Carbon Energy (CRBO) 10-K 2011 FY Annual report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 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)

State of incorporation: Delaware	I.R.S. Employer Identification No. 26-0818050
1700 Broadway - Suite 1170 - Denver, Colorado	80290
(Address of Principal Executive Offices)	(Zip Code)

Registrant’s telephone number, including area code: (720) 407-7030

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

Title of Each Class	Name of Each Exchange on which Registered
Common Stock, Par Value $0.01 Per Share	None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x

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 registrant 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 Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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 the definition 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 Act). Yes o No x

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 2011, the last business day of the registrant’s most recently completed second fiscal quarter, was $27,198,060 (based on the closing price of such stock).

There were 114,185,405 shares of the registrant’s common stock, par value $0.01 per share, outstanding as of March 12, 2012.

CARBON NATURAL GAS COMPANY
TABLE OF CONTENTS

		Page No.
	PART I
Item 1.	Business	1
Item 1A.	Risk Factors	17
Item 1B.	Unresolved Staff Comments	29
Item 2.	Properties	29
Item 3.	Legal Proceedings	29
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 8.	Financial Statements and Supplementary Data	45
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	71
Item 9A.	Controls and Procedures	71
Item 9B.	Other Information	72
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	72
Item 11.	Executive Compensation	74
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	79
Item 13.	Certain Relationships and Related Transactions, and Director Independence	81
Item 14.	Principal Accountant Fees and Services	82
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	83
	Signatures	86

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PART I

Item 1.    Business.

General

Throughout this Annual Report on Form 10-K, we use the terms “Carbon,” “Company,” “we,” “our,” and “us” to refer to Carbon Natural Gas Company and its subsidiaries. In the following discussion, we make statements that may be deemed “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). See “Forward-Looking Statements,” below, for more details. We also use a number of terms used in the oil and gas industry. See “Glossary of Oil and Gas Terms” for the definition of certain terms.

Carbon Natural Gas Company (a Delaware corporation reincorporated from Indiana in August 2007 and formerly known as St. Lawrence Seaway Corporation (“SLSC”), which was organized in Indiana on March 31, 1959), owns and operates natural gas and crude oil interests in the Appalachian and Illinois Basins of the United States.  It produces and sells natural gas, natural gas condensate, natural gas liquids and crude oil.  Carbon’s acreage is held and its exploration and production activities are conducted indirectly through majority-owned subsidiaries.

·Nytis Exploration (USA) Inc. (“Nytis USA”) was organized as a Delaware corporation in 2004.  Pursuant to the Merger, Nytis USA is owned 100% by Carbon.

·Soon after formation, Nytis USA identified natural gas and oil interests located in Clearfield County, Pennsylvania, and organized (along with a minority owner) a subsidiary limited liability company, Nytis Exploration of Pennsylvania LLC, a Pennsylvania limited liability company (“Nytis PA”), which acquired those interests.  Nytis PA is owned 85% by Nytis USA.  Nytis PA is currently being dissolved and its business is being wound up with all assets being sold or distributed to its members.

·Thereafter, Nytis USA identified natural gas and oil interests (owned by Addington Exploration, LLC (“Addington”)) located primarily in Illinois, Indiana, Kentucky, Ohio, Tennessee and West Virginia.  To acquire the Addington assets, Nytis USA formed (along with a different unaffiliated person) Nytis Exploration Company LLC (“Nytis LLC”).  Nytis LLC is owned 98.1% by Nytis USA.  Nytis LLC continued acquiring interests including the 2006 acquisition of Pennsylvania properties from DCPA, LLC (an affiliate of Delta Petroleum Corporation).  In 2010, Nytis PA and Nytis LLC sold all of the Pennsylvania assets and received total proceeds of approximately $30.3 million ($21 million to Nytis LLC and $9.3 million to Nytis PA).  In this transaction, Nytis PA sold all of its assets, and this subsidiary is being dissolved and its business wound up.

·On January 31, 2011, Nytis USA entered into an Agreement and Plan of Merger (the “Merger Agreement”) with SLSC, which was closed on February 14, 2011.  At that date, SLSC acquired all of the issued and outstanding shares of Nytis USA from the Nytis USA stockholders, and thereby became the indirect owner of all of Nytis USA’s equity interests in Nytis LLC and Nytis PA, in exchange for the issuance by SLSC to the Nytis USA stockholders of 47,000,003 restricted shares of SLSC common stock (which then constituted 98.9% of SLSC’s issued and outstanding common stock), Nytis USA became a wholly-owned subsidiary of SLSC, and Nytis LLC and Nytis PA became majority-owned indirect subsidiaries of SLSC (the “Merger”).  The transactions contemplated by the Merger Agreement were intended to be a “tax-free” reorganization under Sections 351 and/or 368 of the Internal Revenue Code of 1986.

·Now, substantially all the natural gas and oil interests are owned by Nytis LLC, which continues to acquire and develop properties.  As of December 31, 2011, Nytis LLC owned interests in approximately 834 gross (534 net) productive natural gas and oil wells and approximately 310,000 (268,000 net) undeveloped acres in the Appalachian and Illinois Basins.

In connection with the closing of the Merger, the officers and directors of Nytis USA became the officers and directors of SLSC.

Prior to the Merger closing, SLSC was a “shell company” (as defined in Rule 12b-2 under the Securities Exchange Act of 1934 (the “Exchange Act”)), with no operations and nominal cash assets.  As a result of the Merger, SLSC exited shell company status as of February 17, 2011, when it filed a Form 8-K with complete “Form 10 Information” as required by Item 2.01(f) of Form 8-K.  On May 2, 2011, SLSC’s name was changed to Carbon Natural Gas Company.

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Carbon is a holding company which conducts substantially all its natural gas and oil operations through Nytis LLC.  Nytis LLC holds an interest in 42 consolidated partnerships and records the non-controlling owners’ interest in the net assets and income.

Strategy

Our strategy is to create shareholder value through consistent growth in production and reserves by drilling on existing properties and the acquisition of complementary properties. We emphasize the development of the Company’s existing leasehold which consists primarily of low risk, repeatable resource plays.  We invest significantly in technical staff, and geological and engineering technology to enhance the value of our properties.

Principal strategy components:

·Concentrate on resources in core operating areas. Our current focus on the Appalachian and Illinois Basins allows the Company to capitalize on its regional expertise to optimize drilling and completion techniques and production and reserve growth.  Numerous objective reservoirs permit us to allocate capital among opportunities based on risked well economics, with a view to balancing the portfolio to achieve consistent and profitable growth in production and reserves.

Some of our proved reserves and resources are classified as unconventional, including fractured shale natural gas plays, tight gas sands, and coalbed methane.  Our technical team has significant experience in drilling vertical, horizontal and directional wells, as well as fracture stimulation of unconventional formations. We utilize the latest geologic, drilling and completion technologies to increase the predictability and repeatability of finding and recovering hydrocarbons in these unconventional plays.

·Production increased from 1,000 Mcfe per day average for the year ended December 31, 2005, to 7,000 Mcfe per day at year ended December 31, 2011.  Estimated proved reserves increased from 15.6 Bcfe at December 31, 2004 to 63.2 Bcfe excluding approximately 4.1 Bcfe of estimated proved reserves attributable to minority interests of consolidated partnerships at December 31, 2011.

·Proven executive management team with track record of value creation.  The Company’s acreage positions provide multiple resource play opportunities.  Our management and technical personnel have extensive experience operating in the Appalachian and Illinois Basins, and have successfully built and sold unconventional resource companies in the past.

·Low-risk development drilling in established resource plays, and flexibility in deployment of exploration and infrastructure capital.  At December 31, 2011, the Company had a multi-year drilling inventory of approximately 1,100 potential horizontal drilling locations on acreage then held. This is a reduction from previously stated potential locations due to the application of horizontal drilling technology wherein one horizontal well can replace the need to drill multiple vertical wells.  Carbon drilled or participated in over 100 vertical or horizontal wells from January 2005 through December 31, 2011, with a success rate of approximately 98%.  Approximately 10% of the drilling locations are included in our estimated proved reserve base at December 31, 2011. The concentrated leasehold position has been delineated largely through drilling done by us, as well as with other industry players.

This property profile is subject to change as we acquire and dispose of various parcels.  In 2010, in addition to selling all our interests (for approximately $30.3 million in gross proceeds) in Pennsylvania assets to a third party, we also sold some undeveloped acreage in West Virginia, bought an interest in 19 wells in Kentucky, acquired  additional interests in 39 productive wells in Indiana, and bought a 50% interest in a company that owns and operates a gas gathering system in the Illinois Basin (this latter transaction added to infrastructure for the Company’s coalbed methane play in the Illinois Basin).  Also, in 2009, we were paid a total of $2.7 million for two separate farmout agreements, by which we reduced capital exposure to dry hole risk, and retained a significant working interest plus overriding royalty interest upside potential. See Note 4 to the Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations.

·Low cost operation.  Our geographic and operating focus and the shallow nature of our drilling activities and producing wells provides for low finding and development and lease operating costs.

·Maintain financial flexibility and conservative financial position.  We typically use cash flow from operations and our bank credit facility with Bank of Oklahoma to fund acquisition and development drilling. In 2010, we repaid $23.5 million of borrowings under our bank credit facility with proceeds from the 2010 disposition of the Pennsylvania assets.

At June 29, 2011, as a result of the increase in proved reserves attributable to the assets acquired from The Interstate Natural Gas Company, the capacity under our bank credit facility 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 $5.0 million.  At

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December 31, 2011, approximately $11.2 million of the credit line was available and $8.8 million was outstanding.  The maturity of all loans from the credit facility was extended from May 31, 2012 to May 31, 2014.

·Control over operating decisions and capital program.  At December 31, 2011, we had an average working interest of 64% in our productive wells and operated 86% of our production.  The high percentage of operated wells allows us to effectively control operating costs, and to better manage the timing of development activities, application of technological enhancements and marketing of production.

·Manage commodity price exposure through an active hedging program.  We maintain a hedging program designed to mitigate volatility in commodity prices and regional basis differentials. As of December 31, 2011, we have outstanding natural gas hedges of 160,000 MMbtu for 2012 at an average price of $5.11 per MMbtu and oil hedges of 6,000 barrels for 2012 at an average price of $99.30. Substantially all of the hedges are at regional sales points in our operating regions, which mitigates the risk of basis differential.

·Manage midstream assets and secure firm takeaway capacity.  We own natural gas gathering and compression facilities in the Illinois and Appalachian Basins.  We believe owning the gathering and compression infrastructure allows us to decrease dependence on third parties, and better manage the timing of our development and the received/netback pricing from the markets in which we sell our production.  In addition, to the extent that we are at risk related to pipeline capacity constraints, we have secured sufficient long-term firm takeaway capacity on major pipelines to accommodate our existing and expected production.

Core Operational Areas

Our oil and gas properties are located primarily in Illinois, Indiana, Kentucky, Tennessee, and West Virginia.  The map below shows locations of the Company’s natural gas and oil properties as of December 31, 2011.

Appalachian Basin

As of December 31, 2011, Nytis LLC owns working interests in 629 gross wells (505 net) and royalty interests in an additional 149 wells located in Kentucky, Ohio, Tennessee and West Virginia, and has leasehold positions in approximately 34,000 net developed acres and approximately 235,000 net undeveloped acres.  As of December 31, 2011, net sales were approximately 6,300 Mcfe per day.   Objective formations are the Berea Sandstone (for oil), and the Chattanooga Shale, Devonian Shale, Lower Huron Shale and other zones which produce natural gas.

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Illinois Basin

As of December 31, 2011, Nytis LLC owns working interests in 64 gross (29 net) primarily coalbed methane wells in the Illinois Basin and has a leasehold position in approximately 4,000 net developed acres and approximately 88,000 net undeveloped acres.  As of December 31, 2011, net natural gas sales were approximately 600 Mcf per day.

Acquisition and Divestiture Activities

Acquisitions

We pursue acquisitions that meet our criteria for investment returns and are consistent with our low-risk development focus.  Acquisitions in and around our existing core areas enable us to leverage our cost control abilities, technical expertise, and existing land and infrastructure positions. In general, our acquisition program has focused on acquisitions of properties that have development drilling opportunities and undeveloped acreage.

The Interstate Natural Gas Company

On June 29, 2011, we held the final closing of the February 14, 2011 Asset Purchase Agreement, as amended (the “ING APA”), between Nytis LLC as buyer and The Interstate Natural Gas Company, LLC and certain related parties, as sellers (hereafter collectively referred to as “ING”) to purchase certain natural gas properties, natural gas gathering and compression facilities and other assets related thereto, located in Kentucky and West Virginia.

The ING Assets are comprised of (i) 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; 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.

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 gathered 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 from ING.  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 affected an initial (the “Initial Closing”) and subsequent close (the “Final Closing”).  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 (the “Alerion APA”) 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

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the Alerion Partnership Assets was effective as of January 1, 2011.  The purchase price paid by Nytis LLC for Alerion Drilling’s share of the assets was approximately $1.2 million.

For additional information on other acquisition transactions, see Note 4 to the Consolidated Financial Statements.  See also, “Recent Developments” below.

Divestitures

In February and March of 2010, Nytis LLC and Nytis PA sold all of their assets located in Pennsylvania for a purchase price of $30.3 million ($21.0 million to Nytis LLC and $9.3 million to Nytis PA).  The assets sold comprised all of the assets of Nytis PA and as a result, this subsidiary is in the process of being dissolved and its business wound up.  In addition, the assets sold comprised all of the assets of Nytis LLC located in Pennsylvania, including approximately 160 wells with net monthly production of approximately 28.3 MMcf.  For detailed information on other divestiture transactions, see Note 4 to the Consolidated Financial Statements.

Reserves

In connection with the Company’s acquisition of the ING assets in 2011, it acquired ING’s partnership interests in various general partnerships.  For partnerships where the Company acquired a controlling interest, the partnerships are consolidated.  The following table summarizes our estimated quantities of proved reserve interests and the pre-tax PV-10 as December 31, 2011 after consolidating these partnerships, in which the Company has a controlling interest and the Company’s estimated quantities of proved reserve interests and the pre-tax PV10 as of December, 31, 2010.

Pre-tax PV-10 value, which is not a financial measure accepted under GAAP, is shown because it is a widely used industry standard.

Estimated Consolidated Proved Reserves

Including Non-Controlling Interests of Consolidated Partnerships

	December 31,
	2011			2010
Proved developed reserves:
Natural gas (MMcf)	44,103			17,482
Oil and liquids (MBbl)	411			72
Total proved developed reserves (MMcfe)	46,572			17,914
Proved undeveloped reserves:
Natural gas (MMcf)	18,849			37,178
Oil and liquids (MBbl)	321			74
Total proved undeveloped reserves (MMcfe)	20,772			37,622
Total proved reserves (MMcfe)	67,344			55,536
Percent developed	69.2		%	32.3		%
PV-10 (thousands)	$	48,889		$	20,952
Average natural gas price used (per Mcf)	$	4.37		$	4.39
Average oil and liquids price used (per Bbl)	$	89.07		$	75.41

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The estimated quantities of proved reserves for the non-controlling interests of the consolidated partnerships are approximately 4.1 Bcfe which is approximately 6.1 percent of total consolidated proved reserves.

The decrease in proved undeveloped reserves from December 31, 2010 to December 31, 2011 was attributable to the following factors:

	MMcfe
Extensions and discoveries	10,566
Revisions of previous estimates	(26,531	)
Conversion to proved developed	(885	)
Change in proved undeveloped reserves	(16,850	)

The revisions of previous estimates in 2011 is primarily attributed to the loss of proved undeveloped natural gas locations due to marginal economics on certain locations as a result of a decline in natural gas prices and the decision by the Company to allocate proportionately more capital to oil locations in the future.  In addition, there was a reduction in natural gas reserves in certain of the Company’s locations due to updated production history information made publicly available by a third party operator in 2011 where the production in wells proximate to these locations showed that the wells were declining faster and therefore had smaller reserves than previously estimated.

The following table summarizes our estimated quantities proved reserves for the Company, excluding the non-controlling interests of the consolidated partnerships, for December 31, 2011.

Estimated Proved Reserves For The Company’s Interests Only

	December 31,
	2011
Proved developed reserves:
Natural gas (MMcf)	39,912
Oil and liquids (MBbl)	411
Total proved developed reserves (MMcfe)	42,380
Proved undeveloped reserves:
Natural gas (MMcf)	18,849
Oil and liquids (MBbl)	321
Total proved undeveloped reserves (MMcfe)	20,772
Total proved reserves (MMcfe)	63,152
Percent developed	67.1		%
PV-10 (thousands)	$	44,458
Average natural gas price used (per Mcf)	$	4.37
Average oil and liquids price used (per Bbl)	$	89.07

For the years ended December 31, 2011 and 2010, the Company drilled or participated in 4 and 12 wells, respectively, that were included in the Company’s reserve estimates as proved undeveloped locations the preceding year. For the year ended December 31, 2011, the Company spent approximately $2.3 million on these wells.

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Preparation of Reserves Estimates

Our proved oil and natural gas reserves estimates as of December 31, 2011 and 2010 were based on the average fiscal-year prices for oil and natural gas (calculated as the unweighted arithmetic average of the first-day-of-the month price for each month within the 12-month period ended December 31, 2011 and 2010, respectively). Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Proved undeveloped reserves on undrilled acreage are limited to those locations on development spacing areas that are offsetting economic producers that are reasonably certain of economic production when drilled. Proved undeveloped reserves for other undrilled development spacing areas are claimed only where it can be demonstrated with reasonable certainty that there is continuity of economic production from the existing productive formation. Proved undeveloped reserves are included when they are scheduled to be drilled within five years.

