytis Pennsylvania which conduct the Company’s operations in the Appalachian and Illinois Basins. The Company focuses on conventional and unconventional reservoirs, including shale gas formations, tight gas sands and coalbed methane. Our corporate headquarters are in Denver, Colorado.

At December 31, 2011, 93% 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 recent capital expenditure programs, the Company is focused on developing its oil reserves while continuing to pursue acquisitions that complement our existing core programs. We believe that our drilling inventory, combined with our operating expense and cost structure, provides us with meaningful organic growth opportunities. Our growth plan is centered on the following activities:

●	Focusing primarily on the development of the Company’s oil reserves;

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

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

●	Continuing to seek property and land acquisitions that complement our core areas.

Our revenue, profitability and future growth rate depend on many factors which are beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and gas prices historically have been volatile and may fluctuate widely in the future. The following table highlights the quarterly average of NYMEX price trends for oil and natural gas prices since the first quarter of 2011:

	2011								2012
		Q1		Q2		Q3		Q4		Q1		Q2		Q3

Oil (Bbl)	$	94.25	$	102.55	$	89.81	$	94.02	$	102.94	$	93.51	$	92.19
Natural Gas (MMBtu)	$	4.10	$	4.32	$	4.20	$	3.54	$	2.72	$	2.22	$	2.81

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

Recent Developments

The Company drilled and completed two producing oil wells in each of the second and third quarters of 2012.

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, 2012 and 2011. 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, 2012 Compared to Three Months Ended September 30, 2011

	Three Months Ended
	September 30,
(in thousands except per unit data)	2012			2011
Revenue:
Oil and natural gas sales	$	2,692		$	3,387
Commodity derivative (loss) gain		(149	)		156
Other income		142			290
Total revenues		2,685			3,833

Expenses:
Lease operating expenses		490			625
Transportation costs		350			469
Production and property taxes		205			213
General and administrative		1,033			1,182
Depreciation, depletion and amortization		588			914
Accretion of asset retirement obligations		24			60
Impairment of oil and gas properties		-			3,825
Total expenses		2,690			7,288

Operating loss	$	(5	)	$	(3,455	)

Other income and (expense):
Interest expense		(276	)		(131	)
Equity investment income		(29	)		(36	)
Other expenses		-			(450	)
Total other income and (expense)	$	(305	)	$	(617	)

Production data:
Natural gas (MMcf)		595			644
Oil and liquids (MBbl)		11			5
Combined (MMcfe)		663			674

Average prices before effects of hedges:
Natural gas (per Mcf)	$	3.01		$	4.70
Oil and liquids (per Bbl)	$	79.87		$	71.82
Combined (per Mcfe)	$	4.06		$	5.03

Average prices after effects of hedges:
Natural gas (per Mcf)	$	2.85		$	4.94
Oil and liquids (per Bbl)	$	75.20		$	71.82
Combined (per Mcfe)	$	3.92		$	5.26

Average costs (per Mcfe):
Lease operating expenses	$	0.74		$	0.93
Transportation costs	$	0.53		$	0.70
Production and property taxes	$	0.31		$	0.32
Depreciation, depletion and amortization	$	0.89		$	1.36

Oil and natural gas sales - Revenues from sales of natural gas and oil and liquids decreased to $2.7 million for the three months ended September 30, 2012 from approximately $3.4 million for the three months ended September 30, 2011, a decrease of 21%. This decrease was primarily due to a 36% decrease in average natural gas prices which was partially offset by an increase in oil production together with a 6% increase in average oil prices. Oil production increased as a result of new oil production from oil wells drilled and completed in the second and third quarters of 2012.

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 or variable swap contracts when our management believes that favorable future sales prices for our natural gas and oil production can be secured. Because we do not designate these derivatives as cash flow hedges, they do not receive hedge accounting treatment and all mark-to-markets gains or losses, as well as realized gains or losses on the derivative instruments, are currently recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these swap agreements as the future strip prices fluctuate relative to the fixed price we will receive from these swap agreements. For the three months ended September 30, 2012 we had hedging losses of approximately $149,000 compared to hedging gains of approximately $156,000 for the three months ended September 30, 2011.

