Carbon Energy (CRBO) 10-Q 2011 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

xQuarterly report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarter ended June 30, 2011 or

oTransition 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 2020, 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 o  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 August 11, 2011, there were issued and outstanding 114,185,405 shares of the Company’s common stock, $0.01 par value.

Carbon Natural Gas Company

TABLE OF CONTENTS

Part I — FINANCIAL INFORMATION
Item 1.  Consolidated Financial Statements
	Consolidated Balance Sheets (unaudited)	2
	Consolidated Statements of Operations (unaudited)	3
	Consolidated Statements of Stockholders’ Equity (unaudited)	4
	Consolidated Statements of Cash Flows (unaudited)	5
	Notes to the Consolidated Financial Statements (unaudited)	6
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations		19
Item 4.  Controls and Procedures		31
Part II — OTHER INFORMATION
Item 1.  Legal Proceedings		32
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds		32
Item 3.  Defaults Upon Senior Securities		33
Item 5.  Other Information		33
Item 6.  Exhibits		34

PART I. FINANCIAL INFORMATION

ITEM 1.  Financial Statements

CARBON NATURAL GAS COMPANY

Consolidated Balance Sheets

	June 30, 2011 (Unaudited)			December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents	$	7,442,894		$	845,054
Accounts receivable:
Revenue	960,754			752,845
Joint interest billings and other	860,945			258,340
Firm transportation contract obligations	1,050,087			—
Prepaid expense, deposits and other current assets	132,403			84,941
Deferred offering costs	—			169,283
Derivative assets	112,190			170,840
Total current assets	10,559,273			2,281,303
Oil and gas properties, at cost, net (based on the full cost method of accounting for oil and gas properties) (note 6)	53,565,082			23,578,264
Other property and equipment, net	121,327			80,703
	53,686,409			23,658,967
Investments in affiliates	1,135,032			582,745
Other long-term assets	2,414,143			463,110
Total assets	$	67,794,857		$	26,986,125
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	3,960,274		$	1,632,193
Firm transportation contract obligations	2,763,388			—
	6,723,662			1,632,193
Non-current liabilities:
Due to related parties (note 12)	1,757,136			3,073,036
Asset retirement obligation (note 2)	1,868,296			351,954
Firm transportation contract obligations	5,422,257			—
Notes payable (note 7)	9,791,383			3,116,383
Total non-current liabilities	18,839,072			6,541,373
Commitments (note 14)
Stockholders’ equity:
Preferred stock, $0.01 par value; authorized 1,000,000 shares, 100 shares Series A Convertible preferred shares issued and outstanding at June 30, 2011 and no shares issued at December 31, 2010	1			—
Common stock, $0.01 par value; authorized 100,000,000 shares, 91,963,183 and 47,903,442 shares issued and 91,963,183 and 47,163,079 shares outstanding at June 30, 2011 and December 31, 2010, respectively	919,632			479,034
Additional paid-in capital	54,168,529			27,700,646
Non-controlling interests	6,579,404			637,612
Treasury stock, at cost	—			(693,820		)
Accumulated deficit	(19,435,443		)	(9,310,913		)
Total stockholders’ equity	42,232,123			18,812,559
Total liabilities and stockholders’ equity	$	67,794,857		$	26,986,125

See accompanying notes to consolidated financial statements.

2

CARBON NATURAL GAS COMPANY

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Revenue:
Oil and gas	$	1,252,889		$	1,089,338		$	2,506,526		$	2,651,434
Commodity derivative gain (loss)	63,530			(63,480		)	124,930			411,130
Other income	91,617			73,311			189,475			123,137
Total revenue	1,408,036			1,099,169			2,820,931			3,185,701
Expenses:
Lease operating expenses	445,849			254,117			688,717			511,926
Transportation costs	116,813			80,548			272,205			122,574
Production and property taxes	89,343			113,428			196,820			210,982
General and administrative	1,144,939			641,858			2,588,915			1,734,377
Depreciation, depletion and amortization	371,400			367,877			746,922			799,880
Accretion of asset retirement obligations	6,041			4,140			11,741			8,482
Impairment of oil and gas properties	1,062,498			—			8,379,719			—
Total expenses	3,236,883			1,461,968			12,885,039			3,388,221
Operating loss	(1,828,847		)	(362,799		)	(10,064,108		)	(202,520		)
Other income and (expense):
Interest income	24			9,728			39			19,133
Interest expense	(114,281		)	(18,522		)	(192,313		)	(249,646		)
Loss on disposition of fixed asset	—			—			(12,564		)	—
Equity investment income	56,269			—			41,359			—
Gain on sale of oil and gas properties	—			—			—			9,876,510
Total other income and (expense)	(57,988		)	(8,794		)	(163,479		)	9,645,997
(Loss) income before income taxes	(1,886,835		)	(371,593		)	(10,227,587		)	9,443,477
Provision for income taxes	—			620,000			—			5,404,000
Net (loss) income before non-controlling interests	(1,886,835		)	(991,593		)	(10,227,587		)	4,039,477
Net loss (income) attributable to non-controlling interests	103,057			—			103,057			(767,061		)
Net (loss) income attributable to controlling interest	$	(1,783,778	)	$	(991,593	)	$	(10,124,530	)	$	3,272,416
Net (loss) income per common share:
Basic	$	(0.04	)	$	(0.02	)	$	(0.22	)	$	0.07
Diluted	$	(0.04	)	$	(0.02	)	$	(0.22	)	$	0.07
Weighted average common shares outstanding:
Basic	46,050,227			45,946,530			45,682,914			45,946,530
Diluted	46,050,227			45,946,530			45,682,914			48,298,391

See accompanying notes to consolidated financial statements.

3

CARBON NATURAL GAS COMPANY

Consolidated Statements of Stockholders’ Equity

(Unaudited)

																				(Accumulated
									Additional			Non-								Deficit) /			Total
	Common Stock					Preferred Stock			Paid-in			Controlling			Treasury Stock					Retained			Stockholders’
	Shares		Amount			Shares	Amount		Capital			Interests			Shares		Amount			Earnings			Equity
Balances, December 31, 2010	47,903,442		$	479,034		—	$	—	$	27,700,646		$	637,612		(740,363	)	$	(693,820	)	$	(9,310,913	)	$	18,812,559
Purchase treasury stock	—		—			—	—		—			—			(163,076	)	(152,823		)	—			(152,823		)
Retire treasury stock	(903,439	)	(9,034		)	—	—		(837,609		)				903,439		846,643			—			—
Reverse merger with St. Lawrence Seaway Corp.	518,736		5,187			—	—		(20,851		)	—			—		—			—			(15,664		)
Issuance of common stock, net of offering costs	44,444,444		444,445			—	—		17,326,344			—			—		—			—			17,770,789
Issuance of Series A preferred stock	—		—			100	1		9,999,999			—			—		—			—			10,000,000
Non-controlling interest — INGC acquisition												6,044,849											6,044,849
Net loss	—		—			—	—		—			(103,057		)	—		—			(10,124,530		)	(10,227,587		)
Balances, June 30, 2011	91,963,183		$	919,632		100	$	1	$	54,168,529		$	6,579,404		—		$	—		$	(19,435,443	)	$	42,232,123

See accompanying notes to consolidated financial statements.

4

CARBON NATURAL GAS COMPANY

Consolidated Statements of Cash Flows

(Unaudited)

	Six Months Ended
	June 30,
	2011			2010
Cash flows from operating activities:
Net (loss) income	$	(10,227,587	)	$	4,039,477
Items not involving cash:
Depreciation, depletion and amortization	746,922			799,880
Accretion of asset retirement obligations	11,741			8,482
Loss on disposition of fixed asset	12,564			—
Impairment of oil and gas properties	8,379,719			—
Gain on sale of oil and gas properties	—			(9,876,510		)
Unrealized derivative loss (gain)	58,650			(292,510		)
Deferred taxes	—			4,784,000
Equity investment income	(41,359		)	—
Net change in:
Accounts receivable	(383,949		)	339,899
Prepaid expenses, deposits and other current assets	(47,462		)	(386,388		)
Accounts payable and accrued liabilities	119,326			33,812
Due to related parties	(1,315,900		)	(2,866,450		)
Net cash used in operating activities	(2,687,335		)	(3,416,308		)
Cash flows from investing activities:
Acquisition and development of properties and equipment	(26,994,588		)	(2,795,205		)
Proceeds from disposition of assets	—			30,052,550
Investment in affiliate	(48,375		)	—
Other long-term assets	109,425			8,224
Net cash (used in) provided by investing activities	(26,933,538		)	27,265,569
Cash flows from financing activities:
Issue common stock	20,000,000			—
Issue Series A convertible preferred stock	10,000,000			—
Offering costs	(303,464		)	—
Issue of non-controlling interests in subsidiary	—			4,236
Treasury share purchase	(152,823		)	—
Proceeds from notes payable	6,675,000			—
Payments on notes payable	—			(23,547,227		)
Net cash provided by (used in) financing activities	36,218,713			(23,542,991		)
Net increase in cash and cash equivalents	6,597,840			306,270
Cash and cash equivalents, beginning of period	845,054			208,295
Cash and cash equivalents, end of period	$	7,442,894		$	514,565

See accompanying notes to consolidated financial statements.