The new SEC rules broadened the types of technologies that a company may use to establish reserve estimates and also broadened the definition of natural gas producing activities to include the extraction of non-traditional resources, including natural gas extracted from shales as well as bitumen extracted from oil sands. See Note 2 to the consolidated financial statements for additional information regarding our estimated proved reserves.

Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of natural gas and oil that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and its interpretation. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing, and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices or development and production expenses, may require revision of such estimates. Accordingly, quantities of natural gas and oil ultimately recovered will vary from reserve estimates. See “Risk Factors,” for a description of some of the risks and uncertainties associated with our business and reserves.

The reserve estimates are based on production performance, data acquired remotely or in wells, and are guided by petrophysical, geologic, geophysical, and reservoir engineering models. Estimates of our proved reserves were based on deterministic methods.  In the case of mature developed reserves, reserve estimates are determined by decline curve analysis and in the case of immature developed and undeveloped reserves, by analogy, using proximate or otherwise appropriate examples. The technologies and economic data used in estimating our proved reserves include empirical evidence through drilling results and well performance, well logs and test data, geologic maps and available downhole and production data.  Further, the internal review process of our wells and related reserve estimates includes but is not limited to the following:

·A comparison is made and documented of actual and historical data from our production system to the data in the reserve database. This ensures the accuracy of the production data, which supplies the basis for forecasting.

·A comparison is made and documented of land and lease records to interest data in the reserve database. This ensures that the costs and revenues will be properly determined in the reserves estimation.

·A comparison is made of the historical costs (capital and expenses) to the capital and lease operating costs in the reserve database. Documentation lists reasons for deviation from direct use of historical data. This ensures that all costs are properly included in the reserve database.

·A comparison is made of input data to data in the reserve database of all property acquisitions, disposals, retirements or transfers to verify that all are accounted for accurately.

·Pricing for the first flow day of every month is collected from Platts Gas Daily.  At the reporting date, 12-month average prices are determined. A similar collection process occurs with pricing deductions and a 12-month average is calculated at year end.

For the year ended December 31, 2011, once the reserve database had been updated with current information and all relevant technical support material had been assembled, Carbon’s independent engineering firm, Cawley, Gillespie & Associates, Inc. (“CG&A”) met with Carbon’s technical personnel to review field performance and future development plans.  Following these reviews, the reserve database and supporting data was furnished to CG&A so that they could prepare their independent reserve estimates and final report.  Access to the database housing reserve information is restricted to select individuals from our engineering department.  CG&A’s independent reserve estimates and final report is for the Company’s interest in the respective oil and gas properties which represents 100% of the total proved hydrocarbon reserves owned by the Company, or 94% of the consolidated proved hydrocarbon reserves presented in the Company’s consolidated financial statements as CG&A’s report does not include the hydrocarbon reserves owned by the non-controlling interests of the consolidated partnerships.  The Company calculated the estimated reserves and related PV-10 of the non-controlling interests of the consolidated partnerships’ oil and gas properties by multiplying CG&A’s independent reserve estimates for such properties by the respective non-controlling interests’ interest in specific properties.

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CG&A is a Texas Registered Engineering Firm.  Our primary contact at CG&A is J. Zane Meekins, Executive Vice President.  Mr. Meekins is a State of Texas Licensed Professional Engineer.  See Exhibit 99.1 of the Annual Report on Form 10-K for the Report of CG&A.

Our Manager of Engineering, Richard Finucane, is responsible for overseeing the preparation of the reserve estimates with significant consultations from our internal technical staff.  Mr. Finucane oversees engineering, production, drilling and completions activities for the Company’s operations including property evaluation, acquisitions and divestitures.  Mr. Finucane has worked as an oil and natural gas engineer since 1978 and holds a B.S. in Civil Engineering from the University of Tennessee (highest honors) and is admitted as an expert in oil and natural gas matters in civil and regulatory proceedings in Virginia, West Virginia and Kentucky.

For the year ended December 31, 2010, the reserve estimates were prepared by Nytis LLC’s internal technical staff under the supervision of Mr. Finucane.

Drilling Activities

The following table summarizes the number of wells drilled for the years ended December 31, 2011, 2010 and 2009.  Gross wells reflect the sum of all wells in which we own an interest.  Net wells reflect the sum of our working interests in gross wells.  As of December 31, 2011, we had two wells in progress.

	Year Ended December 31,
	2011		2010		2009
	Gross	Net	Gross	Net	Gross	Net
Development wells:
Productive	8.0	6.8	12.0	4.7	11.0	5.2
Dry	—	—	—	—	1.0	0.5
Total development wells	8.0	6.8	12.0	4.7	12.0	5.7
Exploratory wells:
Productive	—	—	—	—	—	—
Dry	—	—	—	—
Total exploratory wells	—	—	—	—	—	—

A non-productive well is a well found to be incapable of producing either natural gas or oil in sufficient quantities to justify completion as a natural gas or oil well; also known as a dry well or dry hole.

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Natural Gas and Oil Wells and Acreage

Productive Wells

Productive wells consist of producing wells and wells capable of production, including shut-in wells. A well bore with multiple completions is counted as only one well. The following table summarizes our productive wells as of December 31, 2011.

	December 31, 2011
	Gross	Net
Gas	798	499
Oil	36	35
Total	834	534

Acreage

The following table summarizes developed and undeveloped acreage in which we owned a working interest or held an exploration license as of December 31, 2011. A majority of our developed acreage is subject to mortgage liens securing our bank credit facility. Acreage related to royalty, overriding royalty, and other similar interests is excluded from this summary, as well as acreage related to any options held by us to acquire additional leasehold interests.

December 31, 2011
	Developed		Undeveloped		Total
	Acres		Acres		Acres
	Gross	Net	Gross	Net	Gross	Net
Indiana	160	56	46,636	44,970	46,796	45,026
Illinois	3,130	1,565	54,797	29,690	57,927	31,255
Kentucky	27,044	23,998	58,671	51,552	85,715	75,550
Ohio	338	338	6,776	6,776	7,114	7,114
Tennessee	100	25	93,925	93,925	94,025	93,950
West Virginia	9,057	7,554	9,714	7,704	18,771	15,258
Total	39,829	33,536	270,519	234,617	310,348	268,153

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Undeveloped Acreage Expirations

The following table sets forth the number of gross and net undeveloped acres by state as of December 31, 2011, the leases which are scheduled to expire from the date of the table through 2014 unless production is established within the spacing unit covering the acreage prior to the expiration date or the Company extends the terms of a lease by paying delay rentals to the lessor.

December 31, 2011
	2012		2013		2014
	Gross	Net	Gross	Net	Gross	Net
Indiana	1,760	880	406	203	—	—
Illinois	1,970	985	250	125	—	—
Kentucky	4,648	4,382	105	105	—	—
Ohio	51	51	22	22	—	—
Tennessee	—	—	—	—	—	—
West Virginia	—	—	—	—	—	—
Total	8,429	6,298	783	455	—	—

Production, Average Sales Prices and Production Costs

The following table reflects production, average sales price, and production cost information for the years ended December 31, 2011 and 2010.

	Year Ended December 31,
	2011		2010
Production data:
Natural gas (MMcf)	1,797		1,000
Oil and condensate (Bbl)	14,077		1,827
Combined (MMcfe)	1,882		1,011
Gas and oil production revenue (in thousands)	$	9,018	$	4,880
Commodity hedge gain/(loss) (in thousands)	$	459	$	692
Prices:
Average sales price before effects of hedging;
Natural gas (per Mcf)	$	4.37	$	4.77
Oil and condensate (per Bbl)	$	82.36	$	58.65
Average sale price after effects of hedging:
Natural gas (per Mcf)	$	4.63	$	5.47
Oil and condensate (per Bbl)	$	82.38	$	58.65
Average costs per Mcfe:
Lease operating costs	$	1.03	$	1.04
Transportation costs	$	0.66	$	0.44
Production and property taxes	$	0.36	$	0.43

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Marketing and Delivery Commitments

Our natural gas production is generally sold on a month-to-month basis in the spot market, priced in reference to published indices. We believe that the loss of one or more of our natural gas purchasers would not have a material adverse effect on our ability to sell our production, because any individual purchaser could be readily replaced by another purchaser, absent a broad market disruption. We had no material delivery commitments as of December 31, 2011.

As part of our purchase of assets in June 2011 from The Interstate Gas Company, Nytis LLC assumed certain long-term firm transportation contracts.  Capacity levels and related demand charges for the remaining term of the contracts at December 31, 2011 are (i) for 2012 through 2013; approximately 7,700 dekatherms per day capacity with demand charges ranging between $0.22 and $1.40 per dekatherm, (ii) for 2014 through May 2015; 3,450 dekatherms per day with demand charges ranging between $0.22 and $0.65 and (iii) for June 2015 through 2017; 2,300 dekatherms per day with demand charges of $0.65 per dekatherm.  A liability of approximately $8.2 million related to firm transportation contracts assumed in the ING Asset acquisition was recorded of which $6.8 million is reflected on the Company’s consolidated balance sheets as of December 31, 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 these other contracts at December 31, 2011 are (i) for 2012 through March 2013; 1,300 dekatherms per day with demand charges ranging from $0.22 to $0.80 per dekatherm and (ii) 1,000 dekatherms per day with demand charges of $0.22 from April 2013 through April 2036.

Competition

We encounter competition in all aspects of our business, including acquisition of properties and oil and natural gas leases, marketing oil and natural gas, obtaining services and labor, and securing drilling rigs and other equipment and materials necessary for drilling and completing wells. Our ability to increase reserves in the future will depend on our ability to generate successful prospects on our existing properties, execute on major development drilling programs, and acquire additional leases and prospects for future development and exploration. A large number of the companies that we compete with have substantially larger staffs and greater financial and operational resources than we have. Because of the nature of our natural gas assets and management’s experience in exploiting our reserves and acquiring properties, management believes that we effectively compete in our markets. See— Risk Factor “Competition in the natural gas and oil industry is intense, making it more difficult for us to acquire properties, market natural gas and oil and secure trained personnel.”

Regulation

Our operations are subject to various U.S. federal, state, and local laws and regulations. These laws and regulations may be changed in response to economic or political conditions. Matters subject to current governmental regulation and/or pending legislative or regulatory changes include the discharge or other release into the environment of wastes and other substances in connection with drilling and production activities (including fracture stimulation operations), bonds or other financial responsibility requirements to cover drilling risks and well plugging and abandonment, reclamation or restoration costs, reports concerning our operations, the spacing of wells, unitization and pooling of properties, taxation, and the use of derivative hedging instruments. Failure to comply with the laws and regulations in effect from time to time may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that could delay, limit, or prohibit certain of our operations. In the past, regulatory agencies have imposed price controls and limitations on production. In order to conserve supplies of oil and gas, oil and gas conservation commissions and other agencies may restrict the rates of flow of wells below actual production capacity, generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.  Further, a significant spill from one of our facilities could have a material adverse effect on our results of operations, competitive position, or financial condition. The laws in the U.S., including state laws, regulate, among other things, the production, handling, storage, transportation, and disposal of natural gas and oil, by-products from each, and other substances and materials produced or used in connection with our operations. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.

In August 2005, Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, EPAct 2005 amends the Natural Gas Act (“NGA”) to make it unlawful for “any entity,” including otherwise non-jurisdictional producers such as Carbon, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the Federal Energy Regulatory Commission (“FERC”), in contravention of rules prescribed by the FERC. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects

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a significant expansion of the FERC’s enforcement authority. We do not anticipate we will be affected any differently than other producers of natural gas in respect of EPAct2005.

In December 2007, the FERC issued rules requiring that any market participant, including a producer such as Carbon, that engages in physical sales for resale or purchases for resale of natural gas that equal or exceed 2.2 million MMBtus during a calendar year must annually report such sales or purchases to the FERC, beginning on May 1, 2009. These rules are intended to increase the transparency of the wholesale natural gas markets and to assist the FERC in monitoring such markets and in detecting market manipulation. On September 18, 2008 the FERC issued its order on rehearing, which largely approved the existing rules, except the FERC exempted from the reporting requirement certain types of purchases and sales, including purchases and sales of unprocessed natural gas and bundled sales of natural gas made pursuant to state regulated retail tariffs. Also, the FERC clarified that other end use purchases and sales are not exempt from the reporting requirements. The monitoring and reporting required by the new rules will likely increase our administrative costs. Carbon does not anticipate it will be affected any differently than other producers of natural gas.

Additional proposals and proceedings that might affect the natural gas industry are regularly considered by Congress, the states, the FERC, and the courts. For instance, legislation has been introduced in the U.S. Congress to amend the federal Safe Drinking Water Act to subject hydraulic fracturing operations—an important process used in the completion of our natural gas wells—to regulation under the Safe Drinking Water Act. If adopted, this legislation could establish an additional level of regulation, and impose additional costs, on our operations. We cannot predict when or whether any such proposal, or any additional new legislative or regulatory proposal, may become effective. No material portion of our business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the federal government.

Environmental

As an operator of natural gas and oil properties in the U.S., we are subject to stringent national, state, provincial, and local laws and regulations relating to environmental protection as well as controlling the manner in which various substances, including wastes generated in connection with exploration, production, and transportation operations, are released into the environment. Compliance with these laws and regulations can affect the location or size of wells and facilities, prohibit or limit the extent to which exploration and development may be allowed, and require proper closure of wells and restoration of properties when production ceases. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, or criminal penalties, imposition of remedial obligations, incurrence of capital or increased operating costs to comply with governmental standards, and even injunctions that limit or prohibit exploration and production activities or that constrain the disposal of substances generated by oil field operations.

We currently operate or lease, and have in the past operated or leased, a number of properties that for many years have been used for the exploration and production of natural gas and oil. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties operated or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to laws and regulations imposing joint and several liability and strict liability without regard to fault or the legality of the original conduct that could require us to remove previously disposed wastes or remediate property contamination, or to perform well or pit closure or other actions of a remedial nature to prevent future contamination.

Vast quantities of natural gas and oil deposits exist in deep shale and other formations.  It is customary in our industry to recover natural gas and oil from these deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling.  Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations underground where water, sand and other additives are pumped under high pressure into a shale formation.

The Company’s acreage lies within areas where hydraulic fracturing is used on over 90% of all wells.  The reservoir rock in these areas, in general, has insufficient permeability to flow enough oil or natural gas to be economically viable without stimulation.  The controlling regulatory agencies for well construction have standards that are designed specifically in anticipation of hydraulic fracturing.  Essentially all of our reserves are subject to or have been subjected to hydraulic fracturing.  The stimulation process cost varies according to well location and reservoir.  It ranges from 10% of the well cost to 25%.  To date, no incidents, citations or suits have resulted from our hydraulic fracturing operations.  However, the regulatory environment is changing with respect to the use of hydraulic fracturing.

We contract with well respected service companies to conduct our hydraulic fracturing.  The drivers for these service companies are trained to handle hazardous materials and possess emergency protocols and equipment to deal with spills.  Service companies carry Material Safety Data Sheets for all chemicals.

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In the fracturing process, the focus is on prevention since the accidental release could result in not only possible environmental impact but also injuries.  All wells have complex manifolds with escape lines to containment areas that are staked into the ground.  Chokes are present for flow control and specially designed high pressure valves are on the wellhead.  Valves and piping are designed for far higher pressures than are typically encountered.  Service company steel is rated at 3 to 4 times the planned pumping pressure.  Piping is tested prior to any procedure in excess of the job specs.  The piping is tested prior to coming to location and records are kept on those tests.

All fracturing is designed with the minimal water requirements necessary since there is a cost of accumulating the water and storing the water along with the disposal costs of water recovered from the fracturing.  Water is drawn from nearby streams that are tributaries to the Ohio River and flowing 365 days per year.  The recovered water is injected into EPA or state approved water injection wells.

Despite all of these safety procedures, there are many risks involved in hydraulic fracturing that could result in liability to the Company.

In 2009, the U.S. House of Representatives passed a bill to control and reduce the emission of domestic greenhouse gases through the grant of emission allowances which would gradually be decreased over time.  Although similar bills were considered in the U.S. Senate, such legislation lacked bipartisan support in the current Congress. Despite the lack of federal legislation, nearly half of the states, either individually or through multi-state initiatives, have already begun implementing legal measures to reduce greenhouse gas emissions. Also, the U.S. Supreme Court held in Massachusetts et al. v. EPA (2007) that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act, which could result in future regulation of greenhouse gas emissions from stationary and non-stationary sources, even if Congress does not adopt new legislation specifically addressing such emissions. In December 2009, the U.S. Environmental Protection Agency (“EPA”) published its findings that emissions of greenhouse gases present an endangerment to public health and the environment because such emissions, according to the EPA, are contributing to warming of the earth’s atmosphere and other climate changes. These findings allow the EPA to implement regulations that would restrict greenhouse gas emissions under existing provisions of the Clean Air Act. Accordingly, the EPA has adopted regulations that require a reduction of greenhouse gas emissions from motor vehicles and has proposed additional regulations to further restrict such emissions.  The EPA has also finalized regulations that require certain U.S. facilities, including certain petroleum and natural gas facilities, to report their greenhouse gas emissions beginning on January 1, 2011. The adoption and implementation of these regulations impacts our business, and any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have an adverse effect on demand for the natural gas that we produce.

We believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards. While we believe that we are in substantial compliance with applicable environmental laws and regulations in effect at the present time and that continued compliance with existing requirements will not have a material adverse impact on us, we cannot give any assurance that we will not be adversely affected in the future. We have established internal guidelines to be followed in order to comply with environmental laws and regulations in the U.S. Although we maintain pollution insurance against the costs of cleanup operations, public liability, and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will continue to be available in the future.

Employees

As of December 31, 2011, our workforce (including those employed by our subsidiary Nytis LLC) consisted of approximately 26 employees all of which are full-time employees.  None of the members of our workforce are represented by a union or covered by a collective bargaining agreement.  We believe we have a good relationship with the members of our workforce.

Geographical Data

Carbon operates in one geographical area, the United States.  See Note 1 to the Consolidated Financial Statements.

Offices

Our principal executive offices are located at 1700 Broadway, Suite 1170, Denver, Colorado 80290.  We maintain an office in Lexington, Kentucky in which we conduct our oil and gas operations.

Title to Properties

Title to our oil and gas properties is subject to royalty, overriding royalty, carried, net profits, working, and similar interests customary in the oil and gas industry. Under the terms of our bank credit facilities, we have granted the lenders a lien on a substantial majority of our properties. In addition, our properties may also be subject to liens incident to operating agreements, as well as other customary encumbrances, easements, and restrictions, and for current taxes not yet due. Our general practice is to

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conduct title examinations on material property acquisitions. Prior to the commencement of drilling operations, a title examination and, if necessary, curative work is performed. The methods of title examination that we have adopted are reasonable in the opinion of management and are designed to ensure that production from our properties, if obtained, will be salable by us.

Glossary of Oil and Gas Terms

Many of the following terms are used throughout this Annual Report on Form 10-K.  The definitions of proved developed reserves, proved reserves, and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a) of Regulation S-X adopted by the Securities and Exchange Commission (the “SEC”). The entire definitions of those terms can be viewed on the SEC’s website at http://www.sec.gov.

Bbl	means one stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or liquid hydrocarbons.
Bcf	means one billion cubic feet of natural gas.
Bcfe	means one billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate, or natural gas liquids.
Bbtu	means one billion British Thermal Units.
Btu	means a British Thermal Unit, or the amount of heat necessary to raise the temperature of one pound of water one degree Fahrenheit.
CBM	means coalbed methane.
Condensate	means liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Dekatherm	means one million British Thermal Units.
Developed acreage	means the number of acres which are allocated or held by producing wells or wells capable of production.
Development well	means a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole; dry well	means a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Equivalent volumes	means equivalent volumes are computed with natural gas liquid quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf.
Exploitation	means ordinarily considered to be a form of development within a known reservoir.
Exploratory well	means a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well or a service well.
Farmout	is an assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location or the undertaking of other work obligations.
Field	means an area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Full cost pool	means the full cost pool consisting of all costs associated with property acquisition, exploration, and development activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration, and development activities are included. Any costs related to production, general and administrative expense, or similar activities are not included.
Gross acres or gross wells	means the total acres or wells, as the case may be, in which a working interest is owned.

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Henry Hub	means the natural gas pipeline located in Erath, Louisiana that serves as the official delivery location for futures contracts on the NYMEX.
Lease operating expenses	means the expenses of lifting natural gas or oil from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.
Liquids	describes oil, condensate, and natural gas liquids.
	��
MBbls	means one thousand barrels of crude oil or other liquid hydrocarbons.
Mcf	means one thousand cubic feet of natural gas.
Mcfe	means one thousand cubic feet equivalent determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate, or natural gas liquids.
MMBtu	means one million British Thermal Units, a common energy measurement.
MMcf	means one million cubic feet of natural gas.
MMcfe	means one million cubic feet equivalent determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate, or natural gas liquids.
NGL	means natural gas liquids.
Net acres or net wells	is the sum of the fractional working interest owned in gross acres or gross wells expressed in whole numbers and fractions of whole numbers.
NYMEX	means New York Mercantile Exchange.
Productive wells	means producing wells and wells that are capable of production, and wells that are shut-in.
Proved Developed Reserves	means estimated proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved Reserves	means quantities of natural gas and oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices that are the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Proved Undeveloped Reserves	means estimated proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recovery to occur.
PV-10	means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.

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Reservoir	means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty	means an interest in a natural gas or oil lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
Standardized measure or present value of estimated future net revenues	means an estimate of the present value of the estimated future net revenues from proved natural gas or oil reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs, operating expenses and income taxes computed by applying year end statutory tax rates, with consideration of future tax rates already legislated. The estimated future net revenues are discounted at an annual rate of 10%, in accordance with the SEC’s practice, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using natural gas and oil prices and operating costs at the estimation date and held constant for the life of the reserves.
Tcfe	means one trillion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate, or natural gas liquids.
Undeveloped acreage	means acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
Working interest	means an operating interest which gives the owner the right to drill, produce, and conduct operating activities on the property, and to receive a share of production.

Available Information

You may read, without charge, and copy, at prescribed rates, all or any portion of the registration statement or any reports, statements or other information in the files at the public reference room at the SEC’s principal office at 100 F Street NE, Washington, D.C., 20549. You may request copies of these documents, for a copying fee, by writing to the SEC. You may call the SEC at 1-800-SEC-0330 for further information on the operation of its public reference room. Our filings, including this Annual Report on Form 10-K, will also be available to you on the Internet website maintained by the SEC at http://www.sec.gov.

We are subject to the information and reporting requirements of the Securities Exchange Act and will file annual, quarterly and current reports, proxy statements and other information with the SEC. You can request copies of these documents, for a copying fee, by writing to the SEC. These reports, proxy statements and other information will also be available on the Internet website of the SEC referred to above. We intend to furnish our stockholders with annual reports containing financial statements audited by our independent auditors.

Forward-Looking Statements

The information in this Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “1933 Act”) and Section 21E of the Exchange Act of 1934 (the “1934 Act”). Forward-looking statements are statements other than statements of historical or present facts, that address activities, events, outcomes, and other matters that Carbon 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 and include statements with respect to, among other things:

·estimates of our natural gas and oil reserves;

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

·our future financial condition and results of operations;

·our future revenues, cash flows, and expenses;

·our access to capital and our anticipated liquidity;

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

·our outlook on natural gas and oil prices;

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

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

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

·the impact of federal, state, and local political, regulatory, and environmental developments in the United States.

We believe the expectations and forecasts reflected in our forward-looking statements are reasonable, but we can give no assurance that they will prove to be correct. We caution you that these forward-looking statements can be affected by inaccurate assumptions and are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, and sale of natural gas and oil. See “Competition” and “Regulation” above, as well as Part I, Item 1A—“Risk Factors,” and Part II, Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources” for a description of various, but by no means all, factors that could materially affect our ability to achieve the anticipated results described in the 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 Annual Report on Form 10-K and attributable to Carbon are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we may make or persons acting on our behalf may issue.

Item 1A.    Risk Factors.

We are subject to certain risks and hazards due to the nature of the business activities we conduct, including the risks discussed below.  Any of these risks could materially and adversely affect our business, financial condition, cash flows, and results of operations, and are not the only risks we face. We may experience additional risks and uncertainties not currently known to us; or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows, and results of operations.

Natural gas and oil prices are volatile. A substantial or extended decline in natural gas and oil prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

Our financial condition, operating results, and future rate of growth depend upon the prices that we receive for our natural gas and oil. Prices also affect our cash flow available for capital expenditures and our ability to access funds under our bank credit facility

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and through the capital markets. The amount available for borrowing under our bank credit facility is subject to a borrowing base, which is determined by our lender taking into account our estimated proved developed reserves and is subject to periodic redeterminations based on pricing models determined by the lender at such time. Declines in natural gas and oil prices have in the past adversely impacted the value of our estimated proved developed reserves and, in turn, the market values used by our lenders to determine our borrowing base. Future commodity price declines may have similar adverse effects on our reserves and borrowing base. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Bank Credit Facilities,” for more details. Further, because we have elected to use the full cost accounting method, each quarter we must perform a “ceiling test” that is impacted by declining prices. Significant price declines could cause us to take one or more ceiling test write-downs, which would be reflected as non-cash charges against current earnings. See Risk Factor below entitled “Lower natural gas and oil prices and other factors have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values.”

The markets for natural gas and oil have been volatile historically and are likely to remain volatile in the future. Oil spot prices reached historical highs in July 2008 and natural gas spot prices reached near historical highs in July 2008. Prices have declined significantly since that time and may continue to fluctuate widely in the future.  The prices we receive for our natural gas and oil depend upon factors beyond our control, including among others:

·worldwide and regional economic conditions impacting the global supply and demand for natural gas and oil;

·the price and quantity of imports of foreign natural gas, including liquefied natural gas, and oil;

·political conditions in or affecting other natural gas and oil-producing countries, including the current conflicts in the Middle East and conditions in Latin America, Russia and the independent states of the former Soviet Union;

·the level of global natural gas and oil exploration and production;

·the level of global natural gas and oil inventories;

·prevailing prices on local natural gas and oil price indexes in the areas in which we operate;

·localized and global supply and demand fundamentals and transportation availability;

·weather conditions;

·technological advances affecting energy consumption;

·the price and availability of alternative energy; and

·domestic, local and foreign governmental regulation and taxes.

These factors make it very difficult to predict future commodity price movements with any certainty. We sell the majority of our natural gas and oil production at current prices rather than through fixed-price contracts. However, we do enter into derivative instruments to reduce our exposure to fluctuations in natural gas and oil prices. See Risk Factor below entitled “Future use of hedging arrangements could result in financial losses or reduce income.”  At December 31, 2011, 93% of our estimated proved reserves were natural gas, and, as a result, our financial results will be more sensitive to fluctuations in natural gas prices.

Furthermore, the worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets has led to a worldwide economic recession. The slowdown in economic activity caused by such recession has reduced worldwide demand for energy and resulted in lower natural gas and oil prices. Natural gas spot prices have recently been particularly volatile and declined from record high levels in early July 2008 of over $13.00 per MMBtu to below $3.00 per MMBtu in September 2009 and for portions of 2012.  More recently, oil prices have been generally increasing due in part to the unrest and uncertainty in the Middle East; however, this has not had a similar effect on the price of natural gas.

We have indebtedness and may incur more debt in the future. Our leverage may materially affect our operations and financial condition.

We (through Nytis LLC) have a bank credit facility with the Bank of Oklahoma, the outstanding balance of which was approximately $8.8 million at December 31, 2011, and we may incur more debt in the future. This indebtedness may have several important effects on our business and operations; among other things, it may:

·require us to use a significant portion of our cash flow to pay principal and interest on the debt, which will reduce the amount available to fund working capital, capital expenditures, and other general corporate purposes;

·limit our access to the capital markets;

·increase our borrowing costs, and impact the terms, conditions, and restrictions contained in our debt agreements, including the addition of more restrictive covenants;

·limit our flexibility in planning for and reacting to changes in our business as covenants and restrictions contained in our existing and possible future debt arrangements may require that we meet certain financial tests and place restrictions on the incurrence of additional indebtedness;

·place us at a disadvantage compared to similar companies in our industry that have less debt; and

·make us more vulnerable to economic downturns and adverse developments in our business.

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Our bank credit facility contains various restrictive covenants. A failure on our part to comply with the financial and other restrictive covenants contained in our bank credit facility could result in a default under these agreements. Any default under our bank credit facility could adversely affect our business and our financial condition and results of operations, and would impact our ability to obtain financing in the future. In addition, the borrowing base included in our bank credit facility is subject to periodic redetermination by our lender. A lowering of our borrowing base could require us to repay indebtedness in excess of the redetermined (lower) borrowing base. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Bank Credit Facility.”

A higher level of debt will increase the risk that we may default on our financial obligations. Our ability to meet our debt obligations and other expenses will depend on our future performance. Our future performance will be primarily affected by natural gas prices (and to a lesser extent, oil prices), financial, business, domestic and global economic conditions, governmental regulations and environmental regulations, and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance the debt, sell assets, or sell shares of our stock on terms that we do not find attractive, if it can be done at all.

A portion of our borrowings from time to time may be at variable interest rates, making us vulnerable to increases in interest rates.

Our estimates of proved reserves at December 31, 2011 and 2010 have been prepared under SEC’s rules and could limit our ability to book additional proved undeveloped reserves in the future.

Estimates of our proved reserves as of December 31, 2011 and 2010 have been prepared and presented under the SEC’s rules relating to the reporting of natural gas and oil exploration activities.  These rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking.  This rule has limited and may continue to limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down any proved undeveloped reserves that are not developed within the required five-year timeframe.

Neither the estimated quantities of proved reserves and their discounted present value of future net cash flows attributable to those reserves included in this Annual Report on Form 10-K are intended to represent their fair, or current, market value.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating natural gas reserves is complex.  It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices.  Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.  See “Business—Reserves—Estimated Proved Reserves” for information about our estimated natural gas reserves and the PV-10 and standardized measure of discounted future net cash flows.

In order to prepare our estimates, we must project production rates, the extent of our eventual working and net revenue interests and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data.  The extent, quality and reliability of this data can vary.  The process also requires economic assumptions about matters such as natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas reserves will vary from our estimates.  Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust estimates of our proved reserves to reflect production history, results of exploration and development, prevailing commodity prices and other factors, many of which are beyond our control.

It should not be assumed that the present value of future net revenues from our proved reserves is the current market value of our estimated reserves.  We base the estimated discounted future net cash flows from our proved reserves using the revised SEC regulations.  Actual future prices and costs may differ materially from those used in the present value estimate.

35% of our total proved reserves as of December 31, 2011 consist of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced.

As of December 31, 2011, 33% of our total proved reserves were undeveloped and 2% were developed non-producing.  Although we plan to develop and produce all the proved reserves, ultimately some may not be developed or produced.  In addition, not all of the undeveloped or developed non-producing reserves may begin producing at the expected times or within budget.

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Lower natural gas and oil prices and other factors have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values.

We use the full cost method of accounting to report our natural gas and oil operations. Under this method, we capitalize the cost to acquire, explore for, and develop natural gas and oil properties. Under full cost accounting rules, the net capitalized costs of proved natural gas and oil properties may not exceed a “ceiling limit,” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%. If net capitalized costs of proved natural gas and oil properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling test write-down.” Under the accounting rules, we are required to perform a ceiling test each quarter. A ceiling test write-down would not impact cash flow from operating activities, but it would reduce our stockholders’ equity.  For the year ended December 31, 2011, we recognized a ceiling test impairment for the first, second, third and fourth quarters of $7.3 million, $1.1 million, $3.8 million and $3.6 million, respectively, for a total impairment of $15.8 million for 2011.   Further declines in oil and natural gas prices could result in additional impairments of our oil and gas properties in future periods,  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies, Estimates, Judgments, and Assumptions—Full Cost Method of Accounting,” for further detail.

Investments in unproved properties, including capitalized interest costs, are also assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data relating to the properties. The amount of impairment assessed, if any, is added to the costs to be amortized in the appropriate full cost pool. If an impairment of unproved properties results in a reclassification to proved natural gas reserves, the amount by which the ceiling limit exceeds the capitalized costs of proved natural gas reserves would be reduced.

We also assess the carrying amount of goodwill in the fourth quarter of each year and at other periods when events occur that may indicate an impairment exists. These events include, for example, a significant decline in natural gas prices.

The risk that we will be required to write-down the carrying value of our natural gas and oil properties or our unproved properties increases when natural gas and oil prices are low. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase. For example, we recorded a non-cash ceiling test write-down of approximately $15.8 million in 2011. These write-downs are reflected as a charge to net earnings. Additional write-downs of our full cost pool may be required if natural gas prices decline further, unproved property values decrease, estimated proved reserve volumes are revised downward or costs incurred in exploration, development, or acquisition activities in our full cost pool exceed the discounted future net cash flows from the additional reserves, if any, attributable to our cost pool.

Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our reserves.

The natural gas and oil industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the development, exploitation, production and acquisition of natural gas and oil reserves. Cash used in investing activities related to acquisition, development and exploration expenditures was approximately $31.1 million and $4.9 million in 2011 and 2010, respectively.

The Company anticipates its budget for exploration and completion work on existing acreage will range between $6 million and $8 million for all of 2012.  As we recognized an operating loss of approximately $17.3 million and $648,000 for the years ended December 31, 2011 and 2010, respectively, our planned exploration and development drilling and completion activities may be limited or delayed if cash flow from producing activities or funds available from our credit facility are not sufficient to fund the anticipated level of capital expenditures.

We intend to finance future capital expenditures through cash flow from operations, and to the extent that it is prudent, from borrowings under our bank credit facility.  However, our financing needs may exceed those resources, and thus require a substantial increase in capitalization through the issuance of debt or equity securities or sale or joint venturing of selected assets. The issuance of additional indebtedness may require that a portion of operating cash flow be used to service the debt, thereby reducing the amount of cash flow available for other purposes. The actual amount and timing of future capital expenditures may differ materially from estimates as a result of, among other things, availability of personnel, commodity prices, actual drilling results, the availability of drilling rigs and other services, materials and equipment, and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures. Conversely, a significant improvement in product prices could result in an increase in our capital expenditures.

Our cash flow from operations and access to capital is subject to a number of variables, primarily proved reserves, production volumes and prices, and the ability of our bank to lend.