Lease operating expenses- Lease operating expenses decreased approximately 22% for the three months ended September 30, 2012 compared to the three months ended September 30, 2011. On a per Mcfe basis, lease operating expenses decreased from $0.93 per Mcfe for the three months ended September 30, 2011 to $0.74 per Mcfe for the three months ended September 30, 2012. During the third quarter of 2011, additional lease operating expenses were incurred due to major repairs to roads and well sites damaged by area flooding in Kentucky and West Virginia.

Transportation costs- Transportation costs decreased from approximately $469,000 for the three months ended September 30, 2011 to approximately $350,000 for the three months ended September 30, 2012 due to lower gas production caused, in part, by some natural gas wells shut-in. On a per Mcfe basis, these expenses decreased from $0.70 per Mcfe for the three months ended September 30, 2011 to $0.53 per Mcfe for the three months ended September 30, 2012 due primarily to the reversal of estimated transportation costs recorded during the three months ended June 30, 2012 for wells that were shut-in during certain portions of that period.

Production and property taxes- Production and property taxes decreased from approximately $213,000 for the three months ended September 30, 2011 to approximately $205,000 for the three months ended September 30, 2012. This decrease is attributed primarily decrease in taxable revenues. On a per Mcfe basis, these expenses decreased from $0.32 per Mcfe for the three months ended September 30, 2011 to $0.31 per Mcfe for the three months ended September 30, 2012.

Depreciation, depletion and amortization (DD&A)- DD&A decreased from approximately $914,000 for the three months ended September 30, 2011 to approximately $588,000 for the three months ended September 30, 2012 primarily due to a lower depletion rate. The Company’s depletable asset base was reduced by ceiling test impairments recognized in previous periods due to declining natural gas prices which also served to reduce the Company’s reserves. On a per Mcfe basis, DD&A decreased from $1.36 per Mcfe for the three months ended September 30, 2011 to $0.89 per Mcfe for the three months ended September 30, 2012.

Impairment of oil and gas properties- For the three months ended September 30, 2011, the Company recognized an impairment of approximately $3.8 million. The Company did not recognize an impairment for the three months ended September 30, 2012 as estimated development costs related to certain proved undeveloped reserves decreased in relation to the present value of future net revenues pursuant to terms of the Participation Agreement with Liberty (see Note 4) and certain proved reserves formerly carried by the Company that had positive undiscounted net revenues but had negative net revenues using a discount factor of 10%, were no longer recognized at September 30, 2012, as the undiscounted net revenues from those reserves were no longer positive due to a continued decline in the unweighted arithmetic average of the first-day-of-the-month natural gas prices used in the calculation of the present value of future net revenues at September 30, 2012. A decline in natural gas prices was the primary contributing factor causing the impairment in 2011. Additional impairments may be required in subsequent periods if among other things; the unweighted arithmetic average of the first-day-of-the-month natural gas and oil prices used in the calculation of the present value of future net revenue from estimated production of proved oil and gas reserves decline compared to prices used as of September 30, 2012, unproved property values decrease, estimated proved reserve volumes are revised downward or costs incurred in exploration, development, or acquisition activities exceed the discounted future net cash flows from additional reserves, if any.

General and administrative expenses- General and administrative expenses decreased 13% from approximately $1.2 million for the three months ended September 30, 2011 to approximately $1.0 million for the three months ended September 30, 2012. Included in 2012 general and administrative expenses is a non-cash expense of $112,000 for stock based compensation. In 2011, the Company incurred additional costs related to audit, legal and other administrative costs associated with the acquisition of oil and gas properties from ING and Alerion Drilling and merger related expenses.

The table below sets forth the components of general and administrative expenses for the three months ended September 30, 2012 and 2011.

	2012		2011
General and administrative expenses
(in thousands)
Stock based compensation	$	112	$	-
Other general and administrative expenses		921		1,182
Total general and administrative expenses	$	1,033	$	1,182

Interest expense - Interest expense increased from approximately $131,000 for the three months ended September 30, 2011 to approximately $276,000 for the three months ended September 30, 2012 primarily due to higher average debt balances during the three months ended September 30, 2012 compared to the same period in 2011.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

	Nine Months Ended
	September 30,
(in thousands except per unit data)	2012			2011
Revenue:
Oil and natural gas sales	$	7,909		$	5,894
Commodity derivative gain (loss)		(8	)		281
Other income		250			480
Total revenues		8,151			6,655