5

CARBON NATURAL GAS COMPANY

Notes to Consolidated Financial Statements

(Unaudited)

June 30, 2011

Note 1 — Organization

Carbon Natural Gas Company (“Carbon”), formerly known as St. Lawrence Seaway Corporation (“SLSC”), is an independent oil and gas company engaged in the exploration, development and production of natural gas in the United States.  The Company was formed as the result of a merger with Nytis Exploration (USA) Inc. (“Nytis USA”) in February 2011 (see Note 3).  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 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 become 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 June 30, 2011, and the Company’s results of operations and cash flows for the three and six months ended June 30, 2011 and 2010.  Operating results for the three and six months ended June 30, 2011 and 2010 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas and oil, natural production declines, the uncertainty of exploration and development drilling results and other factors.  For a more complete understanding of the Company’s operations, financial position and accounting policies, the unaudited financial statements and the notes thereto should be read in conjunction with the Company’s audited consolidated financial statements for the year ended December 31, 2010 filed on Form 8-K/A with the Securities and Exchange Commission (“SEC”).

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

Principles of Consolidation

The consolidated financial statements include the accounts of Carbon, Nytis USA and its consolidated subsidiaries.  The Company owns 100% of Nytis USA.  Nytis USA owns 85% of Nytis Pennsylvania and approximately 98% of Nytis LLC.  Nytis LLC also holds an interest in various oil and gas partnerships related to its acquisition discussed in Note 4.

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.  The Company 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 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.

6

CARBON NATURAL GAS COMPANY

Notes to Consolidated Financial Statements

(Unaudited)

June 30, 2011

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 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.

As of June 30, 2011, the Company’s full cost pool exceeded the ceiling limitation, based on oil prices of $86.60 per barrel and gas prices of $4.15 per Mcf and accordingly, for the three months ended June 30, 2011, the Company recorded a non-cash impairment of approximately $1.1 million related to its oil and gas properties.  An impairment expense of approximately $7.3 million was recorded during the three months ended March 31, 2011.  The impairments for the six months ended June 30, 2011 was approximately $8.4 million.  The Company did not recognize any non-cash impairment charges related to its oil and gas properties in the six months ended June 30, 2010.

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

7

CARBON NATURAL GAS COMPANY

Notes to Consolidated Financial Statements

(Unaudited)

June 30, 2011

Note 2 — Summary of Significant Accounting Policies (continued)

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

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

The following table is a reconciliation of the ARO for the six months ended June 30, 2011:

	Six Months Ended June 30,
(in thousands)	2011
Balance at beginning of period	$	352
Liabilities transferred due to property disposition	—
Accretion expense	12
Additions assumed with acquired properties	1,402
Additions during period	102
Balance at end of period	$	1,868

Investments in Affiliates

Investments in non-consolidated affiliates are accounted for under either the equity or cost method of accounting as appropriate.

The Company has an investment that is accounted for using the equity method of accounting, which was acquired in the fourth quarter of 2010 and consists of a 50% interest in a joint venture which owns a gas gathering facility.  Income of approximately $56,000 and $41,000 from the joint venture was recognized for the three and six months ended June 30, 2011, respectively, in the Company’s consolidated statements of operations.

Also 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 statements.  During the second quarter of 2011, it became evident that the Company would not be able to obtain the requisite amount of information relative to Sullivan’s revenues, expenses and reserves and thus 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 as of April 1, 2011 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.

8

CARBON NATURAL GAS COMPANY

Notes to Consolidated Financial Statements

(Unaudited)

June 30, 2011

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 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 the 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 the 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 (see Note 3), 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 June 30, 2011 is the actual number of common shares of the Company outstanding during that period.

At June 30, 2011, the Company had common stock equivalents of 2,326,664 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.  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

ING Assets

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

9

CARBON NATURAL GAS COMPANY

Notes to Consolidated Financial Statements

(Unaudited)

June 30, 2011

Note 4 — Acquisitions (continued)

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 current production and reserve base.  The ING Assets consist 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 include (i) some but not all of ING’s leases and interests in natural gas and oil leases, and 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 and equipment and 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 qualifies 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).

A deminimus amount of revenues and earnings related to the ING Assets are included in the accompanying statement of operations for the three months ended June 30, 2011.  The Company expensed approximately $227,000 and $416,000 of transaction costs that were included in general and administrative expenses on the accompanying consolidated statement of operations during the three and six months ended June 30, 2011, respectively.

Total purchase consideration is still subject to final working capital adjustments which are expected to be completed within 120 days from the date of closing.  At this time, the Company does not believe there will be significant adjustments to the amounts recorded.

The following table summarizes the consideration paid to ING and the estimated fair value of the assets acquired and liabilities assumed.  See Note 5 for discussion of the fair value measurements.

	(in thousands)
Consideration paid to sellers:
Cash consideration	$	25,858
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed properties and related support facilities	$	38,537
Asset retirement obligations	(1,402		)
Operations receivable	474
Firm transportation obligations receivable:
Current	1,050
Long-term	2,061
Accounts and revenue payables assumed	(631		)
Firm transportation obligations assumed	(8,186		)
Non-controlling equity interests	(6,045		)
Total identifiable net assets	$	25,858

10

CARBON NATURAL GAS COMPANY

Notes to Consolidated Financial Statements

(Unaudited)

June 30, 2011

Note 4 — Acquisitions (continued)

Pro Forma

Below are consolidated results of operations for the six months and the quarter ended June 30, 2011 and 2010, as though the ING acquisition made during 2011 had been completed as of January 1, 2011 and 2010, respectively.

	Three Months Ended			Six Months Ended			Three Months Ended			Six Months Ended
(in thousands, except share data)	June 30, 2011			June 30, 2011			June 30, 2010			June 30, 2010
Revenue	$	3,914		$	7,619		$	3,138		$	7,893
Net (loss) income before non-controlling interests	(357		)	(7,487		)	174			6,732
Net income attributable to non-controlling interests	(142		)	(345		)	(239		)	(1,320		)
Net (loss) income attributable to controlling interests	(499		)	(7,832		)	(65		)	5,412
Net income (loss) per share (basic)	(0.01		)	(0.17		)	0.00			0.12
Net income (loss) per share (diluted)	(0.01		)	(0.17		)	0.00			0.11

Note 5 — 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/and or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer.  The Company has consistently applied the valuation techniques discussed below for all periods presented.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2011 and December 31, 2010 by level within the fair value hierarchy:

	Fair Value Measurements Using
(in thousands)	Level 1		Level 2		Level 3		Total
June 30, 2011
Assets:
Commodity derivatives	$	—	$	112	$	—	$	112
December 31, 2010
Assets:
Commodity derivatives	$	—	$	171	$	—	$	171

11

CARBON NATURAL GAS COMPANY

Notes to Consolidated Financial Statements

(Unaudited)

June 30, 2011

Note 5 — Fair Value Measurements (continued)

As of June 30, 2011, the Company’s commodity derivative financial instruments are comprised of four natural gas swap agreements.  The fair values of the swap agreements are determined under the income valuation technique using a discounted cash flow model.  The valuation model requires a variety of inputs, including contractual terms, published forward prices, volatilities for options, and discount rates, as appropriate.  The Company’s estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, the Company’s credit worthiness and the time value of money.  The consideration of these factors result in an estimated exit-price for each derivative asset or liability under a market place participant’s view.  All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s derivative instruments are included within the Level 2 fair value hierarchy. The counterparty in all of the Company’s commodity derivative financial instruments is the lender in the Company’s bank credit facility.

Assets Measured and Recorded at Fair Value on a Non-recurring Basis

The fair value of each of the following assets and liabilities measured and recorded at fair value on a non-recurring basis are based on unobservable pricing inputs and therefore, are included within the Level 3 fair value hierarchy.

The Company uses the income valuation technique to estimate the fair value of asset retirement obligations using the amounts and timing of expected future dismantlement costs, credit-adjusted risk-free rates and time value of money.  During the six months ended June 30, 2011 and 2010, the Company recorded asset retirement obligations for additions of approximately $1.5 million and $4,000, respectively. See Note 2 for additional information.

To determine the fair value of the proved developed properties acquired related to the ING Assets, the Company used a discounted cash flow model based on an income approach and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates.  The Company determined the appropriate discount rates used for the discounted cash flow analyses by first determining the Company’s weighted average cost of capital plus property specific risk premiums for the assets acquired.  The proved developed properties acquired have a much longer reserve to production ratio than its peer group and extreme sensitivities to changes in natural gas prices relative to the resultant present value of the proved developed properties.  The Company estimated property specific risk premiums taking those factors, among others, into consideration.

The fair value of the non-controlling interest in the partnerships the Company is required to consolidate related to the ING Assets, was determined based on the net discounted cash flows of the proved developed properties attributable to the non-controlling interests in these partnerships.