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Adverse events or trends related to these factors could reduce our ability to achieve or obtain the cash flow from operations, debt and/or equity capital necessary to sustain operations at current levels. Our Company, like the majority of smaller and mid-size independent oil and gas exploration companies, must continue acquiring and exploiting properties to replace depleting reserves, and the budget for these activities often will not be fully funded by operating cash flow.  Accordingly, the inability to access outside capital could result in a curtailment of operations relating to the development of our properties, which in turn could lead to a decline in reserves and adversely affect the business, and our financial condition and results of operations.

Distressed economic conditions also may adversely affect the collectability of trade receivables. For example, our accounts receivable are primarily from purchasers of our natural gas production and other exploration and production companies that own working interests in the properties that we operate. This industry concentration could adversely impact our overall credit risk, because customers and working interest owners may be similarly affected by the same adverse changes.  In addition, the possibility of a renewed credit crisis and turmoil in financial markets could cause our commodity derivative instruments to be ineffective because a counterparty might be unable to perform its obligations or even seek bankruptcy protection.

Due to these factors, we cannot be certain that funding, if needed, will be available to the extent required, or on acceptable terms. If we are unable to access funding when needed on acceptable terms, we may not be able to fully implement our business plans, complete new property acquisitions to replace reserves, take advantage of business opportunities, respond to competitive pressures, or refinance debt obligations as they come due, any of which could have a material adverse effect on operations and financial results.

Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations.

We have approximately 1,100 potential horizontal drilling locations. Our management team has specifically identified and scheduled certain drilling locations as an estimation of future multi-year drilling activities on existing acreage. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas and oil prices, the availability and cost of capital, availability of qualified personnel, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering systems and pipeline transportation constraints, regulatory approvals and other factors. Accordingly, we cannot predict when or if the identified drilling locations will be drilled.

We could lose our undeveloped mineral leases if we don’t drill and complete wells in a timely manner.

Leased mineral properties give the holder the right to drill and complete wells in a timely manner.  Leases have a contract term that is negotiated with the mineral owners.  Generally, if a well is drilled and completed (thus “held by production”), the lease term continues so long as there is production from the well.

However, a sizeable portion of our acreage is currently undeveloped, and certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years.  Renewing leases on undrilled acreage may not be feasible due to increased cost or other reasons.  If we are unable to renew leases on undrilled acreage, we would have to write off the initial acquisition cost of such acreage, which could be substantial and our reserve estimates and the financial information related thereto may be found to be inaccurate which could have a material adverse effect on us.

Some of these leases will only allow us to hold a portion of the lease even after one or more wells have been completed.  As is customary in the natural gas and oil industry, Company management continually prioritizes the timing of all of drilling locations against drilling and completion costs, available capital, expected returns on capital (net of debt taken on for drilling and completion work), and lease expirations.

Unless we replace our reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing natural gas and oil reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. As a result, we must locate, acquire and develop new reserves to replace those being depleted by production. We must do this even during periods of low prices when it is difficult to raise capital. Unless we conduct successful ongoing exploration, development and exploitation activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future natural gas and oil reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations will be adversely affected.

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Drilling for and producing natural gas and oil are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.

Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Exploration, exploitation, development and production are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable natural gas or oil production. The Company’s decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes See the Risk Factor “Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, drilling and completion costs always are subject to change before the work is finished.  Further, many factors may curtail, delay or cancel scheduled drilling projects, including:

·delays imposed by or resulting from compliance with regulatory requirements;

·pressure or irregularities in geological formations;

·shortages of or delays in obtaining equipment, materials and qualified personnel;

·equipment failures or accidents;

·adverse weather;

·declines in commodity prices;

·limited availability of financing at acceptable rates;

·title problems; and

·limitations in getting production to market due to transportation issues (see the Risk Factor entitled “Our business depends on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the natural gas we produce.”)

Additionally, drilling, transportation and processing of hydrocarbons bear an inherent risk of loss of containment. Potential consequences include loss of reserves, loss of production, loss of economic value associated with an affected wellbore, contamination of soil, ground water, and surface water, as well as potential fines, penalties, or damages associated with any of the foregoing consequences.

As part of our ongoing operations, we sometimes drill in new or emerging plays. As a result, drilling in these areas is subject to greater risk and uncertainty.

We have an operations group that is responsible for identifying new or emerging plays. These activities are more uncertain as to ultimate profitability than drilling in areas that are developed and have established production, because of little or sometimes no past drilling results by third parties to guide lease acquisition and drilling work. We cannot assure you that our future drilling activities in emerging plays will be successful or, if successful, will achieve the potential resource levels that we currently anticipate based on the drilling activities that have been completed, or that we will achieve the anticipated economic returns based on our current cost models.

Increasing costs could impact operating results.

Areas throughout the United States, including the Appalachian and Illinois Basins, are experiencing steadily rising costs for drilling and completion rigs, pipe, cement, electrical power, and other goods and services.  Over time, a failure of commodity prices to keep pace with the cost creep environment could adversely affect cash flow.

We may suffer losses or incur liability for events for which we or the operator of a property have chosen not to obtain insurance.

Our operations are subject to hazards and risks inherent in drilling, producing and transporting production, such as fires, natural disasters, explosions, pipeline ruptures, spills, and acts of terrorism, all of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other property damage.  We maintain insurance coverage against some, but not all, potential losses, including hydraulic fracturing.  Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons.  The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.  Some concern has been expressed over the potential environmental impact of hydraulic fracturing operations, including the effect on water resources.  We maintain liability insurance to protect us from claims or losses relating to hydraulic fracturing with a policy limit of $1.0 million in general liability, and a $5.0 million umbrella policy.  Our deductible for claims relating to hydraulic fracturing is $1,000.  Pollution and environmental risks generally are not fully insurable.  Existing insurance coverage may not be renewed.  Contractors who perform services may cause

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claims or losses that result in liability to us.  The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our business, financial condition and results of operations.

We may suffer losses or incur environmental liability in hydraulic fracturing operations.

Vast quantities of natural gas and oil deposits exist in deep shale and other formations.  It is customary in our industry to recover natural gas and oil from these deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling.  Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations underground where water, sand and other additives are pumped under high pressure into a shale formation.  We contract with well respected service companies to conduct our hydraulic fracturing.  The drivers for these service companies are Hazmat trained and possess emergency protocols and equipment to deal with spills.  Service companies carry Material Safety Data Sheets for all chemicals.

In the fracturing process, the focus is on prevention since the accidental release could result in not only possible environmental impact but also injuries.  All wells have complex manifolds with escape lines to containment areas that are staked into the ground.  Chokes are present for flow control and specially designed high pressure valves are on the wellheads.  Valves and piping are designed for far higher pressures than are typically encountered.  Service company steel is rated at 3 to 4 times the planned pumping pressure.  Piping is tested prior to any procedure in excess of the job specs.  The piping is tested prior to coming to location and records are kept on those tests. Despite all of these safety procedures, there are many risks involved in hydraulic fracturing that could result in liability to the Company in excess of the Company’s policy limits, resulting in an adverse effect on our operations.

Future use of hedging arrangements could result in financial losses or reduce income.

We may engage in hedging arrangements for a significant part of production to reduce exposure to price fluctuations in commodity prices.  These arrangements would expose the Company to risk of financial loss in some circumstances, including when production is less than expected, the counterparty to the hedging contract defaults on its contract obligations, or there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received. In addition, these hedging arrangements may limit the benefits we would otherwise receive from increased commodity prices.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and to make payments on our indebtedness, which could also limit our ability to borrow funds. Future collateral requirements will depend on arrangements with our counterparties, highly volatile natural gas prices and interest rates.

As of December 31, 2011, the fair value of the contracts with our derivatives counterparty was approximately $308,000. Any default by this counterparty on its obligations to us would have a material adverse effect on the Company’s financial condition and results of operations.

Our business depends on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the natural gas we produce.

The marketability of our natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The amount of natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months.  We may be provided with only minimal, if any, notice as to when these circumstances will arise, or their duration. In addition, future properties may be acquired which are not currently serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport the additional production.  As a result, we may not be able to sell production from these wells until the necessary systems are built.

We may incur losses as a result of title deficiencies.

We typically do not retain attorneys to examine title before acquiring leases or mineral interests.  Prior to drilling a well, however, we (or the company that is the operator) obtain a preliminary title review to initially determine that no obvious title deficiencies are anticipated.  As a result of some such examinations, certain curative work must be done to correct deficiencies in title, and such curative work may be expensive.  In some instances, curative work may not be feasible or possible, and the interest is demonstrated to have been bought in error from someone who is not the owner.  In that event, our interest would be worthless.

In addition, the Company’s reserve estimates assume that we have proper title for the properties we have acquired.  Therefore, in the event we are unable to perform curative work to correct deficiencies and our interest is deemed to be worthless, our reserve

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estimates and the financial information related thereto may be found to be inaccurate, which could have a material adverse effect on us.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Our exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations.

Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production and transportation of, natural gas and oil. Failure to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations.

Changes to existing or new regulations may unfavorably impact the Company, could result in increased operating costs, and could have a material adverse effect on our financial condition and results of operations. For example, Congress is currently considering legislation that, if adopted in its proposed form, would subject companies involved in natural gas and oil exploration and production activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, the elimination of certain U.S. federal tax incentives and deductions available for such activities, and the prohibition or additional regulation of private energy commodity derivative and hedging activities. These and other potential regulations, particularly at the local level, could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our financial condition, results of operations and cash flows.

Operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.

We may incur significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our exploration, development and production activities. These delays, costs and liabilities could arise under a wide range of federal, state and local laws and regulations relating to protection of the environment, health and safety, including regulations and enforcement policies that have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. We are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed project may have on the environment, threatened and endangered species, and cultural and archaeological artifacts. The public may comment on and otherwise engage in the permitting process, including through judicial intervention.  As a result, the permits we need may not be issued, or if issued, may not be issued in a timely manner or may impose requirements that restrict our ability to conduct operations.

In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Strict liability and joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken.

New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our business, financial condition or results of operations could be adversely affected.

The adoption of climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas and oil we produce.

The U.S. Congress has considered legislation to mandate reductions of greenhouse gas emissions and certain states have already implemented, or may be in the process of implementing, similar legislation. Additionally, the U.S. Supreme Court has held in its decisions that carbon dioxide can be regulated as an “air pollutant” under the Clean Air Act, which could result in future regulations even if the U.S. Congress does not adopt new legislation regarding emissions. At this time, it is not possible to predict how legislation or new federal or state government mandates regarding the emission of greenhouse gases could impact our business; however, any such future laws or regulations could require us or our customers to devote potentially material amounts of capital or other resources in order to comply with such regulations. These expenditures could have a material adverse impact on our financial condition, results of operations, or cash flows.

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Even though such legislation has not yet been adopted at the national level, nearly one-half of the states have begun taking actions to control and/or reduce emissions of greenhouse gases. Although most of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as coal-fired electric power plants, it is possible that smaller sources of emissions could become subject to greenhouse gas emission limitations or allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

The Company’s acreage lies within areas where hydraulic fracturing is used on over 90% of all wells.  The reservoir rock in these areas, in general, has insufficient permeability to flow enough oil or natural gas to be economically viable without stimulation.  The controlling regulatory agencies for well construction have standards that are designed specifically in anticipation of hydraulic fracturing.  Essentially all of our reserves are subject to or have been subjected to hydraulic fracturing.  The stimulation process cost varies according to well location and reservoir.  It ranges from 10% of the well cost to 25%.  To date, no incidents, citations or suits have resulted from our hydraulic fracturing operations.  However, the regulatory environment is changing with respect to the use of hydraulic fracturing, and any increase in compliance costs could negatively impact our ability to conduct our business.

In March 2011, legislation was introduced in both the House and Senate to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the natural gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies.  The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. Both bills are still in committee.

Separately, the EPA has commenced the process of studying the possible relationship between hydraulic fracturing and drinking water, the initial results of which the EPA expects in late 2012. To receive input on development of the draft study plan, the EPA held public meetings in four locations across the country in July and September 2010, which attracted hundreds of protestors.  Also in September 2010, the EPA issued voluntary information requests to nine of the leading national and regional hydraulic fracturing service providers.  Although eight of the nine hydraulic fracturing companies agreed to voluntarily compile and submit the information requested by the EPA, one company refused and the EPA issued a subpoena.  Because of heightened public awareness and concern related to hydraulic fracturing, additional federal regulation by the EPA, Congress, or both is likely in the coming years. If adopted, such rules could lead to operational delays or increased operating costs and could result in additional regulatory burdens that would make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

The recently enacted Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) is comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing certain portions of it by mid-July 2011 (which have in part been delayed). The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt similar rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may require us to comply with margin requirements and with certain clearing and trade-execution requirements, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative contracts to spin off some of their derivatives contracts to a separate entity, which may not be as creditworthy as the current counterparty. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower the commodity prices we realize. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.

Any laws or regulations that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our

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trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

Competition in the natural gas and oil industry is intense, making it more difficult for us to acquire properties, market natural gas and oil and secure trained personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing our production and securing trained personnel.  Also, there is substantial competition for investment capital in the industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past few years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition and results of operations.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and field services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. Historically, there have been shortages of qualified personnel, drilling and workover rigs, pipe and other equipment and materials as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

The loss of senior management or technical personnel could adversely affect operations.

We depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Patrick McDonald, our Chairman, President and Chief Executive Officer, Kevin Struzeski, our Chief Financial Officer, Treasurer and Secretary and Mark Pierce, our Senior Vice President for Nytis LLC, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

Our senior management and administrative staff also provide services to Nytis Exploration Company, a corporation separate from the Company and its subsidiaries.  The time that such personnel devote to the other company will impact the time each will have to devote to the Company and could adversely affect operations.

Prior to the closing of the Merger, all of the persons providing services to Nytis USA were employees of Nytis Exploration Company, a company that is separate from the Company and its subsidiaries.  Effective July 1, 2011, these persons now serve as the administrative staff and senior management of the Company.  However, the Company allows these persons, including Mr. McDonald (CEO) and Mr. Struzeski (CFO), to continue to provide services to Nytis Exploration Company.  The Company is paid a flat fee equal to $15,000 per month for all services performed for Nytis Exploration Company, and to the extent the Company incurs out of pocket costs and expenses to third parties in connection with providing such services to Nytis Exploration Company, such costs and expenses are reimbursed by Nytis Exploration Company to the Company.  Historically, Mr. McDonald and Mr. Struzeski have spent approximately 65% to 70% of their professional time on the business of Nytis USA.  However, since the Merger, the ING Asset Acquisition, and the increase in responsibilities that attend the management of a public reporting company, each estimates and intends that they will spend approximately 90% of their time on the business of the Company.  They further believe that this will be in excess of 50 hours per week each.

As a consequence of this arrangement, the time that the Company’s administrative staff and senior management spend on and such persons’ obligations with respect to matters other than Company matters could adversely affect the operations of the Company.

The Company has limited control over activities on properties we do not operate, which could reduce our production and revenues.

A portion of our business is conducted through joint operating agreements under which we own partial interests in oil and gas properties. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The failure of an operator of our wells to adequately perform operations or an operator’s breach of the applicable agreements could reduce our production and revenues. The success

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and timing of our drilling and development activities on properties operated by others, therefore, depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Because we do not have a majority interest in most wells that we do not operate, we may not be in a position to remove the operator in the event of poor performance.

We may be subject to risks in connection with acquisitions of properties.

The successful acquisition of producing properties requires an assessment of several factors, including:

·recoverable reserves;

·future commodity prices and their applicable differentials;

·operating costs; and

·potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even with inspections.  Additionally, when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully, or to minimize any unforeseen operational difficulties could have a material adverse effect on the business, financial condition and results of operations.

We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax deductions currently available with respect to natural gas and oil exploration and development are eliminated as a result of future legislation.

The passage of any legislation as a result of the budget proposal, the Senate bill or any other similar change in U.S. federal income tax law could eliminate certain tax deductions that are currently available with respect to natural gas and oil exploration and development. Any such change could negatively impact our financial condition and results of operations by increasing the costs we incur which would in turn make it uneconomic to drill some prospects if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.

We may incur additional expenses and costs due to environmental damages.

Our sits and equipment are susceptible to damage from environmental pressures such as flooding, tornadoes, hail, snow and other weather related issues.  We may have to expend additional costs and expenses cleaning up areas damaged by weather related instances, such as repair roads, reinforce sites or repair damaged equipment.  There is no assurance that our insurance will pay for all the damage created by such environmental pressures.

Risks Related to the Ownership of our Common Stock

We have incurred and will continue to incur increased costs and demands upon management and accounting and finance resources as a result of complying with the laws and regulations affecting public companies; any failure to establish and maintain adequate internal control over financial reporting or to recruit, train and retain necessary accounting and finance personnel could have an adverse effect on our ability to accurately and timely prepare our consolidated financial statements.

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As a public operating company, we incur significant administrative, legal, accounting and other burdens and expenses beyond those of a private company, including those associated with corporate governance requirements and public company reporting obligations. In particular, we have had to and will continue to expend resources to supplement our internal accounting and financial resources to obtain technical and public company training and expertise, as well as refine our quarterly and annual financial statement closing process, to enable us to satisfy such reporting obligations. However, even if we are successful in doing so, there can be no assurance that our finance and accounting organization will be able to adequately meet the increased demands that result from being a public company.