Expenses:
Lease operating expenses		1,584			1,314
Transportation costs		1,294			742
Production and property taxes		554			410
General and administrative		3,310			3,771
Depreciation, depletion and amortization		2,450			1,661
Accretion of asset retirement obligations		76			71
Impairment of oil and gas properties		15,407			12,204
Total expenses		24,675			20,173

Operating loss	$	(16,524	)	$	(13,518	)

Other income and (expense):
Interest expense		(599	)		(323	)
Loss on disposition of fixed asset		-			(12	)
Equity investment income		(1	)		4
Other expenses		-			(450	)
Total other income and (expense)	$	(600	)	$	(781	)

Production data:
Natural gas (MMcf)		1,800			1,140
Oil and liquids (MBbl)		32			8
Combined (MMcfe)		1,993			1,188

Average prices before effects of hedges:
Natural gas (per Mcf)	$	2.80		$	4.62
Oil and liquids (per Bbl)	$	89.21		$	78.41
Combined (per Mcfe)	$	3.97		$	4.96

Average prices after effects of hedges:
Natural gas (per Mcf)	$	2.77		$	4.87
Oil and liquids (per Bbl)	$	90.83		$	78.41
Combined (per Mcfe)	$	3.96		$	5.20

Average costs (per Mcfe):
Lease operating expenses	$	0.79		$	1.11
Transportation costs	$	0.65		$	0.62
Production and property taxes	$	0.28		$	0.35
Depreciation, depletion and amortization	$	1.23		$	1.40

Oil and natural gas sales - Revenues from sales of natural gas and oil and liquids increased to approximately $7.9 million for the nine months ended September 30, 2012 from approximately $5.9 million for the nine months ended September 30, 2011, an increase of 34%. This increase was primarily due to revenues received from oil and gas properties acquired from ING and Alerion Drilling on June 29, 2011 and July 27, 2011, respectively, and oil revenues from new oil producing properties drilled in late 2011 and in the first nine months of 2012. The production increases from these additions and a 11% increase in average oil prices offset a 39% decrease in natural gas prices for the nine month period.

	2012		2011		Increase
Oil and natural gas sales
(in thousands)
Other properties	$	4,975	$	4,000	$	975
Acquired properties*		2,934		1,894		1,040
Total	$	7,909	$	5,894	$	2,015

	2012		2011		Increase
Production - MMcfe
Other properties		1,045		800		245
Acquired properties*		948		388		560
Total		1,993		1,188		805

*Acquired properties include only three months activity in 2011 as compared to nine months activity in 2012.

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 or variable swap contracts when our management believes that favorable future sales prices for our natural gas and oil production can be secured. Because we do not designate these derivatives as cash flow hedges, they do not receive hedge accounting treatment and all mark-to-markets gains or losses, as well as realized gains or losses on the derivative instruments, are currently recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these swap agreements as the future strip prices fluctuate relative to the fixed price we will receive from these swap agreements. For the nine months ended September 30, 2012 we had hedging losses of approximately $8,000 compared to hedging gains of approximately $281,000 for the nine months ended September 30, 2011.

Lease operating expenses- Lease operating expenses increased approximately 21% for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011 primarily due to the addition of oil and gas properties acquired from ING and Alerion Drilling on June 29, 2011 and July 27, 2011, respectively, and oil properties added from drilling activities. Lease operating expenses for other properties, which include the Company’s existing properties and properties drilled, were higher in the nine months ended September 30, 2011 as compared to the same period in 2012 due to major repairs to roads and well sites damaged by area flooding in Kentucky and West Virginia in 2011. On a per Mcfe basis, lease operating expenses decreased from $1.11 per Mcfe for the nine months ended September 30, 2011 to $0.79 per Mcfe for the nine months ended September 30, 2012.

	2012		2011		Increase/ (Decrease)
Lease operating expenses
(in thousands)
Other properties	$	891	$	1,126	$	(235	)
Acquired properties*		693		188		505
Total	$	1,584	$	1,314	$	270

*Acquired properties include only three months activity in 2011 as compared to nine months activity in 2012.