The Company assumed certain firm transportation contracts as part of the ING Assets acquired.  The fair value of the firm transportation obligations were determined based upon the contractual obligations assumed by the Company and discounted based upon the Company’s effective borrowing rate.  These contracted obligations will be amortized on a monthly basis as the Company pays these firm transportation obligations in the future.

12

CARBON NATURAL GAS COMPANY

Notes to Consolidated Financial Statements

(Unaudited)

June 30, 2011

Note 6 — Property and Equipment

Net property and equipment as of June 30, 2011 and December 31, 2010 consists of the following:

(in thousands)	June 30, 2011			December 31, 2010
Oil and gas properties
Proved oil and gas properties	$	81,548		$	43,535
Unproved properties not subject to depletion	2,183			2,164
Accumulated depreciation, depletion, amortization and impairment	(30,166		)	(22,121		)
Net oil and gas properties	53,565			23,578
Furniture and fixtures, computer hardware and software, and other equipment	528			488
Accumulated depreciation and amortization	(407		)	(407		)
Net other property and equipment	121			81
Total net property and equipment	$	53,686		$	23,659

As of June 30, 2011 and December 31, 2010, the Company had approximately $2.2 million 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 $198,000 and $195,000 for the six months ended June 30, 2011 and 2010, respectively.

Note 7 — Bank Credit Facility

On April 22 and June 10, 2011, Nytis LLC amended its credit facility with the Bank of Oklahoma.  The credit facility’s maturity date was extended from May 2012 to May 2014.  The facility’s borrowing base was increased from $8 million to $20 million and the maximum line of credit available under hedging arrangements was increased from $2.7 million to $5.0 million.  The 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 four consecutive fiscal quarters) increased from 3.5 to 1 to 4.25 to 1.  In connection with these amendments to the credit facility, Carbon entered into an agreement with the Bank of Oklahoma to guaranty Nytis LLC’s obligations under its credit facility.  Nytis LLC also granted the Bank of Oklahoma a security interest in certain of the assets it recently acquired from ING and their related parties (see Note 4).

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 million.  As of June 30, 2011, the borrowing base was $20.0 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 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 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; plus 1.5%.  The portion based on LIBOR is determined by the rate per annum equal to LIBOR

13

CARBON NATURAL GAS COMPANY

Notes to Consolidated Financial Statements

(Unaudited)

June 30, 2011

Note 7 — Bank Credit Facility (continued)

plus between 2.5% and LIBOR plus 3.25% for each LIBOR tranche. For all debt outstanding regardless of if the loan is based on the Alternative Base Rate or LIBOR, there is a minimum floor of 4.5% per annum. 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 $5.0 million.

At June 30, 2011, there were approximately $9.8 million in outstanding borrowings under the credit facility.  The Company’s effective borrowing rate at June 30, 2011 was 4.5%.  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 to current liabilities) of 1.0 to 1.0 and a maximum Funded Debt Ratio of 4.25 to 1.0 as of the end of any fiscal quarter.  The Company is in compliance with all covenants associated with the credit agreement as of June 30, 2011.

Note 8 — Income Taxes

We recognize deferred income tax assets and liabilities for the estimated future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. We have net operating loss carryforwards available in certain jurisdictions to reduce future taxable income. Future tax benefits for net operating loss carryforwards are recognized to the extent that realization of these benefits is considered more likely than not. To the extent that available evidence raises doubt about the realization of a deferred income tax asset, a valuation allowance is established.

At June 30, 2011, 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

On March 22, 2011, the Company increased the number of its authorized common stock from 48,500,000 shares to 100,000,000 shares with a par value of $0.01 per share and deleted any and all references to the Class A Common Stock.

On June 16, 2011, a series of preferred stock designated as the “Series A Convertible Preferred Stock” to consist of 100 authorized shares with a par value $0.01 per share was created. Upon the effective date of filing a Certificate of Amendment to its Certificate of Incorporation (that would increase the Company’s authorized common stock from 100,000,000 shares to 200,000,000 shares) the preferred stock automatically converts into common stock.

Effective July 18, 2011, Carbon filed a Certificate of Amendment to its Certificate of Incorporation thereby increasing its authorized common stock shares from 100,000,000 to 200,000,000 shares, and concurrently, the 100 shares of Series A Convertible Preferred Stock were converted into 22,222,222 shares of Carbon’s $0.01 par value per share common stock.

On June 29, 2011, the Company entered into a common stock purchase agreement with various institutional investors and other accredited investors for the private placement (the “Private Placement”) of 44,444,444 shares of the Company’s common stock at a price of $0.45 per share, and a preferred stock purchase agreement with an institutional investor and affiliate of the Company’s current majority stockholders, for the private placement of 100 shares of the Company’s Series A Convertible Preferred Stock at a price of $100,000 per share, automatically convertible to 22,222,222 shares of common stock upon the effective date of filing the Certificate of Amendment to its Certificate of Incorporation described above.

The $30 million in gross proceeds from the offering is before the deduction of fees payable to the placement agents, representing five percent of gross proceeds ($1.5 million), plus reimbursement of certain expenses and legal fees

14

CARBON NATURAL GAS COMPANY

Notes to Consolidated Financial Statements

(Unaudited)

June 30, 2011

Note 9 — Stockholders’ Equity (continued)

they incurred of approximately $355,000, as well as other fees and expenses of approximately $375,000 incurred by the Company in connection with the private placement.

Net proceeds from the Private Placement were used principally to complete the acquisition of certain gas and oil assets from ING (see Note 4) and to pay down certain amounts outstanding under the Company’s bank credit facility subsequent to June 30, 2011 (see Note 15).

As of June 30, 2011, the authorized capital stock of Carbon was 101,000,000 shares, comprised of 100,000,000 shares of common stock and 1,000,000 shares of preferred stock.

During the three and six month period ended June 30, 2011, no stock options, warrants or restricted stock were granted or forfeited.

Pursuant to the merger (see Note 3), all options, warrants and restricted stock have been adjusted to reflect the conversion ratio used in the merger.  Accordingly, as of June 30, 2011, the Company has 342,459 options outstanding and exercisable, 2,696,133 warrants (including 250,000 warrants granted by SLSC prior to the merger) and 1,956,912 shares of common stock outstanding that are subject to restricted stock agreements.

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 10 — Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities at June 30, 2011 and December 31, 2010 consist of the following:

(in thousands)	June 30,  2011		December 31, 2010
Accounts payable	$	205	$	342
Oil and gas revenue payable to oil and gas property owners	745		325
Production taxes payable	48		35
Accrued drilling costs	—		113
Accrued lease operating costs	260		98
Accrued ad valorem taxes	384		305
Accrued bonus and payroll costs	251		169
Private placement offering costs	1,757		—
Other accrued liabilities	310		245
Total accounts payable and accrued liabilities	$	3,960	$	1,632

Note 11 — Physical Delivery Contracts and Gas Derivatives

The Company has historically used commodity-based derivative contracts to manage exposures to commodity price on certain of its 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.

15

CARBON NATURAL GAS COMPANY

Notes to Consolidated Financial Statements

(Unaudited)

June 30, 2011

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

The Company has fixed price contracts requiring physical deliveries for approximately 90 Mcf per day for an average sales price of $5.26 per Mcf, which are on a month-to-month basis.

At June 30, 2011, other than the above mentioned contracts, the Company’s other gas sales contracts approximate index prices.

The Company’s swap agreements as of June 30, 2011 are summarized in the table below:

Agreement	Remaining		Fixed Price	Floating Price Nytis USA
Type	Term	Quantity	Counterparty Payer	Payer
Swap	7/11 - 4/12	10,000 MMBtu/month	$5.25/ MMBtu	(a)
Swap	7/11 - 12/11	10,000 MMBtu/month	$4.80/ MMBtu	(a)
Swap	1/12 - 12/12	10,000 MMBtu/month	$5.07/ MMBtu	(a)

(a)NYMEX Henry Hub Natural Gas 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)	June 30,  2011		December 31, 2010
Natural gas derivative contracts:
Current assets	$	112	$	171
Current liabilities	$	—	$	—

The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the three and six months ended June 30, 2011 and 2010.  These realized and unrealized gains and losses are recorded and included in commodity derivative gain in the accompanying consolidated statements of operations.

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands)	2011			2010			2011			2010
Commodity derivative contracts:
Realized gains (losses)	$	77		$	158		$	184		$	118
Unrealized (losses) gains	(13		)	(221		)	(59		)	293
Total realized and unrealized gains, net	$	64		$	(63	)	$	125		$	411

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.