Our management team must comply with various requirements of being a public company.  We have devoted, and will continue to devote, significant resources to address these public company-associated requirements, including compliance programs and investor relations, as well as our financial reporting obligations. Complying with these rules and regulations has and will substantially increase our legal and financial compliance costs and make some activities more time-consuming and costly.

An active, liquid and orderly trading market for our common stock may not develop, and the price of our stock may be volatile and may decline in value.

There currently is not an active public market for our common stock. An active trading market may not develop or, if developed, may not be sustained. The lack of an active market may impair your ability to sell your shares of common stock at the time you wish to sell them or at a price that you consider reasonable. An inactive market may also impair our ability to raise capital by selling shares of common stock and may impair our ability to acquire other companies or assets by using shares of our common stock as consideration.

Our common stock may not be eligible for listing on a national securities exchange.

Our common stock is not currently listed on a national securities exchange, and we do not currently meet the initial quantitative listing standards of a national securities exchange. We cannot assure you that we will be able to meet the initial listing standards of any national securities exchange, or, if we do meet such initial qualitative listing standards, that we will be able to maintain any such listing. Until our common stock is listed on a national securities exchange, we expect that it will continue to be eligible and quoted on the OTCQB.  In those venues, however, an investor may find it difficult to obtain accurate quotations as to the market value of our common stock. In addition, if we fail to meet the criteria set forth in SEC regulations, various requirements would be imposed by law on broker-dealers who sell our securities to persons other than established customers and accredited investors. Consequently, such regulations may deter broker-dealers from recommending or selling our common stock, which may further affect its liquidity. This would also make it more difficult for us to raise additional capital.

Our common stock may be considered a “penny stock.”

The SEC has adopted regulations which generally define “penny stock” to be an equity security that has a market price of less than $5.00 per share, subject to specific exemptions. The market price of our common stock may be less than $5.00 per share and therefore may be a “penny stock.” Broker and dealers effecting transactions in “penny stock” must disclose certain information concerning the transaction, obtain a written agreement from the purchaser and determine that the purchaser is reasonably suitable to purchase the securities. These rules may restrict the ability of brokers or dealers to sell our common stock and may affect your ability to sell shares of our common stock in the future.

Control of our stock by current stockholders is expected to remain significant.

Currently, our directors directly and indirectly beneficially own a majority of our outstanding common stock. As a result, these affiliates have the ability to exercise significant influence over matters submitted to our stockholders for approval, including the election and removal of directors, amendments to our certificate of incorporation and bylaws and the approval of any business combination. This concentration of ownership may also have the effect of delaying or preventing a change of control of our company or discouraging others from making tender offers for our shares, which could prevent our stockholders from receiving a premium for their shares.

It is not likely that we will pay dividends.

We currently intend to retain our future earnings to support operations and to finance expansion and, therefore, we do not anticipate paying any cash dividends to holders of our common stock in the foreseeable future.

Terms of subsequent financings may adversely impact stockholder equity.

We may have to raise additional equity or debt in the future.  In that event, the value of the stockholders’ equity in common stock could be reduced.  For example, if we issue debt securities, the holders of the debt would have a claim to our assets that

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would be prior to the rights of shareholders until the debt is paid.  Interest on these debt securities would increase costs and could negatively impact operating results.

Additionally, the borrowing base under our secured lending facility presently is $20 million (subject to increase depending on additions to reserves, and other factors), and all borrowings under the facility are secured by a majority of our oil and natural gas assets.  Borrowings outside the facility may have to be unsecured, and accordingly, such borrowings, if obtainable, would have a higher interest rate, which would increase debt service and more negatively impact operating results.

Preferred stock could be issued in series from time to time with such designations, rights, preferences, and limitations as needed to raise capital.  The terms of preferred stock will be determined by our Board of Directors and could be more advantageous to those investors than to the holders of common stock.  In addition, if we need to raise more equity capital from sale of common stock, institutional or other investors may negotiate terms more favorable than the then current price of Company’s common stock.

The Company’s Certificate of Incorporation does not provide shareholders the pre-emptive right to buy shares from the Company.  As a result, stockholders will not have the automatic ability to avoid dilution in their percentage ownership of the company.

Item 1B.  Unresolved Staff Comments

None.

Item 2.    Properties.

Information on Properties is contained in Item 1 of this Annual Report on Form 10-K.

Item 3.    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 August 2011, Nytis LLC was served with a summons and complaint brought by James B. Lauffer, filed in Martin County, Kentucky.  The suit was brought against The Interstate Natural Gas Company, LLC (“ING”), and Nytis LLC was named as a co-defendant.  The complaint alleges that ING (i) has failed to pay plaintiff for its overriding royalty interests and working interest related to certain wells located on property in Martin County, Kentucky and (ii) has improperly deducted operating expenses from payments made to plaintiff in connection with plaintiff’s overriding royalties from one well.  The amount of damages allegedly suffered by Mr. Lauffer is not specified in the complaint.  Pursuant to the Asset Purchase Agreement by and between ING and Nytis LLC (the “ING APA”), ING agreed to indemnify Nytis LLC for (i) all Losses (as such term is defined in the ING APA) arising from the breach by ING of any representation, warranty or covenant set forth in the ING APA that survives Closing and (ii) all Losses arising from or in connection with the Excluded Obligations (as such term is defined in the ING APA).  Nytis LLC believes that the claims alleged by Mr. Lauffer are subject to indemnification by ING pursuant to the ING APA and on October 27, 2011, Nytis LLC delivered a written notice of claim for indemnification to ING.  Nytis LLC engaged Kentucky counsel in connection with the claims brought by Mr. Lauffer as well as in connection with asserting Nytis LLC’s claim for indemnification from ING.  Nytis LLC is being represented by James H. Moore III with the firm of Campbell Woods, PLLC, Ashland, Kentucky.  As of the date of this Annual Report on Form 10-K, Mr. Lauffer and Nytis LLC have agreed in principle to settle the matter and are in the process of memorializing the terms of the settlement.

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 a certain coal seam gas lease currently held by Nytis LLC.  Addington Exploration, LLC (the party from which Nytis LLC obtained the lease at issue) was named as a co-defendant in the complaint.  Nytis LLC, with the assistance of Indiana counsel, filed a motion to dismiss these claims, however, that motion was denied by the Vigo Superior Court in February 2012.  Nytis LLC has subsequently filed an answer and affirmative defenses. No trial date has been set.

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

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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 July 2010, Nytis LLC 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.

PART II

Item 5.    Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Common Stock

Carbon has one class of common shares outstanding, its common stock, par value $0.01 per share (“Common Stock”). Our common stock is quoted through the OTC Markets (“OTCQB”) under the symbol CRBO. However, the limited and sporadic quotations of our stock may not constitute an established trading market for our stock.  The table below sets forth the high and low bid prices per share of our common stock as quoted on the OTCQB for the periods indicated.  Prior to May 11, 2011, the common stock traded under the symbol STLS. All OTCQB quotations included herein reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.  Prior to the Merger, there was limited or no trading activity in SLSC’s common stock and there has continued to be a lack of trading activity in our common stock. There can be no assurance that an active market will develop for our common stock in the future.

Year Ended December 31,	Quarter	High		Low
2011	First	$	1.01	$	0.70
	Second	$	1.20	$	0.40
	Third	$	1.49	$	0.50
	Fourth	$	1.01	$	0.55
2010	First	$	1.02	$	0.66
	Second	$	1.02	$	1.02
	Third	$	1.02	$	0.68
	Fourth	$	1.01	$	0.70

As of March 12, 2012, the closing bid price for our common stock on the OTCQB was $0.65 per share.

Holders

As of March 12, 2012, there were approximately 1,200 holders of record of our common stock.  The number of holders does not include the shareholders for whom shares are held in a “nominee” or “street” name.

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Dividend Policy and Restrictions

We have not paid any cash dividends on our common stock to date. The payment of dividends in the future will be contingent upon our revenues and earnings, if any, capital requirements and general financial condition, and will be within the discretion of our then-existing Board of Directors. We currently intend to retain our future earnings to support operations and to finance expansion and, therefore, our Board of Directors does not anticipate paying any cash dividends to holders of our common stock in the foreseeable future.

The Company’s ability to pay distributions is currently limited by:

·The terms of our credit facility with the Bank of Oklahoma prohibit us from paying dividends on our common stock while amounts are owed to the Bank of Oklahoma; and

·The Delaware General Corporation Law also provides that a Delaware corporation may pay dividends either: 1) out of the corporation’s surplus (as defined by Delaware law); or 2) if there is no surplus, out of the corporation’s net profit for the fiscal year in which the dividend is declared or the preceding fiscal year. Any determination in the future to pay dividends will depend on the Company’s financial condition, capital requirements, results of operations, contractual limitations, legal restrictions and any other factors the Board of Directors deem relevant.

Securities Authorized for Issuance Under Compensation Plans

Our Board of Directors has adopted the 2011 Stock Incentive Plan (the “Plan”) under which 12,600,000 shares of common stock are authorized for issuance.  On December 8, 2011, the stockholders approved the adoption of the Plan at Carbon’s annual meeting of shareholders.  As of December 31, 2011, no awards had been made under the Plan.

Upon closing the Merger, the Company assumed outstanding options granted prior to the Merger to acquire 342,459 shares of common stock.  At the time of the Merger such options became exercisable to acquire Company common stock and the terms of the options were amended to reflect the exchange ratio used to effect the Merger.  The following is provided with respect to compensation plans (including individual compensation arrangements) under which equity securities are authorized for issuance as of December 31, 2011:

Equity Compensation Plan Information
					Number of Securities
					Remaining Available
	Number of Securities				for Future Issuance
	to be Issued Upon		Weighted-Average		Under Equity
	Exercise of		Exercise Price of		Compensation Plans
	Outstanding Options,		Outstanding Options,		(Excluding Securities
Plan Category	Warrants, and Rights		Warrants, and Rights		Reflected in Column (a))
and Description	(a)		(b)		(c)
Equity Compensation Plans Approved by Security Holders (1)(3)	—		—		12,600,000
Equity Compensation Plans Not Approved by Security Holders	269,075	(2)	$	0.63	—
Total	269,075		$	0 .63	12,600,000

(1)On December 8, 2011 the Company’s shareholders approved the adoption of the Company’s 2011 Stock Incentive Plan under which 12,600,000 shares are reserved for issuance.  As of December 31, 2011, no awards had been made pursuant to such Plan.

(2)Consists of options granted prior to the Merger by Nytis USA to persons who are affiliates and former affiliates of Nytis USA (three of which are now officers and former directors of the Company).  All of these options were assumed by the Company at the time of the Merger.

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(3)Subsequent to December 31, 2011, the Company has issued 1,450,000 restricted shares and 1,096,500 restricted performance units pursuant to the Plan.

Unregistered Sales of Equity Securities

All sales of unregistered equity securities that occurred during the period covered by this report, and through December 31, 2011, have been previously reported in a Quarterly Report on Form 10-Q or a Current Report on Form 8-K.

Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion includes forward-looking statements about our business, financial condition and results of operations, including discussions about management’s expectations for our business. These statements represent projections, beliefs and expectations based on current circumstances and conditions and in light of recent events and trends, and you should not construe these statements either as assurances of performance or as promises of a given course of action. Instead, various known and unknown factors are likely to cause our actual performance and management’s actions to vary, and the results of these variances may be both material and adverse. A description of material factors known to us that may cause our results to vary, or may cause management to deviate from its current plans and expectations, is set forth under “Risk Factors.” See “Cautionary Note Regarding Forward-Looking Statements.” The following discussion should also be read in conjunction with our Consolidated Financial Statements, including the notes thereto appearing elsewhere in this Annual Report on Form 10-K.

Carbon is an independent natural gas and oil company engaged in the acquisition, exploration, development and production of natural gas and oil properties located in the Appalachian and the Illinois Basin of the United States. We focus on unconventional reservoirs, including fractured shale gas plays, tight gas sands and coalbed methane.  Our corporate headquarters are in Denver, Colorado and Lexington, Kentucky.

Prior to the Merger, our management team led Nytis USA and has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience developing natural gas and oil resource plays to profitably grow our reserves and production, primarily through internally generated projects on our existing acreage and acquisitions within our core geographic areas. As of December 31, 2011, 93% of our proved reserves were natural gas, 67% were proved developed and 90% of our production was operated by us. From December 31, 2004 through December 31, 2011, we grew our estimated proved reserves from 15.6 Bcfe to 63.2 Bcfe. In addition, we grew our average daily production from 1,000 Mcfe for the year ended December 31, 2005 to 7,000 Mcfe at December 31, 2011.

We have assembled a diversified portfolio of long-lived properties that are characterized by what we believe to be low geologic risk and a large inventory of repeatable drilling opportunities. Our drilling opportunities are focused in the Appalachian and Illinois Basins. From January 2005 through December 31, 2011, we have drilled or participated in over 100 vertical or horizontal wells with a success rate of approximately 98%. Our drilling inventory consists of approximately 1,100 potential horizontal drilling locations, all of which are resource-style opportunities and approximately 10% of which are included in our estimated proved reserve base as of December 31, 2011. For information on the possible limitations on our ability to drill our potential locations, see Risk Factor - “Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations.”

Recent developments

Merger

On January 31, 2011, Nytis USA entered into a Merger Agreement with SLSC, which was closed on February 14, 2011.  At that date, SLSC acquired all of the issued and outstanding shares of Nytis USA from the Nytis USA stockholders, and thereby became the indirect owner of all of Nytis USA’s equity interests in Nytis LLC and Nytis PA, in exchange for the issuance by SLSC to the Nytis USA stockholders of 47,000,003 restricted shares of SLSC common stock (which then constituted 98.9% of SLSC’s issued and outstanding common stock), and Nytis USA became a wholly-owned subsidiary of SLSC, and Nytis LLC and Nytis PA became majority-owned indirect subsidiaries of SLSC.

The Company’s Consolidated Financial Statements for periods prior to the Merger represent the consolidated financial statements of Nytis USA.

In connection with the closing of the Merger, the officers and directors of Nytis USA became the officers and directors of SLSC.  On May 2, 2011, SLSC’s name was changed to Carbon Natural Gas Company.

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Purchase of Certain Assets of The Interstate Natural Gas Company, LLC and Alerion Drilling I, LLC

The 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 were comprised of (i) some but not all of its 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; 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.

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 gathered 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 from ING.  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 affected an initial (the “Initial Closing”) and subsequent close (the “Final Closing”).  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 (the “Alerion APA”) 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 effective as of January 1, 2011.  The purchase price paid by Nytis LLC was approximately $1.2 million.

The Private Placement

The Private Placement closed on June 29, 2010 with the sale of 44,444,444 common stock shares at a price of $0.45 per share and 100 shares of our Series A Convertible Preferred Stock at a price of $100,000 per share.  There were 24 investors, including Yorktown Energy Partners IX, L.P.  Because we 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, we 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 so implemented, and we issued 22,222,222 common shares to Yorktown Energy Partners IX, L.P.  Upon such 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.

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Net proceeds from the Private Placement were principally used for our majority owned subsidiary, Nytis LLC, to complete the acquisitions from ING and Alerion Drilling described above.  The remainder of the net proceeds were used for general working capital purposes.

Change of Fiscal Year

On February 10, 2011, the Board of Directors of SLSC, unanimously approved amendments to amended and restated bylaws.  The amendments became effective immediately upon their adoption by the board.  Article XVI, Section 16.2 was amended to read as follows: “The fiscal year of the corporation shall end on December 31, unless otherwise fixed by resolution of the Board of Directors.”  Previously SLSC’s fiscal year ended on March 31 of each year.

Revenue Sources

Our production revenues are entirely from the continental United States and for the year ended December 31, 2011 are comprised of 96% natural gas and 4% oil and liquids. Gas prices reached historically high levels in recent years and reached over $13.00 per MMBtu in July 2008. Since then, natural gas prices have declined sharply to below $3.00 per MMBtu in September of 2009 and for portions of 2012.  Natural gas and oil prices are inherently volatile and are influenced by many factors outside of our control. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we use derivative instruments to hedge future sales prices on a portion of our production. We currently use fixed price swaps in which we receive a fixed price for future production in exchange for a payment of the variable market price received at the time future production is sold. At each period end we estimate the fair value of these swaps and recognize any unrealized gain or loss. We have not elected hedge accounting and, accordingly, the unrealized gains and losses on open positions are reflected currently in earnings. We expect continued volatility in the fair value of these swaps.

Principal Components of Our Cost Structure

·Lease operating and gathering, compression and transportation expenses.  These are daily costs incurred to bring natural gas and oil out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our natural gas properties.

·Production taxes.  Production taxes consist of severance and ad valorem taxes and are paid on natural gas and oil produced based on a percentage of market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities.

·Depreciation, depletion, amortization and impairment.  The Company uses the full cost method of accounting for oil and gas properties.  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.  The Company historically has performed a ceiling test quarterly.  The full cost ceiling test is a limitation on capitalized cost prescribed by the SEC.  The ceiling test is not a fair value based measurement, rather it is a standardized mathematical calculation that compares the net capitalized costs of the Company’s full cost pool to estimated discounted cash flows.  Should the net capitalized cost exceed the sum of the estimated discounted cash flows, a ceiling test write-down would be recognized to the extent of the excess.