Transportation costs- Transportation costs increased from approximately $742,000 for the nine months ended September 30, 2011 to approximately $1.3 million for the nine months ended September 30, 2012 due to transportation price increases and transportation for production from oil and gas properties acquired from ING and Alerion Drilling on June 29, 2011 and July 27, 2011, respectively. On a per Mcfe basis, these expenses increased from $0.62 per Mcfe for the nine months ended September 30, 2011 to $0.65 per Mcfe for the nine months ended September 30, 2012 due to higher gathering costs per Mcfe incurred on the acquired properties compared to the Company’s properties prior to the acquisitions.

	2012		2011		Increase
Transportation costs
(in thousands)
Other properties	$	502	$	413	$	89
Acquired properties*		792		329		463
Total	$	1,294	$	742	$	552

*Acquired properties include only three months activity in 2011 as compared to nine months activity in 2012.

Production and property taxes- Production and property taxes increased 35% from approximately $410,000 for the nine months ended September 30, 2011 to approximately $554,000 for the nine months ended September 30, 2012. This increase is attributed primarily to production and property taxes on the oil and natural gas properties acquired from ING and Alerion Drilling on June 29, 2011 and July 27, 2011, respectively. On a per Mcfe basis, these expenses decreased from $0.35 per Mcfe for the nine months ended September 30, 2011 to $0.28 per Mcfe for the nine months ended September 30, 2012. The decrease on a per Mcfe basis is primarily attributed to lower natural gas prices which resulted in lower taxable revenues per Mcfe produced.

	2012		2011		Increase
Production and property taxes
(in thousands)
Other properties	$	320	$	288	$	32
Acquired properties*		234		122		112
Total	$	554	$	410	$	144

*Acquired properties include only three months activity in 2011 as compared to nine months activity in 2012.

Depreciation, depletion and amortization (DD&A)- DD&A increased from approximately $1.7 million for the nine months ended September 30, 2011 to approximately $2.5 million for the nine months ended September 30, 2012 primarily due to additional depletion recognized on the production of the oil and natural gas properties acquired from ING and Alerion Drilling on June 29, 2011 and July 27, 2011, respectively. On a per Mcfe basis, these expenses decreased from $1.40 per Mcfe for the nine months ended September 30, 2011 to $1.23 per Mcfe for the nine months ended September 30, 2012. The decrease in the DD&A rate per equivalent unit is principally attributed to lower depletion rates. The decrease in the depletion rates is primarily attributed to lower gas prices which resulted in the recognition of impairments of oil and gas properties recognized in 2011 and 2012. The impairments reduced the depletable asset base and thus, lowered the depletion rates.

Impairment of oil and gas properties- The Company recognized a non-cash impairment expense of approximately $15.4 million for the nine months ended September 30, 2012. For the nine months ended September 30, 2011, the Company recognized an impairment of approximately $12.2 million. A decline in natural gas prices has been the primary contributing factor causing the impairments in both 2012 and 2011. Additional impairments may be required in subsequent periods if among other things; the unweighted arithmetic average of the first-day-of-the-month natural gas and oil prices used in the calculation of the present value of future net revenue from estimated production of proved oil and gas reserves decline compared to prices used as of September 30, 2012, unproved property values decrease, estimated proved reserve volumes are revised downward or costs incurred in exploration, development, or acquisition activities exceed the discounted future net cash flows from additional reserves, if any.

General and administrative expenses- General and administrative expenses decreased 12% from approximately $3.8 million for the nine months ended September 30, 2011 to approximately $3.3 million for the nine months ended September 30, 2012. Included in 2012 general and administrative expenses is a non-cash expense of approximately $328,000 for stock based compensation. In 2011, the Company incurred additional costs related to audit, legal and other administrative costs associated with the acquisition of oil and gas properties from ING and Alerion Drilling and merger related expenses. In addition, during the nine months ended September 30, 2011, pursuant to the merger, Nytis USA, as manager of Nytis LLC, redeemed all unvested, forfeitable restricted membership interests pursuant to the Nytis LLC restricted membership plan for $300,000 which was recognized as general and administrative expenses.

The table below sets forth the components of general and administrative expenses for the nine months ended September 30, 2012 and 2011.

	2012		2011
General and administrative expenses
(in thousands)
Stock based compensation	$	328	$	-
Other general and administrative expenses		2,982		3,771
Total general and administrative expenses	$	3,310	$	3,771

Interest expense - Interest expense increased from approximately $323,000 for the nine months ended September 30, 2011 to approximately $599,000 for the nine months ended September 30, 2012 primarily due to higher average debt balances during the first nine months of 2012 compared to the first nine months in 2011.