16

CARBON NATURAL GAS COMPANY

Notes to Consolidated Financial Statements

(Unaudited)

June 30, 2011

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

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 12 — Related Party Transactions

Nytis Exploration Company (“NEC”) is an independent oil and gas company whose nature of its business is the exploration, development, production, marketing and sale of oil, gas, coalbed methane and other hydrocarbons in locations other than the United States.  Prior to the closing of the Private Placement on June 29, 2011 (see Note 9 and Item 2 — Recent Developments), NEC had substantially the same shareholders as the Company.  The Company had engaged NEC to assist in the management, direction and supervision of the operations and business functions of the Company.  A service agreement between the Company and NEC provided for certain restrictions on NEC’s authority to perform acts in connection with the business of the Company and established provisions for the compensation of NEC in performing these duties.  General and administrative expenses charged by NEC to the Company were approximately $302,000 and $284,000 for the three months ended June 30, 2011 and 2010, respectively.  NEC charged the Company general and administrative expenses of approximately $673,000 and $561,000 for the six months ended June 20, 2011 and 2010, respectively.  As of June 30, 2011, the Company owed NEC approximately $1.8 million.  This payable consists primarily of charges incurred under the service agreement and advances made for capital expenditures and other miscellaneous general and administrative expenses.

The Company and NEC have terminated this service agreement and in its place, effective July 1, 2011, is a new agreement whereby the Company will manage, direct and supervise the operations and business of the Company in addition to providing these services to NEC for a monthly fee of $15,000.  The new agreement’s initial term of one year is automatically renewable for successive one-year terms.

Note 13 — Supplemental Cash Flow Disclosure

Supplemental cash flow disclosures for the six months ended June 30, 2011 and 2010 are presented below:

	Six Months Ended June 30,
(in thousands)	2011			2010
Cash paid during the period for:
Interest payments	$	170		$	231
Non-cash transactions:
Increase in net asset retirement obligations due to additions	$	102		$	4
Various assets acquired and liabilities assumed in acquisition (see Note 4)	$	6,635		$	—
Decrease in net asset retirement obligations due to sale of properties	$	—		$	(513	)
Decrease in accounts payable and accrued liabilities included in oil and gas properties	$	(194	)	$	(421	)
Offering costs included in accounts payable	$	1,756		$	—
Net assets transferred from oil and gas properties to investment in affiliate	$	463		$	—
Increase in interest receivable on promissory note	$	—		$	9

17

CARBON NATURAL GAS COMPANY

Notes to Consolidated Financial Statements

(Unaudited)

June 30, 2011

Note 14 — Commitments and Contingencies

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 June 30, 2011 are (i) for the remainder of 2011 through 2013; approximately 7,700 dekatherms per day capacity with demand charges ranging between $.22 and $1.40 per dekatherm, (ii) for 2014 through May 2015; 3,450 dekatherms per day with demand charges ranging between $.22 and $.65 and (iii) for June 2015 through 2017; 2,300 dekatherms per day with demand charges of $.65 per dekatherm.   A liability of approximately $8.2 million related to firm transportation contracts assumed in the ING Asset acquisition (see Note 4) was recorded and is reflected on the Company’s consolidated  balance sheets as of June 30, 2011.

In addition to the contracts assumed in the ING Asset acquisition, the Company has other long-term firm transportation contracts related to the Nytis LLC assets.  Capacity and related demand charges for the remaining term of the contracts at June 30, 2011 are (i) for the remainder of 2011 through March 2013; 1,300 dekatherms per day with demand charges ranging from $.22 to $.80 per dekatherm and (ii) 1,000 dekatherms per day with demand charges of $.22 from April 2013 through April 2036.

In connection with the Private Placement (see Note 9) of the Company’s common stock and Series A Convertible Preferred Stock, the Company entered into a Registration Rights Agreement (the “Agreement”) with the purchasers of the common stock.  Pursuant to the Agreement, the Company is required to file with the SEC and have declared effective one or more registration statements to register the resale of the common stock shares sold in the Private Placement.  If the Company fails to meet the deadlines for filing and effectiveness of the registration statement(s) set forth in the Agreement or if it fails to maintain the effectiveness thereof for the term provided for in the Agreement, the Company will be obligated to make pro rata payments to the common stock purchasers in an amount equal to 1.5% of the aggregate amount invested by such purchasers for each 30 day period until the Company fulfills its obligations.

Note 15 — Subsequent Events

Purchase of Oil and Gas Assets

On June 6, 2011, Nytis LLC and Alerion Drilling I, LLC, a New Jersey limited liability company (“Alerion Drilling”) entered into an Asset Purchase Agreement (the “Alerion APA”) to acquire Alerion Drilling’s interests of the assets (the “Alerion Assets”) that were distributed to Alerion Drilling and ING by Alerion JV-1, a Kentucky general partnership (the “Alerion Partnership”).  The Company purchased ING’s property interests of the distributed Alerion Partnership assets pursuant to the ING APA.

On July 27, 2011, Nytis LLC paid Alerion Drilling approximately $1.2 million, for the Alerion Assets acquired pursuant to the Alerion APA entered into on June 6, 2011.  Funds to acquire the Alerion Assets came from a draw on the Company’s credit facility with Bank of Oklahoma.

Paydown of Debt

On July 2, 2011, the Company reduced the outstanding balance of its credit facility with the Bank of Oklahoma by approximately $6.8 million with proceeds from the Private Placement (see Note 7).

Conversion of Stock

Effective July 18, 2011, Carbon amended its Certificate of Incorporation thereby increasing its authorized common stock shares from 100,000,000 to 200,000,000 shares, and concurrently, the 100 shares of Series A Convertible Preferred Stock was converted into 22,222,222 shares of Carbon’s $0.01 par value per share common stock (see Note 9).

Related Party Agreement

Effective July 1, 2011, the Company entered into a new agreement with NEC, a related party (see Note 12).

18

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

General Overview

On February 14, 2011, the Company closed the January 31, 2011 Merger Agreement, between (i) SLSC and its subsidiary Merger Co, a Delaware corporation, and (ii) Nytis USA.  As a result, Merger Co has been merged with and into Nytis USA, and Nytis USA is a surviving subsidiary of SLSC.  Subsequent to the merger, the Company believed that the continued use of the name St. Lawrence Seaway 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 become effective May 2, 2011.

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 the Illinois Basin 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 unconventional reservoirs, including fractured shale gas plays, tight gas sands and coalbed methane.  Our corporate headquarters are in Denver, Colorado and Catlettsburg, Kentucky.

Recent Developments

Private Placement of Securities

On June 29, 2011, the Company closed a private placement of securities which resulted in the sale of 44,444,444 common stock shares at a price of $0.45 per share and 100 shares of Series A Convertible Preferred Stock at a price of $100,000 per share.  Because the Company had only 100,000,000 common shares authorized, with not enough shares to cover the additional common shares needed to close the Private Placement at the pricing negotiated by the principal institutional investors, the Company issued preferred shares to Yorktown Energy Partners IX, L.P. which would automatically convert to common shares when the increase in authorized common shares (to 200,000,000 shares) was implemented under Delaware law.  On July 18, 2011, the increase was implemented, and the Company issued 22,222,222 common shares to Yorktown Energy Partners IX, L.P.  Upon the conversion, Carbon had issued a total of 66,666,666 shares of common stock at $0.45 per share, for $30 million in gross proceeds.

Net proceeds from the Private Placement were principally used for Nytis LLC to complete the acquisitions from ING and Alerion Drilling I, LLC described below.  After initially reducing the outstanding balance of its credit facility with the Bank of Oklahoma, the remainder of the net proceeds will be used to fund future acquisitions, drilling and completion activities and for general working capital purposes.

Interstate Natural Gas Company

On June 29, 2011, we held the final closing of the February 14, 2011 ING APA, as amended, between Nytis LLC as buyer and ING and certain related parties, as sellers to purchase certain natural gas properties, natural gas gathering and compression facilities and other assets related thereto, located in eastern Kentucky and four counties in West Virginia.

The ING Assets are comprised of (i) some but not all of ING’s leases and interests in oil and natural gas leases, and wells and wellbores thereon and related natural gas production equipment (ii) ING’s partnership interests in various general partnerships wherein ING is the managing general partner (at closing, Nytis LLC succeeded ING as managing general partner of these general partnerships, and owns ING’s partnership interests therein); (iii) ING’s partnership interests in other general partnerships in which it owns partnership interests but is not the managing general partner; (iv) ING’s interests in various farm-ins and similar agreements; (v) natural gas gathering and compression facilities related only to the acquired properties; and (vi) various other contracts, vehicles and equipment of ING related to the assets purchased, and easements and rights-of-way relating to or used in connection with the ownership and operation of the assets acquired.

19

The partnership interests included in the ING Assets (described in (ii) and (iii) above) include interests in approximately 162 of the 430 producing wells acquired.  In all of the partnerships, Nytis LLC succeeded ING as a full substitute partner; for those partnerships where ING was the managing general partner, Nytis LLC succeeded ING as managing general partner as well.

ING gathers its natural gas production through a series of mostly 2-4 inch gathering lines to numerous meter stations.  At these meter stations the gas is delivered directly into interstate transmission lines or into other gatherers or into one of several systems owned by local production companies for redelivery into interstate transmission.  Nytis LLC has assumed certain obligations to transport gas from wells 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 on the ING Closing Date.  Nytis LLC did not buy all of ING’s assets, or ING itself or its business generally.