The Company performs its ceiling tests based on average first-of-the-month prices during the twelve-month period prior to the reporting date.  The Company’s net capitalized cost of its natural gas and oil properties exceeded the ceiling limitation by $15.8 million for the year ended December 31, 2011, resulting in an impairment charge for that amount. The Company did not have any ceiling test write downs for the year ended December 31, 2010.

Depletion is calculated using the capitalized costs in the full cost pool, including estimated asset retirement costs and the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values and depleted based on a unit-of-production method.

·General and administrative expense.  These costs include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit, tax, legal and other professional fees and legal compliance.

·Interest expense.  We finance a portion of our working capital requirements and acquisitions with borrowings under our bank credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We will likely continue to incur interest expense as we continue to grow.

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·Income tax expense.  Each of the Company’s subsidiaries file separate federal and state income tax returns; therefore, our provision for income taxes consists of the sum of our income tax provisions for each of the operating entities. We are subject to state and federal income taxes but historically have not been in a tax paying position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs (“IDC”). However, in 2010, due to the sale of our Pennsylvania assets we were subject to federal and state income taxes.  We do pay some state income or franchise taxes where our IDC deductions do not exceed our taxable income or where state income or franchise taxes are determined on another basis. Collectively, our operating entities have generated net operating loss carryforwards which expire starting in 2025 through 2031. The amount of deferred tax assets considered realizable, however, could change in the near term as we generate taxable income or estimates of future taxable income are reduced.

Significant Acquisitions and Dispositions

During 2010, we completed the sale of our Pennsylvania assets and used the proceeds to significantly reduce the outstanding amounts under our bank credit facility.  During 2011, we completed the acquisitions of certain assets from ING and Alerion Drilling funded from proceeds of the Private Placement.  The following table presents a summary of our significant acquisitions and dispositions for the years ended December 31, 2011 and 2010.

Primary Locations of Acquired Properties	Date Acquired	Purchase Price
		(in millions)
Appalachian Basin (KY/WV)	June 2011	$	25.9
Appalachian Basin (KY/WV)	July 2011	$	1.2
Illinois Basin (IL/IN)	December 2010	$	0.5
Illinois Basin (IL)	September 2010	$	0.6
Appalachian Basin (KY)	June 2010	$	1.3

Primary Locations of Dispositions	Date Disposed	Sales Price
		(in millions)
Appalachian Basin (WV)	September 2010	$	0.8
Appalachian Basin (PA)	March-April 2010	$	30.3

Our acquisitions for the years ended December 31, 2011 and 2010 were financed with a combination of borrowings under our credit facilities, cash flow from operations, and funds we received through the sale of our common and preferred stock (later converted to common stock) in the Private Placement that closed on June 29, 2011.

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Results of Operations

The following discussion and analysis relates to items that have affected our results of operations for the years ended December 31, 2011 and 2010.  The following table sets forth for the periods presented selected historical statements of operations data.  The information contained in the table should be read in conjunction with the Company’s Consolidated Financial Statements and the information under “Forward Looking Statements” above.

	Twelve Months Ended
	December 31,						Increase /			Percent
(in thousands except per unit data)	2011			2010			(Decrease)			Change
Revenue:
Oil and natural gas sales	$	9,018		$	4,880		$	4,138		85	%
Commodity derivative gain	459			692			(233		)	-34	%
Other income	226			286			(60		)	-21	%
Total revenues	9,703			5,858			3,845			66	%
Expenses:
Lease operating expenses	1,932			1,053			879			83	%
Transportation costs	1,242			444			798			180	%
Production and property taxes	684			430			254			59	%
General and administrative	4,638			3,021			1,617			54	%
Depreciation, depletion and amortization	2,664			1,540			1,124			73	%
Accretion of asset retirement obligations	95			18			77			428	%
Impairment of oil and gas properties	15,769			—			15,769			*
Total expenses	27,024			6,506			20,518			315	%
Operating loss	$	(17,321	)	$	(648	)	$	16,673		*
Other income and expenses:
Interest income	$	1		$	38		$	(37	)	*
Interest expense	(483		)	(352		)	131			37	%
Other expenses	(13		)	—			13			*
Equity investment income	32			23			9			39	%
Gain on sale of properties	—			10,104			(10,104		)	*
Total other expenses and income	$	(463	)	$	9,813		$	(10,276	)	-105	%
Production data:
Natural gas (MMcf)	1,797			1,000			797			80	%
Oil and liquids (MBbl)	14			2			12			*
Combined (MMcfe)	1,882			1,011			871			86	%
Average prices before effects of hedges:
Natural gas (per Mcf)	$	4.37		$	4.77		$	(0.40	)	-8	%
Oil and liquids (per Bbl)	$	82.36		$	58.65		$	23.71		41	%
Combined (per Mcfe)	$	4.79		$	4.83		$	(0.04	)	-1	%
Average prices after effects of hedges**:
Natural gas (per Mcf)	$	4.63		$	5.47		$	(0.84	)	15	%
Oil and liquids (per Bbl)	$	82.38		$	58.65		$	23.73		40	%
Combined (per Mcfe)	$	5.04		$	5.51		$	(0.47	)	-9	%
Average costs (per Mcfe):
Lease operating expenses	$	1.03		$	1.04		$	(0.01	)	-1	%
Transportation costs	$	0.66		$	0.44		$	0.22		50	%
Production and property taxes	$	0.36		$	0.43		$	(0.07	)	-16	%
Depreciation, depletion and amortization	$	1.42		$	1.52		$	(0.10	)	-7	%

*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 $9.0 million for the year ended December 31, 2011 from $4.9 million for the year ended December 31, 2010. This increase was primarily due to new revenues received from oil and gas properties acquired from ING and Alerion Drilling on June 29, 2011 and July 27, 2011, respectively, and oil revenues from new oil producing properties drilled in 2011.

	2011		2010		Increase/ (Decrease)
Oil and natural gas sales
Other properties	$	5,218	$	4,880	$	338
Acquired properties*	3,800		—		3,800
Total	$	9,018	$	4,880	$	4,138

	2011	2010	Increase/ (Decrease)
Production - MMcfe
Other properties	1,056	1,011	45
Acquired properties*	826	—	826
Total	1,882	1,011	871

* 6 months

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-market gains or losses, as well as realized gains or losses on the derivative instruments, are currently recognized in our results of operations.  The unrealized gains and losses represent the changes in the fair value of these swap agreements as future strip prices fluctuate compare to the fixed price we will receive from these swap agreements.  For the year ended December 31, 2011 we had hedging gains of approximately $459,000 compared to hedging gains of approximately $692,000 for the year ended December 31, 2010.

Lease operating expenses- Lease operating expenses increased approximately 83% for the year ended December 31, 2011 compared to the year ended December 31, 2010 primarily due to the addition of oil and gas properties acquired from ING and Alerion Drilling on June 29, 2011 and July 27, 2011, respectively, 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 decreased from $1.04 per Mcfe for the year ended December 31, 2010 to $1.03 per Mcfe for the year ended December 31, 2011.

	2011		2010		Increase/ (Decrease)
Lease operating expenses
Other properties	$	1,439	$	1,053	$	386
Acquired properties*	493		—		493
Total	$	1,932	$	1,053	$	879

* 6 months

Transportation costs- Transportation costs increased from approximately $444,000 for the year ended December 31, 2010 to approximately $1.2 million for the year ended December 31, 2011 due to transportation price increases and transportation costs for new production from the Company’s Illinois properties and transportation for production from oil and gas properties acquired from ING and Alerion Drilling on June 29, 2011 and July 27, 2011, respectively. On a per Mcfe basis, these expenses increased from $0.44 per Mcfe for the year ended December 31, 2010 to $0.66 per Mcfe for the year ended December 31, 2011 due to higher gathering costs per Mcfe incurred on the acquired properties compared to the Company’s properties prior to the acquisitions.

	2011		2010		Increase/ (Decrease)
Transportation costs
Other properties	$	856	$	444	$	412
Acquired properties*	386		—		386
Total	$	1,242	$	444	$	798

* 6 months

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Production and property taxes- Production and property taxes increased from approximately $430,000 for the year ended December 31, 2010 to approximately $684,000 for the year ended December 31, 2011 primarily due to new natural gas production in the Illinois Basin, new oil production in the Appalachian Basin and new oil and gas production from properties acquired from ING and Alerion Drilling on June 29, 2011 and July 27, 2011, respectively. On a per Mcfe basis, these expenses decreased from $0.43 per Mcfe for the year ended December 31, 2010 to $0.36 per Mcfe for the year ended December 31, 2011.

	2011		2010		Increase/ (Decrease)
Production and property taxes
Other properties	$	507	$	430	$	77
Acquired properties*	177		—		177
Total	$	684	$	430	$	254

* 6 months

Depreciation, depletion and amortization (DD&A)- DD&A increased from approximately $1.5 million for the year ended December 31, 2010 to approximately $2.7 million for the year ended December 31, 2011.  On a per Mcfe basis, these expenses decreased from $1.52 per Mcfe for the year ended December 31, 2010 to $1.42 per Mcfe for the year ended December 31, 2011.  The Company’s depletion rate decreased due to the impact on the blended rate of the ING and Alerion Drilling acquisitions which had a lower depletion rate than the Company’s depletion rate on its oil and gas properties prior to the acquisitions.

Impairment of oil and gas properties- The Company recognized a non-cash impairment expense of approximately $15.8 million due to the Company’s full cost pool exceeding the ceiling limitation for year ended December 31, 2011.  The impairment for the year ended December 31, 2011 was primarily due to a decrease in natural gas prices and to a new gathering arrangement on certain of the Company’s proved undeveloped gas reserves in Kentucky and reductions in natural gas prices utilized in calculating the present value of future net revenues from the Company’s proved gas reserves.  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 year ended December 31, 2010, the Company did not record a non-cash impairment.

General and administrative expenses- General and administrative expenses increased from $3.0 million for the year ended December 31, 2010 to $4.6 million for the year ended December 31, 2011 primarily due to costs totaling approximately $712,000 associated with the merger with SLSC and the acquisition of the ING Assets and Alerion Drilling oil and gas interests.  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 year ended December 31, 2011 as compared with the year ended December 31, 2010.

	2011			2010			Increase/ (Decrease)
General and administrative expenses	$	4,756		$	3,094		$	1,662
Reimbursements	(118		)	(73		)	45
General and administrative expense, net	$	4,638		$	3,021		$	1,617

Interest expense- Interest expense increased from approximately $352,000 for the year ended December 31, 2010 to approximately $483,000 for the year ended December 31, 2011 primarily due to average higher debt balances during 2011 as compared with 2010. During the year ended December 31, 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.

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 PA 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 of $10.1 million in the first quarter of 2010.

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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 or selling shares of the Company’s stock, such as the Private Placement.

Changes in the market prices for natural gas directly impact our level of cash flow generated from operations. Natural gas made up approximately 96% and 99% of our hydrocarbon production for the years ended December 31, 2011 and 2010, respectively, 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 December 31, 2011, we have outstanding natural gas hedges of 160,000 MMbtu for 2012 at an average price of $5.11 per MMbtu and oil hedges of 6,000 barrels for 2012 at an average price of $99.30.  This level of hedging will provide a measure of certainty of the cash flow that we will receive for a portion of our production in 2012.  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,” 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 December 31, 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 of which $11.2 million was available as of December 31, 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 mature in May 2014. See—“Bank Credit Facility” below for further details.

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, expected future cash flows provided by operating activities, and the approximately $11.2 million of additional borrowing capacity available under our credit facility as of December 31, 2011 will be sufficient to fund our normal recurring operating needs, anticipated capital expenditures (other than the potential acquisition of additional natural gas and oil properties), and our contractual obligations. However, if our revenue and cash flow decrease in the future as a result of 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,” 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 December 31, 2011 was $20.0 million. The determination of the Borrowing Base is made by the lender in its sole discretion, on a semi-annual basis, taking into consideration the estimated value of our natural gas properties in accordance with the lender’s customary practices for natural gas loans. The available borrowing amount under the Credit Facility could increase or decrease based on such redetermination. The next redetermination of the Borrowing Base is expected to occur in May 2012. In addition to the semi-annual redeterminations, Nytis LLC and the lender each have discretion at any time, but not more often than once during a calendar year, to have the Borrowing Base redetermined.

A lowering of the Borrowing Base could require us to repay indebtedness in excess of the Borrowing Base in order to cover the deficiency.

The facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base.  Interest rates are based on either an Alternate Base Rate or LIBOR.  The portion of the loan based on an “Alternate Base Rate” is determined by the rate per annum equal to 1.5% plus the greatest of the following: (a) the Federal Funds Rate for such day plus one-half of one percentage point, (b) the Prime Rate for such day or (c) LIBOR for a one-month LIBOR Interest Period plus one percentage point.  The portion based on LIBOR is determined by the rate per annum equal to LIBOR plus between 2.5% and 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, as defined) of 1.0 to 1.0 and a maximum Funded Debt

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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 lender, 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 affiliates 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 December 31, 2011 there was approximately $8.8 million in borrowings under the 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.

Historical Cash Flow

Net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 2011 and 2010 were as follows:

	Years Ended
	December 31,
(in thousands)	2011			2010
Net cash used in operating activities	$	(2,661	)	$	(2,679	)
Net cash (used in) provided by investing activities	$	(30,971	)	$	25,567
Net cash provided by (used in) financing activities	$	33,260		$	(22,251	)

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.  Operating cash flows increased approximately $18,000 for the year ended December 31, 2011 as compared to the year ended December 31, 2010.

Net cash (used in) provided by 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 $56.5 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010 was primarily due to the acquisition of oil and gas properties from ING in the 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 $55.5 million for the year ended December 31, 2011 as compared to the year ended December 31, 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.

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Capital Expenditures

Capital expenditures for the years ended December 31, 2011 and 2010 are summarized in the following table:

	Years Ended December 31,
(in thousands)	2011		2010
Acquisition of oil and gas properties:
Unevaluated properties	$	276	$	81
Natural gas and oil producing properties	27,058		1,806
Drilling and development	3,305		2,987
Pipeline and gathering	163		—
Other	271		—
Total capital expenditures	$	31,073	$	4,874

Capital expenditures reflected in the table above represent cash used for capital expenditures and does not include non-cash transactions of the acquisitions described in Note 4 of the Company’s consolidated financial statements.  Our reserve report anticipates $3.1 million of future capital expenditures in 2012 which we intend to fund through our capacity on our borrowing base or additional equity as needed.

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 for drilling activity for the years ended December 31, 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 December 31, 2011, the Company’s ceiling test resulted in an impairment of approximately $15.8 million.  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.

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 December 31, 2011, the off-balance sheet arrangements and transactions that we have entered into include (i) operating lease agreements, (ii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as certain natural gas transportation commitments, and (iii) gas physical delivery contracts that are not expected to be net cash settled and are considered to be normal sales contracts and not derivatives.  We do not believe that any of these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.

Critical Accounting Policies, Estimates, Judgments, and Assumptions

Full Cost Method of Accounting

The accounting for our business is subject to special accounting rules that are unique to the natural gas and oil industry.  There are two allowable methods of accounting for natural gas and oil business activities: the full cost method and the successful efforts method.  The differences between the two methods can lead to significant variances in the amounts reported in financial statements.  We have elected to follow the full cost method, which is described below.

Under the full cost method, separate cost centers are maintained for each country in which we incur costs.  All costs incurred in the acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to exploration and development activities) are capitalized. The fair value of estimated future costs of site restoration, dismantlement, and abandonment activities is capitalized, and a corresponding asset retirement obligation liability is recorded.

Capitalized costs applicable to each full cost center are depleted using the units-of-production method based on conversion to common units of measure using one barrel of oil as an equivalent to six thousand cubic feet of natural gas. Changes in estimates of reserves or future development costs are accounted for prospectively in the depletion calculations. Based on this accounting policy, our December 31, 2011 and 2010 reserves estimates were used for our respective period depletion calculations. These reserves estimates were calculated in accordance with SEC rules. See “Business—Reserves” and Notes 1 and 2 to the consolidated financial statements for a more complete discussion of the rule and our estimated proved reserves as of December 31, 2011 and 2010.

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Companies that use the full cost method of accounting for natural gas and oil exploration and development activities are required to perform a ceiling test for each cost center. 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 test determines a limit, or ceiling, on the book value of natural gas properties. That limit is basically the after tax present value of the future net cash flows from proved natural gas reserves. This ceiling is compared to the net book value of the natural gas and oil properties reduced by any related net deferred income tax liability. If the net book value reduced by the related deferred income taxes exceeds the ceiling, an impairment or non-cash write-down is required. Our December 31, 2011 ceiling test calculation, which included a ceiling based on natural gas and oil reserves calculated using twelve-month average prices, resulted in the Company’s natural gas and oil properties exceeding the ceiling limitation by approximately $15.8 million, and accordingly the Company took a non-cash charge to income for approximately $15.8 million for the year ended December 31, 2011.  The Company did not have a ceiling test write down for the year ended December 31, 2010.  If oil and gas prices decrease, we may be required to recognize an impairment of our oil and gas properties in future periods, which could have a material adverse effect on our results of operations in the period recognized.

In countries or areas where the existence of proved reserves has not yet been determined, leasehold costs, seismic costs, and other costs incurred during the exploration phase remain capitalized as unproved property costs until proved reserves have been established or until exploration activities cease. Investments in unproved properties are not depleted pending the determination of the existence of proved reserves. If exploration activities result in the establishment of proved reserves, amounts are reclassified as proved properties and become subject to depreciation, depletion, and amortization, and the application of the ceiling limitation. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to individually assess properties whose costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized in the appropriate full cost pool.