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, as market conditions have permitted, we have engaged in asset monetization transactions.

Changes in the market prices for oil and natural gas directly impact our level of cash flow generated from operations. For each of the three and nine months ended September 30, 2012, natural gas made up approximately 90% of our hydrocarbon production and, as a result, our operations and cash flow are more sensitive to fluctuations in the market price for natural gas than to fluctuations in the market price for oil and liquids. We employ a commodity hedging strategy as an attempt to moderate the effects of wide fluctuations in commodity prices on our cash flow. As of September 30, 2012, we have outstanding hedges of 150,000 MMbtu for 2012 at an average price of $3.24 per MMbtu and 240,000 MMbtu for 2013 at an average price of $3.25 per MMbtu in addition to oil hedges of 3,000 barrels for 2012 at an average price of $106.25 per barrel and 6,000 barrels for 2013 at an average price of $87.70 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 2012 and 2013. 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, 2012, our derivative counterparty 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 of which approximately $6.2 million was available as of September 30, 2012. The available borrowing base increased to $8.6 million after the Company reduced its outstanding balance of its credit facility by $2.4 million with proceeds from the Liberty Participation Agreement on October 1, 2012. This credit facility is used to fund daily operations and to fund acquisitions and refinance debt, as needed and if available. The credit facility is secured by substantially all of the Company’s oil and natural gas assets and matures in May 2014. See —“ Bank Credit Facility ” below for further details. We had approximately $13.8 million drawn on our credit facility as of September 30, 2012.

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 $6.2 million of funds available under our credit facility at September 30, 2012 will be sufficient to fund our normal recurring operating needs, anticipated capital expenditures (other than the potential acquisition of additional natural gas and oil properties), and our contractual obligations. In addition, pursuant to the terms of the Participation Agreement, as Liberty is responsible to carry a greater percentage of the costs associated with the first 20 wells drilled under the Participation Agreement, we believe that little or no additional debt will be required to fund the drilling and completion of these wells. However, if our revenue and cash flow decrease further in the future as a result of a deterioration in domestic and global economic conditions or a significant decline in commodity prices, we may elect to reduce our planned capital expenditures. We believe that this financial flexibility to adjust our spending levels will provide us with sufficient liquidity to meet our financial obligations should economic conditions deteriorate. See “ Risk Factors ,” in our Annual Report filed on Form 10-K with the SEC for a discussion of the risks and uncertainties that affect our business and financial and operating results.

Bank Credit Facility

Nytis LLC has a bank credit facility which consists of a $50.0 million credit facility (the “Credit Facility”) with Bank of Oklahoma. The Credit Facility will mature in May 2014 and is guaranteed by Nytis USA and Carbon. Our availability under the Credit Facility is governed by a borrowing base (the “Borrowing Base”), which at September 30, 2012 was at $20.0 million. The determination of the Borrowing Base is made by the lenders in their sole discretion, on a semi-annual basis, taking into consideration the estimated value of our oil and natural gas properties in accordance with the lenders’ 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 2012. In addition to the semi-annual redeterminations, Nytis LLC and the lenders 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 Alternative 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 LIBOR plus 3.25% for each LIBOR tranche. For all debt outstanding regardless if the loan is based on an Alternative Base Rate or LIBOR, there is a minimum floor of 4.5% per annum.

The Credit Facility is collateralized by substantially all of the Company's oil and gas assets and 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.

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

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, 2012 there was $13.8 million borrowed under our Credit Facility.

On October 1, 2012, the Company reduced the outstanding balance of its credit facility with the Bank of Oklahoma by approximately $2.4 million with proceeds from the Liberty Participation Agreement.

In addition, the Credit Facility includes a hedging component that provides a line of credit under commodity swap, exchange, collar, cap and fixed price agreements and agreements designated to protect the Company against changes in interest and currency exchange rates. The maximum amount of credit on this line is $8.0 million.