On April 22 and June 29, 2011, Nytis LLC effected an initial (the “ING Initial Closing”) and subsequent close (the “ING Final Closing”).  The ING Initial Closing was in accordance with the April 14, 2011 amendment to the ING APA (the “ING APA Amendment”).  Under the ING APA Amendment, the parties agreed:

(i)	To permit ING to use a portion of the Deposit (the “Property Tax Draw”) to pay property taxes due and owing on the natural gas properties being sold by ING to Nytis LLC pursuant to the APA. The amount of the Property Tax Draw was credited to the ING Total Purchase Price at the ING Final Closing.
(ii)	To provide for two closings. The first closing was to be held on or before April 22, 2011 (extendable by either Nytis LLC or ING for a maximum of seven days), was for the purchase of approximately 45 natural gas wells (the “ING Initial Assets”), for not more than $1,519,932.

The second closing (the “Final Closing”) was to be held on or before May 23, 2011 (which date was extendable by either party but not beyond May 31, 2011) at which time Nytis LLC was to purchase the ING Assets (other than the ING Initial Assets) in accordance with the terms of the amended APA.

On April 22, 2011, Nytis LLC bought the ING Initial Assets at the Initial Closing, with a cash payment of $1,488,703, provided by a loan from Nytis LLC’s lending facility with Bank of Oklahoma.

On May 31, 2011 and again on June 14, 2011, Nytis LLC and ING agreed to further extensions of the Final Closing date, ultimately to a date no later than June 30, 2011.

Nytis LLC paid $450,000 as a Deposit into an escrow account when the original APA was signed.  There remains $200,000 in the escrow account to cover possible indemnity claims that Nytis LLC may bring within one year of the ING Final Closing.  The Effective Date of the acquisition under the APA was January 1, 2011.  The original purchase price of $29.6 million under the APA was reduced pursuant to adjustments:

(i)	up for all actual operating or capital expenditures or prepaid expenses attributable to the assets, (including if paid by ING at the ING Closing Date) paid by or on behalf of ING in connection with the assets and attributable to the period between the effective date and the ING Closing Date. These expenses included royalties, rentals and other charges; ad valorem and other taxes based on or measured by ownership of the assets, third-party expenses under joint operating agreements, and similar items;
(ii)	down for environmental and/or title defects related to the assets; money received by ING from the sale of production of natural gas and liquids after the Effective Date; costs and expenses relating to the assets attributable to the time before the Effective date but not paid by ING; unpaid ad valorem and similar taxes which become due and payable or accrue prior to the effective date; the $450,000 escrow deposit; distributions by the general partnerships or other entities allocated to the interests acquired, which are attributable to production or sale of oil or natural gas that occurred after the Effective Date; and similar items;
(iii)	down further for the $1,488,703 paid at the Initial Closing; and
(iv)	down further pursuant to the ING APA Amendment for the exclusion of certain ING assets from the transaction.

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At the Initial and Final Closings, we paid a total of approximately $24.2 million cash for the ING Assets: $1.5 million at the Initial Closing (funded through a loan from our credit facility), and $22.7 million at the Final Closing (from the Private Placement).  Because completion of the financing through the Private Placement took longer than anticipated, in addition to the amount paid at the Final Closing, Nytis LLC paid ING $500,000 in return for a promissory note which was cancelled at the Final Close and the amount due under the note was credited against the amount due ING at the Final Close and a total of $765,000 as additional purchase price adjustments and consideration for extending the date of the Final Closing to June 29, 2011.

Alerion Drilling I, LLC

Prior to the Final Closing, a portion of the ING Assets acquired by Nytis LLC from ING was 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 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.  Nytis LLC’s acquisition of the Alerion Partnership Assets was also effective as of January 1, 2011.  The purchase price paid by Nytis LLC for Alerion Drilling’s share of such assets was approximately $1.2 million, and adjusted:

(i)

up, for all actual operating or capital expenditures or prepaid expenses attributable to the assets, (including if paid by Alerion Drilling at closing) paid by or on behalf of Alerion Drilling attributable to the period between January 1, 2011 and closing, including royalties, rentals and other charges; ad valorem and other taxes based on or measured by ownership of the assets, third-party expenses under joint operating agreements, and similar items; and

(ii)

down for among others items: money received by Alerion Drilling from the sale of production of natural gas and liquids after January 1, 2011; costs and expenses relating to the assets attributable to the time before January 1, 2011 but not paid by Alerion Drilling; unpaid ad valorem and similar taxes which become due and payable or accrue prior to January 1, 2011; and distributions by the Alerion Partnership to Alerion Drilling attributable to production or sale of oil or natural gas that occurred after January 1, 2011.

Further Amendment to Certificate of Incorporation to Increase Authorized Common Stock Shares and Conversion of Series A Convertible Preferred Stock to Common

On July 18, 2011, a Certificate of Amendment to the Company’s Amended and Restated Certificate of Incorporation filed with the Delaware Secretary of State became effective and increased the number of shares of common stock, par value $0.01 per share, that the Company is authorized to issue from 100,000,000 to 200,000,000.

Further Amendment to Credit Facility

Effective June 29, 2011, as a result of the increase in proved reserves attributable to the assets acquired from ING, the borrowing base under Nytis LLC’s credit facility with Bank of Oklahoma was increased from $10 million to $20 million, and the maximum line for credit available under hedging arrangements was increased from $2.7 million to $5 million.  The maturity of all loans from the credit facility was extended from May 31, 2012 to May 31, 2014.

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Results of Operations

The following discussion and analysis relates to items that have affected our results of operations for the three months and six months ended June 30, 2011 and 2010.  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 June 30, 2011 Compared to Three Months Ended June 30, 2010

	Three Months Ended
	June 30,						Increase /			Percent
(in thousands except per unit data)	2011			2010			(Decrease)			Change
Revenue:
Oil and natural gas sales	$	1,253		$	1,089		$	164		15	%
Commodity derivative gain	64			(63		)	127			202	%
Other income	91			73			18			25	%
Total revenues	1,408			1,099			309			28	%
Expenses:
Lease operating expenses	446			254			192			76	%
Transportation costs	117			81			36			44	%
Production and property taxes	89			113			(24		)	-21	%
General and administrative	1,145			642			503			78	%
Depreciation, depletion and amortization	371			368			3			1	%
Accretion of asset retirement obligations	6			4			2			50	%
Impairment of oil and gas properties	1,063			—			1,063			*
Total expenses	3,237			1,462			1,775			121	%
Operating loss	$	(1,829	)	$	(363	)	$	(1,466	)	-404	%
Other income and expenses:
Interest income	$	—		$	10		$	(10	)	-100	%
Interest expense	(114		)	(19		)	95			500	%
Loss on disposition of fixed asset	—			—			—			*
Equity investment income	56			—			56			*
Total other income and expenses	$	(58	)	$	(9	)	(49		)	-544	%
Production data:
Natural gas (MMcf)	233			245			(12		)	-5	%
Oil and liquids (MBbl)	2			—			2			100	%
Combined (MMcfe)	245			245			—			—
Average prices before effects of hedges:
Natural gas (per Mcf)	$	4.62		$	4.38		$	0.24		5	%
Oil and liquids (per Bbl)	$	93.90		$	65.68		$	28.22		43	%
Combined (per Mcfe)	$	5.13		$	4.42		$	0.71		16	%
Average prices after effects of hedges**:
Natural gas (per Mcf)	$	4.89		$	4.12		$	0.77		19	%
Oil and liquids (per Bbl)	$	93.90		$	65.68		$	28.22		43	%
Combined (per Mcfe)	$	5.39		$	4.16		$	1.23		30	%
Average costs (per Mcfe):
Lease operating expenses	$	1.83		$	1.03		$	0.80		78	%
Transportation costs	$	0.48		$	0.33		$	0.15		45	%
Production and property taxes	$	0.37		$	0.46		$	(0.09	)	-20	%
Depreciation, depletion and amortization	$	1.52		$	1.49		$	0.03		2	%

*Not meaningful or applicable

**Includes realized and unrealized commodity derivative gains

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Oil and natural gas sales- Revenues from sales of natural gas and oil and liquids increased to $1.3 million for the three months ended June 30, 2011 from $1.1 million for the three months ended June 31, 2010, an increase of 15%. This increase was primarily due to a 16% increase in the average price per Mcfe. For the quarter ending June 30, 2011, natural declines in gas production and declines attributed to pipeline constraints were offset by an increase in oil production from a new producing well in Kentucky and new producing gas wells in Illinois.

Commodity derivative gains- 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 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 for the fixed price we will receive from future production.  For the three months ended June 30, 2011 we had hedging gains of approximately $64,000 compared to hedging losses of approximately $63,000 for the three months ended June 30, 2010.

Lease operating expenses- Lease operating expenses increased to approximately $446,000 for the three months ended June 30, 2011 from $254,000 for the three months ended June 30, 2010.  Increases were primarily due to major repairs to roads and well sites damaged by area flooding in Kentucky and West Virginia and the addition of new wells principally in Illinois and Kentucky. On a per Mcfe basis, lease operating expenses increased from $1.03 per Mcfe for the three months ended June 30, 2010 to $1.83 per Mcfe for the three months ended June 30, 2011.