Under the alternative successful efforts method of accounting, surrendered, abandoned, and impaired leases, delay lease rentals, exploratory dry holes, and overhead costs are expensed as incurred. Capitalized costs are depleted on a property-by-property basis. Impairments are also assessed on a property-by-property basis and are charged to expense when assessed.

The full cost method is used to account for our natural gas and oil exploration and development activities, because we believe it appropriately reports the costs of our exploration programs as part of an overall investment in discovering and developing proved reserves.

Natural Gas Reserve Estimates

Our estimates of proved reserves are based on the quantities of natural gas and oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production and property taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Despite the inherent uncertainty in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our natural gas and oil properties, the quantity of reserves could significantly impact our DD&A expense. Our natural gas and oil properties are also subject to a “ceiling test” limitation based in part on the quantity of our proved reserves.

Reference should be made to “Reserves” under “Description of Business,” and “Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves,” under “Risk Factors”.

Accounting for Derivative Instruments

We recognize all derivative instruments as either assets or liabilities at fair value. Under the provisions of authoritative derivative accounting guidance, we may or may not elect to designate a derivative instrument as a hedge against changes in the fair value of an asset or a liability (a “fair value hedge”) or against exposure to variability in expected future cash flows (a “cash flow hedge”). The accounting treatment for the changes in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is a cash flow hedge or a fair value hedge, and upon whether or not the derivative is designated as a hedge. Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings. Changes in the fair value of a derivative instrument designated as a fair value hedge, to the extent the hedge is effective, have no effect on the statement of operations, because changes in fair value of the derivative offsets changes in the fair value of the hedged item. Where hedge accounting is not elected or if a derivative instrument does not qualify as either a fair value hedge or a cash flow hedge, changes in fair value are recognized in earnings. We have elected

42

not to use hedge accounting and as a result, all changes in the fair values of our derivative instruments are recognized in commodity derivative gains in our consolidated statements of operations.

As of December 31, 2011 and 2010, the fair value of the Company’s derivative agreements was a current asset of approximately $308,000 and $171,000, respectively.  The fair value measurement of the commodity derivative assets and liabilities are measured based upon our valuation model that considers various inputs including (a) quoted forward prices for commodities, (b) time value, (c) notional quantities, (d) current market and contractual prices for the underlying instruments; and (e) the counterparty’s credit risk.  The unobservable inputs related to the volatility of the oil and gas commodity market are very significant in these calculations.  Continued volatility in these markets could have a significant impact on the fair value of our derivative contracts.  See Note 11 to the consolidated financial statements for further discussion.  The values we report in our financial statements change as these estimates are revised to reflect changes in market conditions or other factors, many of which are beyond our control.

Due to the volatility of natural gas and oil prices, the estimated fair values of our commodity derivative instruments are subject to large fluctuations from period to period and we expect the volatility to continue. Actual gains or losses recognized related to our commodity derivative instruments will likely differ from those estimated at December 31, 2011 and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.

Valuation of Deferred Tax Assets

We use the asset and liability method of accounting for income taxes. Under this method, income tax assets and liabilities are determined based on differences between the financial statement carrying values of assets and liabilities and their respective income tax bases (temporary differences). Income tax assets and liabilities are measured using the tax rates expected to be in effect when the temporary differences are likely to reverse. The effect on income tax assets and liabilities of a change in tax rates is included in earnings in the period in which the change is enacted. The book value of income tax assets is limited to the amount of the tax benefit that is more likely than not to be realized in the future.

In assessing the need for a valuation allowance on our deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize net operating loss and credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both negative and positive. Negative evidence considered by management primarily included a recent history of book losses which were driven entirely from ceiling test write-downs, which are not fair value based measurements. Positive evidence considered by management included forecasted book income over a reasonable period of time and the utilization of significant net operating loss (“NOL”) carryforwards in 2010 due primarily to a substantial tax gain associated with the disposition of the Company’s Pennsylvania assets.  See Note 8 to the Consolidated Financial Statements.

The primary evidence utilized to determine that it is more likely than not that our deferred tax assets will be realized is management’s expectation of future book income over the next several years, as well as the significant tax gain recognized in connection with the sale of our Pennsylvania assets during 2010, which allowed us to realize a significant amount of our deferred tax assets that were attributable to NOL carryforwards. With a majority of our NOL carryforwards utilized, our deferred tax asset position is now almost exclusively driven by the accelerated reduction in the book value of our natural gas assets relative to our tax basis due to the use of the full cost method of accounting for natural gas and oil properties.

Asset Retirement Obligations

We have obligations to remove tangible equipment and restore locations at the end of the natural gas production operations. Estimating the future restoration and removal costs, or asset retirement obligations, is difficult and requires management to make estimates and judgments, because most of the obligations are many years in the future, and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.

Inherent in the calculation of the present value of our asset retirement obligations (“ARO”) are numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the natural gas and oil property balance. Increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense in the Consolidated Statements of Operations.

43

Impact of Recently Issued Accounting Pronouncements.

Effective January 1, 2011, the Company adopted the new guidance requiring that purchases, sales, issuances, and settlements in the rollforward activity in Level 3 measurements be disclosed.  The adoption had no impact on the Company’s financial position, results of operations, or cash flows.  See Note 11 to the consolidated financial statements.

44

Item 8.    Financial Statements and Supplementary Data.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of Carbon Natural Gas

We have audited the accompanying consolidated balance sheets of Carbon Natural Gas Company and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Carbon Natural Gas Company and subsidiaries as of December 31, 2011 and 2010, and the consolidated results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

	/s/ Ehrhardt Keefe Steiner & Hottman PC
Denver, Colorado March 30, 2012

45

CARBON NATURAL GAS COMPANY

Consolidated Balance Sheets

(In Thousands)

	December 31, 2011			December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents	$	473		$	845
Accounts receivable:
Revenue	1,815			753
Joint interest billings and other	713			258
Firm transportation contract obligations (note 13)	1,019			—
Due from related parties (note 15)	228			—
Prepaid expense, deposits and other current assets	85			85
Deferred offering costs	—			169
Derivative assets	308			171
Total current assets	4,641			2,281
Property and equipment, at cost (note 5)
Oil and gas properties, full cost method of accounting:
Proved, net	48,890			21,414
Unevaluated	1,369			2,164
Other property and equipment, net	287			81
	50,546			23,659
Investments in affiliates (note 6)	1,126			583
Other long-term assets	1,869			463
Total assets	$	58,182		$	26,986
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	5,856		$	1,632
Firm transportation contract obligations (note 13)	2,681			—
	8,537			1,632
Non-current liabilities:
Due to related parties (note 15)	—			3,073
Asset retirement obligation (note 2)	2,149			352
Firm transportation contract obligations (note 13)	4,096			—
Notes payable (note 7)	8,758			3,116
Total non-current liabilities	15,003			6,541
Commitments (note 13)
Stockholders’ equity:
Preferred stock, $0.01 par value; authorized 1,000,000 shares, no shares issued and outstanding at December 31, 2011 and 2010	—			—
Common stock, $0.01 par value; authorized 200,000,000 shares, 114,185,405 and 47,903,442 shares issued and 114,185,405 and 47,163,079 shares outstanding at December 31, 2011 and 2010, respectively	1,142			479
Additional paid-in capital	53,922			27,701
Non-controlling interests	4,884			638
Treasury stock, at cost	—			(694		)
Accumulated deficit	(25,306		)	(9,311		)
Total stockholders’ equity	34,642			18,813
Total liabilities and stockholders’ equity	$	58,182		$	26,986

See Notes to Consolidated Financial Statements.

46

CARBON NATURAL GAS COMPANY

Consolidated Statements of Operations

(In Thousands, except per share amounts)

	Year Ended  December 31, 2011			Year Ended  December 31, 2010
Revenue:
Oil and gas	$	9,018		$	4,880
Commodity derivative gain	459			692
Other income	226			286
Total revenue	9,703			5,858
Expenses:
Lease operating expenses	1,932			1,053
Transportation costs	1,242			444
Production and property taxes	684			430
General and administrative	4,638			3,021
Depreciation, depletion and amortization	2,664			1,540
Accretion of asset retirement obligations	95			18
Impairment of oil and gas properties	15,769			—
Total expenses	27,024			6,506
Operating loss	(17,321		)	(648		)
Other income and (expense):
Interest income	1			38
Interest expense	(483		)	(352		)
Other expenses	(13		)	—
Equity investment income	32			23
Gain on sale of oil and gas properties	—			10,104
Total other (expense) and income	(463		)	9,813
(Loss) income before income taxes	(17,784		)	9,165
Income taxes:
Provision for income taxes expense (benefit)	(161		)	5,404
Net (loss) income before non-controlling interests	(17,623		)	3,761
Net loss (income) attributable to non-controlling interests	1,628			(941		)
Net (loss) income attributable to controlling interest	$	(15,995	)	$	2,820
Net (loss) income per common share:
Basic	$	(0.20	)	$	0.06
Diluted	$	(0.20	)	$	0.06
Weighted average common shares outstanding (in thousands):
Basic	78,133			45,947
Diluted	78,133			48,223

See notes to Consolidated Financial Statements.

47

CARBON NATURAL GAS COMPANY

Consolidated Statements of Stockholders’ Equity

(In Thousands)

												Share
						Additional			Non-			Purchase											Total
	Common Stock					Paid-in			Controlling			Promissory			Treasury Stock					Accumulated			Stockholders’
	Shares		Amount			Capital			Interests			Note			Shares		Amount			Deficit			Equity
Balances, December 31, 2009	47,903		$	479		$	27,701		$	848		$	(655	)	—		$	—		$	(12,131	)	$	16,242
Interest on promissory note	—		—			—			—			(39		)	—		—			—			(39		)
Non-controlling interests:
Contributions	—		—			—			4						—		—			—			4
Distributions	—		—			—			(1,155		)				—		—			—			(1,155		)
Shares surrendered in settlement of promissory note	—		—			—			—			694			(740	)	(694		)	—			—
Net income	—		—			—			941						—		—			2,820			3,761
Balances, December 31, 2010	47,903		479			27,701			638			—			(740	)	(694		)	(9,311		)	18,813
Purchase treasury stock	—		—			—			—			—			(163	)	(153		)	—			(153		)
Retire treasury stock	(903	)	(9		)	(838		)	—			—			903		847			—			—
Reverse merger with St. Lawrence Seaway Corp.	519		5			(21		)	—			—			—		—			—			(16		)
Issuance of common stock, net of offering costs of $2.2 million	44,444		445			17,302			—			—			—		—			—			17,747
Issuance of Series A preferred stock	—		—			10,000			—			—			—		—			—			10,000
Series A preferred stock converted to common stock	22,222		222			(222		)	—			—			—		—			—			—
Non-controlling interest:
INGC acquisition	—		—			—			6,044			—			—		—			—			6,044
Distributions	—		—			—			(170		)	—			—		—			—			(170		)
Net loss	—		—			—			(1,628		)	—			—		—			(15,995		)	(17,623		)
Balances, December 31, 2011	114,185		$	1,142		$	53,922		$	4,884		$	—		—		$	—		$	(25,306	)	$	34,642

See Notes to Consolidated Financial Statements.

48

CARBON NATURAL GAS COMPANY

Consolidated Statements of Cash Flows

(In Thousands)

	Year Ended December 31, 2011			Year Ended December 31, 2010
Cash flows from operating activities:
Net (loss) income	$	(17,623	)	$	3,761
Items not involving cash:
Depreciation, depletion and amortization	2,664			1,540
Accretion of asset retirement obligations	95			18
Gain on sale of oil and gas properties	—			(10,104		)
Impairment of oil and gas properties	15,769			—
Deferred tax benefit	—			4,784
Unrealized derivative gain	(138		)	(294		)
Equity investment income	(32		)	(23		)
Other	13			—
Net change in:
Accounts receivable	(1,026		)	180
Prepaid expenses, deposits and other current assets	—			2
Accounts payable, accrued liabilities and firm transportation contracts	918			(112		)
Due to/from related parties	(3,301		)	(2,431		)
Net cash used in operating activities	(2,661		)	(2,679		)
Cash flows from investing activities:
Development of properties and equipment	(4,015		)	(3,068		)
Cash paid for acquired properties	(27,058		)	(1,806		)
Proceeds from disposition of assets	—			31,203
Equity method investment	(48		)	(560		)
Other long-term assets	150			(202		)
Net cash (used in) provided by investing activities	(30,971		)	25,567
Cash flows from financing activities:
Common stock and preferred stock issued	30,000			—
Offering costs	(2,059		)	(169		)
Issue of non-controlling interests in subsidiary	—			4
Treasury share purchase	(153		)	—
Proceeds from notes payable	12,442			2,622
Payments on notes payable	(6,800		)	(23,553		)
Distribution to non-controlling interests	(170		)	(1,155		)
Net cash provided by (used in) financing activities	33,260			(22,251		)
Net (decrease) increase in cash and cash equivalents	(372		)	637
Cash and cash equivalents, beginning of period	845			208
Cash and cash equivalents, end of period	$	473		$	845

See Note 16  —  Supplemental Cash Flow Disclosure

See Notes to Consolidated Financial Statements.

49

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 oil and 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 Corporation might result in market confusion regarding the Company’s current planned operations and business objectives.  The Company believed the name “Carbon Natural Gas Company” was more descriptive of the business operations in which the Company engages.  This action was implemented by filing an Amended and Restated Certificate of Incorporation with the State of Delaware which 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

Accounting policies used by the Company reflect industry practices and conform to accounting principles generally accepted in the United States of America.  The more significant of such accounting policies are briefly discussed below.

Principles of Consolidation

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

For partnerships where the Company has a controlling interest, the partnerships are consolidated.  In these instances, the Company reflects the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on its consolidated combined statements of operations and also reflects the non-controlling ownership interest in the net assets of the partnerships as non-controlling interests within stockholders’ equity on its consolidated balance sheets.  All significant intercompany accounts and transactions have been eliminated.

In accordance with established practice in the oil and gas industry, the Company’s consolidated financial statements also include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the oil and gas partnerships in which the Company has a non-controlling interest. The Company is currently consolidating 42 partnerships.

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.

Cash and Cash Equivalents

Cash and cash equivalents in excess of daily requirements have been generally invested in money market accounts, certificates of deposits and other cash equivalents with maturities of three months or less.  Such investments are deemed to be cash equivalents for purposes of the consolidated financial statements.  The carrying amount of cash equivalents approximates fair value because of the short maturity and high credit quality of these investments.

Accounts Receivable

Revenue producing activities are conducted primarily in Illinois, Kentucky, Ohio and West Virginia.  The Company grants credit to all qualified customers, which potentially subjects the Company to credit risk resulting from, among other factors, adverse changes in the industries in which the Company operates and the financial condition of its customers.  The Company continuously monitors collections and payments from its customers and maintains an allowance for doubtful accounts based upon its historical experience and any specific customer collection issues that it has identified.  At December 31, 2011 and 2010, the Company had not identified any collection issues and as a consequence no allowance for doubtful accounts was provided for on those dates.  During 2011 and 2010, the Company’s primary purchaser of its natural gas accounted for 23% and 47%, respectively of the Company’s natural gas revenues and represented approximately 18% and 45% of the Company’s natural gas revenues receivable at December 31, 2011 and 2010, respectively.  There are a number of purchasers in the areas that the Company sells its production and accordingly, management does not believe that changing its primary purchaser, as the Company elected to do in 2010, or a loss of any other single purchaser would materially impact the Company’s business.

50

Note 2 — Summary of Significant Accounting Policies (continued)

Accounting for Oil and Gas Operations

The Company uses the full cost method of accounting for oil and gas properties.  Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized.  Overhead costs incurred that are directly identified with acquisition, exploration and development activities undertaken by the Company for its own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized.

Unproved properties are excluded from amortized capitalized costs until it is determined whether or not proved reserves can be assigned to such properties.  The Company assesses its unproved properties for impairment at least annually.  Significant unproved properties are assessed individually.

Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil.  Depletion is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.

No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves.  All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.

The Company performs a ceiling test quarterly.  The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10.  The ceiling test is not a fair value based measurement. Rather, it is a standardized mathematical calculation.  The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties.  Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down (impairment) would be recognized to the extent of the excess capitalized costs.  Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds the capitalized costs in future periods.

As of December 31, 2011, the Company’s full cost pool exceeded the ceiling limitation, based on average oil prices of $96.19 per barrel and average natural gas prices of $4.12 per Mcf.  For the year ended December 31, 2011, the Company recognized a ceiling test impairment for the first, second, third and fourth quarters of $7.3 million, $1.1 million, $3.8 million and $3.6 million, respectively, for a total impairment of $15.8 million for 2011. Further declines in oil and natural gas prices could result in additional impairments of our oil and gas properties in future periods.  The Company did not recognize any non-cash impairment charges related to its oil and gas properties in the year ended December 31, 2010.

Other Property and Equipment

Other property and equipment are recorded at cost upon acquisition.  Depreciation of other property and equipment over their estimated useful lives is provided for using the straight-line method over three to seven years.

Long-Lived Assets

The Company reviews its long-lived assets other than oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered.  The Company looks primarily to the estimated undiscounted future cash flows in its assessment of whether or not long-lived assets have been impaired.