Historical Cash Flow

Net cash used in operating activities, net cash used in investing activities, and net cash provided by financing activities for the nine months ended September 30, 2012 and 2011 were as follows:

	Nine Months Ended
	September 30,
(in thousands)	2012			2011

Net cash used in operating activities	$	( 552	)		$	(2,883	)
Net cash used in investing activities	$	(1,847	)		$	(30,232	)
Net cash provided by financing activities	$	4,983			$	33,432

Net cash provided by or used in operating activities is primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and changes in working capital. The increase in operating cash flows of approximately $2.3 million for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011 was primarily due to decreases in working capital related to positive changes in accounts receivable and amounts due to related parties and increased operating income generated from new oil production and natural gas producing properties acquired from ING and Alerion Drilling in mid-2011 offset, in part, by decreases in oil and natural gas prices.

Net cash provided by or used in investing activities is primarily comprised of the acquisition, exploration, and development of natural gas properties net of dispositions of natural gas properties. The increase in investing cash flows of approximately $28.4 million for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011 was primarily due to the acquisition of oil and natural gas properties from ING in the second quarter of 2011 and proceeds received from the Liberty Participation Agreement in the third quarter of 2012 partially offset by increased development expenditures.

The decrease in financing cash flows of approximately $28.4 million for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011 was primarily due to the proceeds received from the issuance of common and preferred shares in the second quarter of 2011.

Capital Expenditures

Capital expenditures for the nine months ended September 30, 2012 and 2011 are summarized in the following table:

	Nine Months Ended September 30,
(in thousands)	2012		2011

Acquisition of oil and gas properties:
Unevaluated properties	$	350	$	191
Proved producing properties		269		38,430

Drilling and development		4,665		2,281
Pipeline and gathering		227		53
Other		51		152
Total capital expenditures	$	5,562	$	41,107

Primary factors impacting the level of our capital expenditures include natural gas and oil prices, the volatility in these prices, the cost and availability of oil field services and general economic and market conditions.

Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of September 30, 2012, 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 derivative contracts that are sensitive to future changes in commodity prices or interest rates. 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

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 as used and defined by us, may not be comparable to similarly titled measures employed by other companies and are not a measure 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, or other performance measures 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, 2012 and 2011 .

	Three Months Ended
	September 30,
(in thousands)	2012			2011

Net loss	$	(310	)	$	(4,072	)

Adjustments:
Interest expense		276			131
Depreciation, depletion and amortization		588			914
EBITDA		554			(3,027	)

Adjusted EBITDA
EBITDA		554			(3,027	)
Adjustments:
Accretion of asset retirement obligations		24			60
Impairment of oil and gas properties		-			3,825
Adjusted EBITDA	$	578		$	858

	Nine Months Ended
	September 30,
(in thousands)	2012			2011

Net loss	$	(17,124	)	$	(14,299	)

Adjustments:
Interest expense		599			323
Depreciation, depletion and amortization		2,450			1,661
EBITDA		(14,075	)		(12,315	)

Adjusted EBITDA
EBITDA		(14,075	)		(12,315	)
Adjustments:
Accretion of asset retirement obligations		76			71
Impairment of oil and gas properties		15,407			12,204
Adjusted EBITDA	$	1,408		$	(40	)

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.

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, 2012. 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, 2012.

Changes in Internal Control over Financial Reporting

There has not been any change in our internal control over financial reporting that occurred during our three month period ended September 30, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

Legal Proceedings

The Company is subject to legal claims and proceedings in the ordinary course of its oil and natural gas exploration and 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 (i) to Form 8-K/A for St. Lawrence Seaway Corporation filed on June 30, 2011.
10*			Participation Agreement dated September 17, 2012 by and between Carbon Natural Gas Company, Nytis Exploration Company LLC and Liberty Energy, LLC.
14			Code of Ethics, incorporated by reference to Exhibit 14 to Form 10-K filed on June 29, 2004.
31.1*			Certification of Chief Executive Officer Pursuant to Rule 13a-15(e) / Rule 15d-15(e).
31.2*			Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) / Rule 15(e)/15d-15(e).
32.1†			Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2†			Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
101*			Interactive data files pursuant to Rule 405 of Regulation S-T

*	Filed herewith

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

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

	CARBON NATURAL GAS COMPANY
	(Registrant)

Date: November 14, 2012	By:	/s/ Patrick R. McDonald
		PATRICK R. MCDONALD,
		Chief Executive Officer

Date: November 14, 2012	By:	/s/ Kevin D. Struzeski
		KEVIN D. STRUZESKI
		Chief Financial Officer

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