Transportation costs- Transportation costs increased from approximately $81,000 for the three months ended June 30, 2010 to approximately $117,000 for the three months ended June 30, 2011 due to transportation price increases and transportation costs for new producing properties located in Illinois and Kentucky.  On a per Mcfe basis, these expenses increased from $.33 per Mcfe for the three months ended June 30, 2010 to $.48 per Mcfe for the three months ended June 30, 2011.

Production and property taxes- Production and property taxes decreased from approximately $113,000 for the three months ended June 30, 2010 to approximately $89,000 for the three months ended June 30, 2011 primarily due to lower revenues in states with higher tax rates.  On a per Mcfe basis, these expenses decreased from $.46 per Mcfe for the three months ended June 30, 2010 to $.37 per Mcfe for the three months ended June 30, 2011.

Depreciation, depletion and amortization (DD&A)- DD&A increased from approximately $368,000 for the three months ended June 30, 2010 to approximately $371,000 for the three months ended June 30, 2011.  On a per Mcfe basis, these expenses increased from $1.49 per Mcfe for the three months ended June 30, 2010 to $1.52 per Mcfe for the three months ended June 30, 2011.  Depletion rates are impacted by capital expenditures, future development costs, impairment expense and changes in reserves.  Lower gas prices may cause a reduction in reserves.  An increase in future development costs associated with proved undeveloped reserves (included in the depletion calculation)  from March 31, 2011 to June 30, 2011 offset the impact of the impairment expense recognized in the first quarter of 2011 and resulted in the depletion rate remaining unchanged between the first and second quarters of 2011.

Impairment of oil and gas properties- The Company recognized a non-cash impairment expense of approximately $1.1 million due to the Company’s full cost pool exceeding the ceiling limitation as of June 30, 2011.  The Company did not recognize any non-cash impairment charges for the quarter ended June 30, 2010.

General and administrative expenses- General and administrative expenses increased from approximately $642,000 for the three months ended June 30, 2010 to approximately $1.1 million for the three months ended June 30, 2011 primarily due to costs totaling approximately $299,000 associated with the merger with SLSC and the acquisition of the ING Assets and increased costs of approximately $99,000 related to legal and audit, and insurance fees and other public company related costs.

Interest expense- Interest expense increased from approximately $19,000 for the three months ended June 30, 2010 to approximately $114,000 for the three months ended June 30, 2011 primarily due to a higher debt balance during the quarter ended June 30, 2011 as compared with the same period in 2010.  In the first quarter of 2010, the

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Company used proceeds from the disposition of the Company’s Pennsylvania assets to pay down approximately $23.5 million of debt on the Company’s credit facility which resulted in a lower debt balance and interest expense for second quarter of 2010.  During the second quarter of 2011, the Company utilized its credit facility to fund the initial close of the ING Assets and related expenses.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

	Six Months Ended
	June 30,						Increase /			Percent
(in thousands except per unit data)	2011			2010			(Decrease)			Change
Revenue:
Oil and natural gas sales	$	2,507		$	2,652		$	(145	)	-5	%
Commodity derivative gain	125			411			(286		)	-70	%
Other income	189			123			66			54	%
Total revenues	2,821			3,186			(365		)	-11	%
Expenses:
Lease operating expenses	689			512			177			35	%
Transportation costs	272			122			150			123	%
Production and property taxes	197			211			(14		)	-7	%
General and administrative	2,589			1,734			855			49	%
Depreciation, depletion and amortization	747			800			(53		)	-7	%
Accretion of asset retirement obligations	12			9			3			33	%
Impairment of oil and gas properties	8,379			—			8,379			*
Total expenses	12,885			3,388			9,497			280	%
Operating loss	$	(10,064	)	$	(202	)	$	9,862		4882	%
Other income and expenses:
Interest income	$	—		$	19		$	(19	)	-100	%
Interest expense	(192		)	(250		)	(58		)	-23	%
Loss on disposition of fixed asset	(13		)	—			(13		)	*
Equity investment income	41			—			41			*
Gain on sale of properties	—			9,877			(9,877		)	*
Total other income and expenses	$	(164	)	$	9,646		$	(9,810	)	-102	%
Production data:
Natural gas (MMcf)	496			516			(20		)	-4	%
Oil and liquids (MBbl)	3			—			3			*
Combined (MMcfe)	514			516			(2		)	*
Average prices before effects of hedges:
Natural gas (per Mcf)	$	4.51		$	5.10		$	(0.59	)	-12	%
Oil and liquids (per Bbl)	$	88.94		$	55.01		$	33.93		62	%
Combined (per Mcfe)	$	4.87		$	5.12		$	(0.25	)	-5	%
Average prices after effects of hedges**:
Natural gas (per Mcf)	$	4.76		$	5.90		$	(1.14	)	-19	%
Oil and liquids (per Bbl)	$	88.94		$	55.01		$	33.93		62	%
Combined (per Mcfe)	$	5.12		$	5.91		$	(0.79	)	-13	%
Average costs (per Mcfe):
Lease operating expenses	$	1.34		$	0.99		$	0.35		35	%
Transportation costs	$	0.53		$	0.24		$	0.29		121	%
Production and property taxes	$	0.38		$	0.41		$	(0.03	)	-7	%
Depreciation, depletion and amortization	$	1.45		$	1.54		$	(0.09	)	-6	%

*Not meaningful or applicable

**Includes realized and unrealized commodity derivative gains

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Oil and natural gas sales- Revenues from sales of natural gas and oil and liquids decreased to $2.5 million for the six months ended June 30, 2011 from $2.7 million for the six months ended June 30, 2010, a decrease of 5%. This was primarily due to a 12% decrease in the average price per Mcfe and a decline in natural gas production attributed to the disposition of the Company’s Pennsylvania producing properties in the first quarter of 2010 and natural declines.  Approximately 7% of the Company’s natural gas revenues for the first six months of 2010 were generated from the Company’s Pennsylvania producing properties.  The decrease in gas production and related revenues caused by natural declines was partially offset by new oil production and related revenues from a new producing oil well in Kentucky.

Commodity derivative gains- 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 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 for the fixed price we will receive from future production.  For the six months ended June 30, 2011 we had hedging gains of approximately $125,000 compared to hedging gains of approximately $411,000 for the six months ended June 30, 2010.

Lease operating expenses- Lease operating expenses increased approximately 35% for the six months ended June 30, 2011 compared to the six months ended June 30, 2010 primarily due to major repairs to roads and well sites damaged by area flooding in Kentucky and West Virginia and the addition of new wells principally in Illinois and Kentucky.  These costs were partially offset by the disposition of the Company’s Pennsylvania assets in the first quarter of 2010.  On a per Mcfe basis, lease operating expenses increased from $0.99 per Mcfe for the six months ended June 30, 2010 to $1.34 per Mcfe for the six months ended June 30, 2011.

Transportation costs- Transportation costs increased from approximately $122,000 for the six months ended June 30, 2010 to approximately $272,000 for the six months ended June 30, 2011 due to transportation price increases and transportation costs for new production from the Company’s Illinois properties.  The Company also entered into new firm transportation agreements for properties located in Kentucky and West Virginia.  On a per Mcfe basis, these expenses increased from $.24 per Mcfe for the six months ended June 30, 2010 to $.53 per Mcfe for the six months ended June 30, 2011.

Production and property taxes- Production and property taxes decreased from approximately $211,000 for the six months ended June 30, 2010 to approximately $197,000 for the six months ended June 30, 2011 primarily due to new natural gas production in the Illinois Basin and new oil production in the Appalachian Basin for the six months ended June 30, 2011.  On a per Mcfe basis, these expenses decreased from $.41 per Mcfe for the six months ended June 30, 2010 to $.38 per Mcfe for the six months ended June 30, 2011 due to a decrease in taxable production revenues.  The disposition of the Company’s Pennsylvania assets reduced production volumes and revenues, but did not decrease production and property taxes as revenues from these properties did not have a production or property tax burden.  Although gas production volumes and related revenues are lower in the six months ended June 30, 2011 compared to the six months ended June 30, 2010, the per unit production and property taxes increased as the disposition of production that was not burdened with production and property taxes was partially replaced with production revenues that are burdened with production and property taxes.

Depreciation, depletion and amortization (DD&A)- DD&A decreased from approximately $800,000 for the six months ended June 30, 2010 to approximately $747,000 for the six months ended June 30, 2011.  On a per Mcfe basis, these expenses increased from $1.54 per Mcfe for the six months ended June 30, 2010 to $1.45 per Mcfe for the six months ended June 30, 2011.  This decrease was caused by lower natural gas production in the first half of 2011 as compared with the same period in 2010.

Impairment of oil and gas properties- The Company recognized a non-cash impairment expense of approximately $8.4 million due to the Company’s full cost pool exceeding the ceiling limitation for the six month period ended June 30, 2011, respectively.  A further decline in oil and natural gas prices could result in a further impairment of the Company’s oil and gas properties in subsequent periods.  In the first six months of 2010, the Company did not record a non-cash impairment.

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General and administrative expenses- General and administrative expenses increased from $1.7 million for the six months ended June 30, 2010 to $2.6 million for the six months ended June 30, 2011 primarily due to costs totaling approximately $621,000 associated with the merger with SLSC and the acquisition of the ING Assets.  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 which also contributed to the increase in general and administrative expenses in the first half of 2011 as compared with the first half of 2010.

Interest expense- Interest expense decreased from approximately $250,000 for the six months ended June 30, 2010 to approximately $192,000 for the six months ended June 30, 2011 primarily due to lower debt balances during the first quarter in 2011 as compared with the same period in 2010.  During the six month period ended June 30, 2010, the Company paid down its outstanding debt by approximately $23.5 million with a portion of the proceeds from the disposition of the Company’s Pennsylvania assets in the first quarter of 2010.  During the six month period ended June 30, 2011, the Company’s debt increased due to borrowings used for the initial close of the ING Assets acquisition and related expenses, and for costs incurred related to the merger and Private Placement.

Gain on sale of oil and gas properties- In March 2010, the Company sold all of its interests in the Pennsylvania assets owned by Nytis LLC and Nytis Pennsylvania to a third party for approximately $30.2 million, net of normal adjustments and transaction fees, with an effective date of February 1, 2010.  Proceeds from the sale were used to reduce outstanding borrowings due under the Company’s credit facility and to reduce amounts due Nytis Exploration Company.  Because the sale of these assets significantly altered the relationship between capitalized costs and proved reserves, the Company recorded a gain in the first quarter of 2010.

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 facilities as our primary sources of liquidity and, as market conditions have permitted, we have engaged in asset monetization transactions, such as the divestiture of our Pennsylvania assets.

Changes in the market prices for oil and natural gas directly impact our level of cash flow generated from operations.  For the quarter and six months ended June 30, 2011, natural gas made up approximately 95% and 96%, respectively, 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 June 30, 2011, we have outstanding hedges of 120,000 MMbtu for 2011 at an average price of $5.03 per MMbtu and 160,000 MMbtu for 2012 at an average price of $5.11 per MMbtu.  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 2011 and 2012.  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 Amended Current Report on Form 8-K/A filed with the SEC on April 15, 2011 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 June 30, 2011, our derivative counterparty was party to our credit facility, or its affiliates.

The other primary source of liquidity is our U.S. credit facility (described below), which had an aggregate borrowing base of $20.0 million as of June 30, 2011.  This 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 a portion of our assets and matures in May 2014. See—“Bank Credit Facility” below for further details. We had approximately $9.8 million drawn on our credit facility as of June 30, 2011.

Our ability to access the debt and equity capital markets on economical terms is affected by general economic conditions, the domestic and global financial markets, our operational and financial performance, the value of our equity securities, prevailing commodity prices, and other macroeconomic factors outside of our control.

We believe that our current cash and cash equivalents, cash flows provided by operating activities, and $10.2 million of funds available under our credit facility at June 30, 2011 will be sufficient to fund our normal recurring operating needs, anticipated capital expenditures (other than the potential acquisition of additional natural gas and

26

oil properties), and our contractual obligations. However, if our revenue and cash flow decrease 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 Amended Current Report on Form 8-K/A filed with the SEC on April 15, 2011 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 June 30, 2011 was at $20.0 million.  On June 10, 2011, Nytis LLC and Bank of Oklahoma amended the Credit Facility to provide an increase in the Borrowing Base to $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 natural gas properties in accordance with the lenders’ customary practices for 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 2011. 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 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 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 four consecutive fiscal quarters as of the end of any fiscal quarter.  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.

Under the Credit Facility, we are required to mortgage and grant a security interest in 80% of the present value of our proved natural gas properties. Under certain circumstances, we could be obligated to pledge additional assets as collateral.

Of the $50.0 million total nominal amount under the Credit Facility, Bank of Oklahoma held 100% of the total commitments.  As of June 30, 2011 there was $9.8 million borrowed under our Credit Facility.

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 $5.0 million.

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Historical Cash Flow

Net cash provided by (used in) operating activities, net cash provided by (used in) investing activities, and net cash provided by (used in) financing activities for the six months ended June 30, 2011 and 2010 were as follows:

	Six Months Ended
	June 30,
(in thousands)	2011			2010
Net cash provided by (used in) operating activities	$	(2,687	)	$	(3,416	)
Net cash provided by (used in) investing activities	$	(26,934	)	$	27,266
Net cash provided by (used in) financing activities	$	36,219		$	(23,543	)

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 $729,000 for the six months ended June 30, 2011 as compared to the six months ended June 30, 2010 was primarily due to decreases in working capital.

Net cash provided by (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 decrease in investing cash flows of approximately $54.2 million for the six months ended June 30, 2011 as compared to the six months ended June 30, 2010 was primarily due to the acquisition of oil and gas properties from ING in second quarter of 2011 and the proceeds received by the disposition of the Company’s Pennsylvania assets in the first quarter of 2010.

The increase in financing cash flows of $59.8 million for the six months ended June 30, 2011 as compared to the six months ended June 30, 2010 was primarily due to the proceeds received from the issuance of common and preferred shares in the second quarter of 2011 and the net repayments of bank borrowings of $23.5 million from proceeds received by the disposition of the Company’s Pennsylvania assets in the first quarter of 2010.  See “Capital Expenditures” below for more detail on our capital expenditures.

Capital Expenditures

Capital expenditures for the six months ended June 30, 2011 and 2010 are summarized in the following table:

	Six Months Ended June 30,
(in thousands)	2011		2010
Acquisition of oil and gas properties:
Unevaluated properties	$	155	$	43
Proved producing properties	37,135		1,274
Drilling and development	675		1,289
Pipeline and gathering	41		96
Other	71		—
Total capital expenditures	$	38,077	$	2,702

Capital expenditures reflected in the table above differ from the amounts shown in the statements of cash flows in the consolidated financial statements.  Amounts reflected in the table above include changes in accounts payable from the previous reporting period for capital expenditures and a non-controlling equity interest of approximately $6.0 million associated with partnership consolidation of proved producing properties acquired, while the amounts in the statements of cash flow in the consolidated financial statements are presented on a cash basis.

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Due to the significant downturn in the overall economy and its impact on the price for natural gas, we chose to reduce our capital expenditures and drilling activity for the six months ended June 30, 2011 and 2010 by keeping our exploration and development capital spending near our cash flows which the Company can manage as it controls and operates substantially all the wells in which it has an interest.  Primary factors impacting the level of our capital expenditures include natural gas prices, the volatility in these prices, the cost and availability of oil field services, general economic and market conditions, and weather disruptions.  As of June 30, 2011, the Company’s quarterly ceiling test amount closely approximated the Company’s capitalized costs.  A further decline in oil and natural gas prices could result in an impairment of the Company’s oil and gas properties in subsequent periods.

Critical Account Policies

There have been no material changes in our critical accounting policies since December 31, 2010, and a detailed discussion of the nature of our accounting practices can be found in the section titled “Critical Accounting Policies, Estimates, Judgments, and Assumptions” included on Form 8-K/A filed with the SEC for St. Lawrence Seaway Corporation for the year ended December 31, 2010.

Forward Looking Statements

The information in this Quarterly Report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are statements other than statements of historical or present facts, that address activities, events, outcomes, and other matters that the Company plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates, or anticipates (and other similar expressions) will, should, or may occur in the future. Generally, the words “expects,” “anticipates,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “may,” “will,” “could,” “should,” “future,” “potential,” “continue,” variations of such words, and similar expressions identify forward-looking statements. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

These forward-looking statements appear in a number of places in this report and include statements with respect to, among other things:

·estimates of our natural gas and oil reserves;

·estimates of our future natural gas and oil production, including estimates of any increases or decreases in our production;

·our future financial condition and results of operations;

·our future revenues, cash flows, and expenses;

·our access to capital and our anticipated liquidity;

·our future business strategy and other plans and objectives for future operations;

·our outlook on natural gas and oil prices;

·the amount, nature, and timing of future capital expenditures, including future development costs;

·our ability to access the capital markets to fund capital and other expenditures;

·our assessment of our counterparty risk and the ability of our counterparties to perform their future obligations; and

·the impact of federal, state, and local political, regulatory, and environmental developments in the United States and certain foreign locations where we conduct business operations.

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We believe the expectations and forecasts reflected in our forward-looking statements are reasonable, but we can give no assurance that they will prove to be correct. We caution you that these forward-looking statements can be affected by inaccurate assumptions and are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, and sale of oil and gas. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included or incorporated in Part 1A of our Amended Current Report on Form 8-K/A filed with the SEC on April 15, 2011.

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.

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 June 30, 2011, 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.

Reconciliation of 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 less net income attributed to non-controlling interests and 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, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. EBITDA and Adjusted EBITDA provide no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. EBITDA and Adjusted EBITDA do not represent funds available for discretionary use because those funds are required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, our management team believes EBITDA and Adjusted EBITDA are useful to an investor in evaluating our operating performance because these measures:

·are widely used by investors in the natural gas and oil industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors; and

·helps 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.

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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 six months ended June 30, 2011 and 2010.

	Three Months			Three Months
	Ended			Ended
	June 30,			June 30,
(in thousands)	2011			2010
Net (loss) income	$	(1,784	)	$	(992	)
Adjustments:
Interest expense	114			19
Income taxes	—			620
Depreciation, depletion and amortization	371			368
EBITDA	(1,299		)	15
Adjusted EBITDA
EBITDA	(1,299		)	15
Adjustments:
Accretion of asset retirement obligations	6			4
Impairment of oil and gas properties	1,063			—
Net loss attributed to non-controlling interests	(103		)	—
Adjusted EBITDA	$	(333	)	$	19

	Six Months			Six Months
	Ended			Ended
	June 30,			June 30,
(in thousands)	2011			2010
Net (loss) income	$	(10,125	)	$	3,272
Adjustments:
Interest expense	192			250
Income taxes	—			5,404
Depreciation, depletion and amortization	747			800
EBITDA	(9,186		)	9,726
Adjusted EBITDA
EBITDA	(9,186		)	9,726
Adjustments:
Net income attributed to non-controlling interests	—			767
Accretion of asset retirement obligations	12			8
Impairment of oil and gas properties	8,379			—
Net loss attributed to non-controlling interests	(103		)	—
Gain on sale of oil and gas properties	—			(9,877		)
Adjusted EBITDA	$	(898	)	$	624

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

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controls and procedures as defined in Rules 13a - 15(e) and 15d-15(e) under the Exchange Act as of June 30, 2011.  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 June 30, 2011 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There has not been any change in our internal control over financial reporting that occurred during our quarterly period ended June 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II.  OTHER INFORMATION

ITEM 1.  Legal Proceedings

The Company is subject to legal claims and proceedings in the ordinary course of its oil and natural gas exploration and development business.  Management believes that none of the current pending proceedings would have a material adverse effect on the Company, should the controversies be resolved against the Company.  Notwithstanding management’s belief that there are no claims that could have a material effect on the financial condition or results of the Company’s operations, the Company’s indirect subsidiary, Nytis LLC, is involved in the following matters:

In July 2010, Nytis LLC, a Delaware limited liability company and 98.1% owned subsidiary of the Company received correspondence from the Pennsylvania Department of Revenue requesting additional information relating to whether the correct realty transfer tax was paid at the time of the closing of Nytis LLC’s acquisition of properties in Pennsylvania in 2006 from DCPA, LLC (an affiliate of Delta Petroleum Corporation).  Nytis LLC has submitted the requested information to the Pennsylvania Department of Revenue and is awaiting its response.

In November 2010, Nytis LLC was served with a summons and complaint brought by ICG Knott County, LLC and filed in Knott County, Kentucky.  The suit is in the nature of a quiet title action and concerns ICG’s claims that it is the party to which Nytis LLC should be making certain payments under several leases.  Also in November 2010, ICG Natural Resources, LLC filed suit against Nytis LLC in Floyd County, Kentucky concerning payments allegedly due under a certain coalbed methane lease.  Nytis LLC has engaged counsel to assist it in defending against these claims.

In August 2011, Nytis LLC was served with a summons and complaint brought by RLF Chinook Properties, LLC, Charles K. and Kimberly L. Butts, Chinook Project, LLC and Chinook Enterprises, LLC (collectively, “Chinook”) and filed in the Vigo Superior Court in Vigo County, Indiana.  The suit is in the nature of a quiet title action and Chinook seeks to invalidate certain coal seam gas leases currently held by Nytis LLC.  Addington Exploration, LLC (the party from which Nytis LLC obtained the leases at issue) was named as a co-defendant in the complaint.  Nytis LLC intends to defend itself against these claims with the assistance of Indiana counsel.

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

All unregistered sales of equity securities during the quarter ended June 30, 2011, and subsequently, have been previously disclosed in a Current Report on Form 8-K except as follows:

On July 18, 2011 the Company issued 22,222,222 shares of common stock to Yorktown Energy Partnership IX, LP upon conversion of 100 shares of the Company’s Series A Convertible Stock.  The

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shares of Series A Convertible Stock were issued as part of the Private Placement that closed on June 29, 2011.  Because the holder of the Series A Convertible Stock was an existing Company security holder and had previously represented that it qualified as an accredited investor, the Company relied on the exemptions from registration set forth in Sections 3(a)(9) and 4(2) of the Securities Act of 1933 and Rule 506 promulgated thereunder for this issuance.

ITEM 3.  Defaults Upon Senior Securities

Not applicable.

ITEM 5.  Other Information

On July 14, 2011, the Company filed a Certificate of Amendment to its Certificate of Incorporation with the Delaware Secretary of State, which had a delayed effective date of July 18, 2011, and which increased the number of shares of common stock Carbon is authorized to issue from 100,000,000 to 200,000,000 shares.  Prior to filing the Certificate of Amendment with the Delaware Secretary of State, the form and terms thereof were approved by the Carbon Board of Directors on June 10, 2011, and on June 14, 2011 by the holders of 37,867,771 shares of Carbon common stock (being approximately 80% of the then issued and outstanding shares).  The approval of the Certificate of Amendment and the increase in the number of authorized common stock shares was described in a Definitive Information Statement on Schedule 14C filed by Carbon with the Securities and Exchange Commission on June 28, 2011, and distributed to Carbon’s stockholders on June 28, 2011.

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ITEM 6.  Exhibits

Exhibit No.	Description
2.1	Agreement and Plan of Merger dated January 31, 2011 by and among the Company, St. Lawrence Merger Sub, Inc. and Nytis Exploration (USA), Inc., incorporated by reference to exhibit 2.1 to Form 8-K for St. Lawrence Seaway Corporation filed February 1, 2011.
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 or 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 March 31, 2011.
10.1	Asset Purchase Agreement, by and between The Interstate Natural Gas Company, LLC and Nytis Exploration Company LLC, dated February 14, 2011, incorporated by reference to exhibit 10.1 to Form 8-K for St. Lawrence Seaway Corporation filed on February 17, 2011.
10.2	Amended and Restated Credit Agreement, by and between Nytis Exploration Company LLC and Bank of Oklahoma, National Association, dated May 31, 2010, incorporated by reference to exhibit 10.2 to Form 8-K/A for St. Lawrence Seaway Corporation filed on March 31, 2011.
10.2(a)	Guaranty from Nytis USA to Bank of Oklahoma, National Association, dated June 21, 2005, incorporated by reference to exhibit 10.2(a) to Form 8-K/A for St. Lawrence Seaway Corporation filed on March 31, 2011.
10.2(b)	Consent of Guarantor and Amendment of Guaranty from Nytis USA to Bank of Oklahoma, National Association, dated May 31, 2010, incorporated by reference to exhibit 10.2(b) to Form 8-K/A for St. Lawrence Seaway Corporation filed on March 31, 2011.
10.3	Second Amendment of Amended and Restated Credit Agreement, Limited Waiver and Borrowing Base Redetermination, by and between Nytis Exploration Company LLC and Bank of Oklahoma, National Association, dated June 10, 2011, incorporated by reference to exhibit 10.3 to Form S-1 for Carbon Natural Gas Company filed on August 12, 2011.
10.4	Guaranty from the Company to Bank of Oklahoma, National Association, dated June 10, 2011, incorporated by reference to exhibit 10.4 to Form S-1 for Carbon Natural Gas Company filed on August 12, 2011.
10.5	Administrative Services Agreement by and among the Company, Nytis Exploration Company and Nytis Exploration Company LLC, dated June 29, 2011, incorporated by reference to exhibit 10.5 to Form S-1 for Carbon Natural Gas Company filed on August 12, 2011.
10.6	Form of Common Stock Purchase Agreement dated June 29, 2011, incorporated by reference to exhibit 10.1 to Form 8-K for Carbon Natural Gas Company filed on July 6, 2011.
10.7	Form of Preferred Stock Purchase Agreement dated June 29, 2011, incorporated by reference to exhibit 10.2 to Form 8-K for Carbon Natural Gas Company filed on July 6, 2011.
10.8	Form of Registration Rights Agreement dated June 29, 2011, incorporated by reference to exhibit 10.3 to Form 8-K for Carbon Natural Gas Company filed on July 6, 2011.
31.1*	Certification of Chief Executive Officer Pursuant to Rule 13a-15(e) / Rule 15d-15(e)
31.2*	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) / Rule 15(e)/15d-15(e)
32.1†	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002
32.2†	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002

*Filed herewith

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

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

	CARBON NATURAL GAS COMPANY
	(Registrant)
Date: August 17, 2011	By:	/s/ Patrick R. McDonald
		PATRICK R. MCDONALD,
		President and CEO
Date: August 17, 2011	By:	/s/ Kevin D. Struzeski
		KEVIN D. STRUZESKI
		Chief Financial Officer

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