Investments in Affiliates

Investments in non-consolidated affiliates are accounted for under either the equity or cost method of accounting as appropriate.  The cost method of accounting is used for investments in affiliates in which the Company has less than a 20% of the voting interests of the affiliate and does not have significant influence.  The investment in the affiliate, accounted for using the costs method of accounting, is recorded at cost and an impairment assessment of the investment is made annually to determine if a decline in the fair value of the investment, other than temporary, has occurred.  A permanent impairment is recognized if a decline in the fair value occurs.  If the Company holds between 20% and 50% of the voting interest and exercises significant influence or control, the equity method of accounting is used to account for the investment.  The Company’s investment in an affiliate, that is accounted for

51

Note 2 — Summary of Significant Accounting Policies (continued)

using the equity method of accounting, would increase or decrease by the Company’s share of the affiliate’s profits or losses and such profits or losses would be recognized in the Company’s Statements of Operations.

Asset Retirement Obligations

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

The estimated ARO liability is based on estimated economic lives, estimates as to the cost to plug and 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 years ended December 31, 2011 and 2010.

	Year Ended December 31,
In thousands	2011		2010
Balance at beginning of year	$	352	$	749
Accretion expense	95		18
Additions during period	121		36
Additions assumed with acquired properties	1,581		62
Property dispositions	—		(513		)
Balance at end of year	$	2,149	$	352

Financial Instruments

The Company’s financial instruments include cash and cash equivalents, accounts receivables, accounts payables, accrued liabilities, derivative instruments and its credit facility.  The carrying value of cash and cash equivalents, accounts receivables, payables and accrued liabilities are considered to be representative of their fair value, due to the short maturity of these instruments.  The Company’s derivative instruments are recorded at fair value, as discussed below and in Note 11.  The carrying amount of the Company’s credit facility approximated fair value since borrowings bear interest at variable rates.

Commodity Derivative Instruments

The Company enters into commodity derivative contracts to manage its exposure to natural gas and oil price volatility with an objective to achieve more predictable cash flows.  Commodity derivative contracts may take the form of futures contracts, swaps or options.  The Company has elected not to designate its derivatives as cash flow hedges.  All derivatives are initially and subsequently measured at estimated fair value and recorded as assets or liabilities on the consolidated balance sheets and the changes in fair value are recognized as gains or losses in revenues in the consolidated statements of operations.

Income Taxes

Carbon accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases, as well as the future tax consequences attributable to the future utilization of existing tax net operating losses and other types of carryforwards.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled.  The

52

Note 2 — Summary of Significant Accounting Policies (continued)

effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

In assessing the need for a valuation allowance on our deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize net operating loss and credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both negative and positive. Negative evidence considered by management primarily included a recent history of book losses which were driven entirely from ceiling test write-downs, which are not fair value based measurements. Positive evidence considered by management included forecasted book income over a reasonable period of time and the utilization of significant net operating loss (“NOL”) carryforwards in 2010 due primarily to a substantial tax gain associated with the disposition of the Company’s Pennsylvania assets.  See Note 8.

Stock - Based Compensation

Compensation cost is measured at the grant date based on the fair value of the awards and is recognized on a straight-line basis over the requisite service period (usually the vesting period).

Revenue Recognition

The Company accounts for natural gas sales using the entitlements method.  The Company accounts for oil sales when title to the product is transferred. Under the entitlements method, revenue is recorded based upon the Company’s share of volumes sold, regardless of whether the Company has taken its proportionate share of volumes produced.  The Company records a receivable or payable to the extent it receives less or more than its proportionate share of the related revenue.  Gas imbalances at December 31, 2011 and 2010 were not significant.

Earnings Per Common Share

Basic earnings (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders 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 as adjusted for the merger described above.  The number of common shares outstanding from the merger date to December 31, 2011 is the actual number of common shares of the Company outstanding during that period.

At December 31, 2011, the Company had common stock equivalents of 2,020,374 which were excluded from the calculation of diluted loss per share as the effect would be anti-dilutive.  At December 31, 2010, the Company had common stock equivalents of 2,275,397 which were included in the calculation of diluted income per share.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and expenses and disclosure of contingent assets and liabilities.  Significant items subject to such estimates and assumptions include the carrying value of oil and gas properties, the estimate of proved oil and gas reserve volumes and the related depletion and present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, determining the amounts recorded for deferred income taxes, stock-based compensation, fair value of derivative instruments and asset retirement obligations.  Actual results could differ from those estimates and assumptions used.

53

Note 2 — Summary of Significant Accounting Policies (continued)

Impact of Recently Issued Accounting Standards

Effective January 1, 2011, the Company adopted the new guidance requiring that purchases, sales, issuances, and settlements in the rollforward activity in Level 3 measurements be disclosed.  The adoption had no impact on the Company’s financial position, results of operations, or cash flows.  See Note 11.

Note 3 — Reverse Merger

On February 14, 2011, pursuant to an Agreement and Plan of Merger (“Merger Agreement”) by and among SLSC, St. Lawrence Merger Sub, Inc. (“Merger Co”) and Nytis USA, Merger Co merged with and into Nytis USA with Nytis USA remaining as the surviving subsidiary of SLSC.  Per the terms of the Merger Agreement, in exchange for all the outstanding common shares of Nytis USA, SLSC issued 47,000,003 shares of common stock of SLSC (restricted under SEC Rule 144) which represented an exchange ratio of approximately 1,631 shares of SLSC for each share of Nytis USA.

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

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

Note 4 — Dispositions and Acquisitions

ING Asset Acquisition

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

The Company acquired these assets to obtain proved developed producing reserves that were proximate and complimentary to the Company’s then current production and reserve base.  The ING Assets 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).

The Company expensed approximately $459,000 of transaction costs that were included in general and administrative expenses on the accompanying consolidated statements of operations during the year ended December 31, 2011.

Total purchase consideration is still subject to final working capital adjustments which are currently being negotiated.  At this time, the Company does not believe there will be significant adjustments to the amounts recorded.

54

Note 4 — Dispositions and Acquisitions (continued)

The following table summarizes the consideration paid to ING and the estimated fair value of the assets acquired and liabilities assumed.  See Note 11 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	$	37,992
Asset retirement obligations	(1,387		)
Accounts receivable	1,007
Firm transportation obligations receivable:
Current	1,502
Long-term	2,061
Accounts and revenue payables assumed	(631		)
Firm transportation obligations assumed (see Note 13)	(8,192		)
Non-controlling equity interests	(6,044		)
Total identifiable net assets	$	25,858

ING Asset Acquisition Pro Forma

Below are consolidated results of operations for the years ended December 31, 2011 and 2010 as though the ING acquisition made during 2011 had been completed as of January 1, 2010.  The ING acquisition closed June 29, 2011 and accordingly, the Company’s consolidated statements of operations for the year ended December 31, 2011 includes the results of operations for the six months ended December 31, 2011 of the ING properties acquired, including $3.8 million of revenue.

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

	Unaudited Pro Forma Consolidated Results
	For Years Ended December 31,
(in thousands, except share data)	2011			2010
Revenue	$	14,001		$	14,681
Net (loss) income before non-controlling interests	(13,781		)	9,133
Net loss (income) attributable to non-controlling interests	1,230			(1,936		)
Net (loss) income attributable to controlling interests	(12,551		)	7,197
Net (loss) income per share (basic)	(0.01		)	0.06
Net (loss) income per share (diluted)	(0.01		)	0.06

Alerion Drilling I, LLC Asset Acquisition

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

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

55

Note 4 — Dispositions and Acquisitions (continued)

The purchase of Alerion Partnership Assets 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).

The following table summarizes the consideration paid to the sellers and the fair value of the assets acquired and liabilities assumed.

	(in thousands)
Consideration paid to sellers:
Cash consideration	$	1,200
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed properties	$	1,394
Asset retirement obligations	(194		)
Total identifiable net assets	$	1,200

Other Acquisition and Disposition Activity

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 $30.2 million, net of normal adjustments and transaction fees.  Proceeds from this sale were used to reduce outstanding borrowings due under the Company’s credit facility (see Note 7) and accounts payable due Nytis Exploration Company (“NEC”) (see Note 15), to pay resultant taxes due to the sale of these assets and distribute funds to members of Nytis Pennsylvania.  Because the sale of these assets significantly altered the relationship between capitalized costs and proved reserves, the Company recorded a gain of approximately $10.1 million.

In September 2010, the Company sold all of its interest in undeveloped acreage located in Webster County, West Virginia for approximately $770,000.

During 2010, the Company purchased a 17.5% interest in Sullivan Energy Ventures, LLC (“Sullivan”) for approximately $415,000. As of December 31, 2011, Sullivan’s investment consists of a 50% interest in Sunrise Energy, LLC (“Sunrise”).  Sunrise’s assets are comprised principally of a gathering system which moves production from the Company’s producing gas wells in a specific area to a major delivery point to be transported to market, unevaluated properties and producing wells.  As of December 31, 2011, the Company accounts for this investment using the cost method of accounting (see Note 2).

In June 2010, the Company acquired an interest in 19 producing wells located Boyd and Greenup Counties, Kentucky for a cash purchase price of approximately $1.3 million which qualifies as a business combination.  The following table summarizes the consideration paid to the sellers and the fair value of the assets acquired and liabilities assumed in the $1.3 million acquisition.

	(in thousands)
Consideration paid to sellers:
Cash consideration	$	1,300
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed and undeveloped properties	$	1,362
Asset retirement obligations	(62		)
Total identifiable net assets	$	1,300

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Note 5 — Property and Equipment

Net property and equipment at December 31, 2011 and 2010 consists of the following:

	As of December 31,
(in thousands)	2011			2010
Oil and gas properties:
Proved oil and gas properties	$	89,392		$	43,535
Unproved properties not subject to depletion	1,369			2,164
Accumulated depreciation, depletion, amortization and impairment	(40,502		)	(22,121		)
Net oil and gas properties	50,259			23,578
Furniture and fixtures, computer hardware and software, and other equipment	728			488
Accumulated depreciation and amortization	(441		)	(407		)
Net other property and equipment	287			81
Total net property and equipment	$	50,546		$	23,659

The Company had approximately $1.4 million and $2.2 million, at December 31, 2011 and 2010, respectively, of unproved oil and gas properties not subject to depletion.  At December 31, 2011 and 2010, the Company’s unproved properties consist principally of leasehold acquisition costs in the following areas:

	As of December 31,
(in thousands)	2011		2010
Illinois Basin:
Indiana	$	636	$	945
Illinois	243		470
Appalachian Basin:
Kentucky	412		685
Ohio	75		61
Tennessee	2		2
West Virginia	1		1
Total unproved properties not subject to depletion	$	1,369	$	2,164

During 2011 and 2010, approximately $1.1 million and $846,000 of expiring acreage, respectively, was reclassified into proved property (see Note 2) and, in addition in 2010,  unevaluated leasehold costs of approximately $2.2 million associated with leaseholds in Pennsylvania were sold (see Note 4).  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.  These costs do not relate to any individually significant projects. The excluded properties are assessed for impairment at least annually.  The Company believes that the majority of the unproved costs will become subject to depletion within the next five years, by proving up reserves relating to the acreage through development activities, by impairing the acreage that will expire before the property can be explored or developed, or by making decisions that further development activity will not occur.

During the years ended December 31, 2011 and 2010, overhead applicable to acquisition, development and exploration activities in the amounts of approximately $513,000 and $436,000, respectively, was capitalized to oil and gas properties.

Depletion expense related to oil and gas properties for the years ended December 31, 2011 and 2010 was approximately $2.7 million, or $1.39 per equivalent Mcfe, and $1.5 million, or $1.47 per equivalent Mcfe, respectively.  Oil and natural gas property ceiling test impairments of approximately $15.8 million were recognized for the year ended December 31, 2011.  Depreciation and amortization expense related to furniture and fixtures, computer hardware and software and other equipment for the years ended December 31, 2011 and 2010 was approximately $52,000 and $50,000, respectively.

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Note 6 — Equity Method Investment

During 2010, the Company invested $560,000 for a 50% interest in Crawford County Gas Gathering Company, LLC (CCGGC).  CCGGC owns and operates pipelines and related gathering and treating facilities that it acquired in 2010.  The Company’s gas production located in Illinois is gathered and transported on CCGGC’s gathering facilities.  The Company’s investment in CCGGC is accounted for under the equity method of accounting, and its share of the income or loss is recognized.  During 2011 and 2010, the Company recorded approximately $32,000 and $23,000, respectively, of equity method income related to this investment.

In the fourth quarter of 2010, the Company acquired a 17.5% ownership in Sullivan Energy Ventures LLC.  At that time, the Company determined that it had the ability to significantly influence the operating decisions of Sullivan and accounted for its ownership in Sullivan by recording the Company’s pro-rata share of Sullivan’s financial results.  During the second quarter of 2011, it became evident that the Company 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.

Note 7 — Bank Credit Facility

On April 21 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.  As a result of the amendments in April and June 2011, 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 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 and Alerion Drilling (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 December 31, 2011, the borrowing base was $20 million.  The borrowing base is redetermined semi-annually, and the available borrowing amount could be increased or decreased as a result of such redeterminations.  Under certain circumstances the lender may request an interim redetermination.  The facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base.  Interest rates are based on either an Alternate Base Rate or LIBOR.  The portion of the loan based on an “Alternate Base Rate” is determined by the rate per annum equal to 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 plus between 2.5% and LIBOR plus 3.25% for each LIBOR tranche. For all debt outstanding regardless if the loan is based on the Alternative Base Rate or LIBOR, there is a minimum floor of 4.5% per annum. 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 million.

At December 31, 2011, there were approximately $8.8 million in outstanding borrowings and approximately $11.2 million of additional borrowing capacity available under the credit facility.  The Company’s effective borrowing rate at December 31, 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 (including borrowing base capacity) to current liabilities as defined) 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 December 31, 2011.

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Note 8 — Income Taxes

The provision for income taxes for the years ended December 31, 2011 and 2010 consists of the following:

(in thousands)	Year Ended December 31, 2011			Year Ended December 31, 2010
Current income tax (benefit) expense	$	(161	)	$	620
Deferred income tax (benefit) expense	(6,172		)	2,699
Change in valuation allowance	6,172			2,085
Total income tax (benefit) expense	$	(161	)	$	5,404

The effective income tax rate for the years ended December 31, 2011 and 2010 differed from the statutory U.S. federal income tax rate as follows:

	Year Ended December 31, 2011		Year Ended December 31, 2010
Federal income tax rate	(35.0	)%	35.0	%
State income taxes, net of federal benefit	(3.9	)	6.7
Percentage depletion in excess of basis	(0.7	)	(0.8	)
Non-controlling interest in consolidated partnerships	3.0		—
Rate changes of prior year deferreds	1.9		—
Increase in valuation allowance and other	34.7		18.1
Total income tax (benefit)	0.0	%	59.0	%

59

Note 8 — Income Taxes (continued)

The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities at December 31, 2011 and 2010 are presented below:

(in thousands)	December 31, 2011			December 31, 2010
Deferred tax assets
Net operating loss carryforwards	$	3,992		$	1,627
Depletion carryforwards	1,046			1,200
Accrual and other	81			62
Asset retirement obligations	835			146
Property, plant and equipment	4,706			1,400
Total deferred tax assets	10,660			4,435
Deferred tax liability
Derivatives	(75		)	(21		)
Less valuation allowance	(10,585		)	(4,414		)
Net deferred tax asset	$	—		$	—

The Company has net operating losses (“NOL”) of approximately $10.2 million available to reduce future years’ federal taxable income.  The federal net operating losses expire in 2031.  The Company has NOL of approximately $11.4 million available to reduce future years’ state taxable income.  These state NOL will expire in the future based upon each jurisdiction’s specific law surrounding NOL carryforwards.  Tax returns are subject to audit by various taxation authorities.  The results of any audits will be accounted for in the period in which they are determined.

The Company believes that the tax positions taken in the Company’s tax returns satisfy the more-likely-than-not threshold for benefit recognition.  Furthermore, the Company believes it has appropriately addressed material book-tax differences.  Carbon is confident that the amounts claimed (or expected to be claimed) in the tax returns reflect the largest amount of such benefits that are greater than fifty percent likely of being realized upon ultimate settlement.  Accordingly, no liabilities have been recorded by the Company.  Any potential adjustments for uncertain tax positions would be a reclassification between the deferred tax asset related to the Company’s NOL and another deferred tax asset.  No penalty or interest would be recorded as the Company has not been in a taxable income position prior to 2010 nor is it in a taxable income position in 2011.

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 would automatically convert into 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

60

Note 9 — Stockholders’ Equity (continued)

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.

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 were converted into 22,222,222 shares of Carbon’s $0.01 par value per share common stock.

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 they incurred of approximately $248,000, as well as other fees and expenses of approximately $505,000 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 $6.8 million of the Company’s bank credit facility.

As of December 31, 2011, the authorized capital stock of Carbon was 201,000,000 shares, comprised of 200,000,000 shares of common stock and 1,000,000 shares of preferred stock.

During the years ended December 31, 2011 and 2010, no stock options, warrants or restricted stock awards 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 December 31, 2011, the Company has 269,075 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.

Stock Option Plan

The following table reflects the outstanding equity awards as of December 31, 2011 and 2010.  Each of the following awards were made by Nytis USA prior to the merger and were assumed as a result of the merger.  The number of shares and the option exercise price have been adjusted in line with the exchange ratio of Nytis USA shares for Carbon shares in the merger.

	Number of Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)
Outstanding — January 1, 2010	342,459		$	1,047	6.43
Outstanding — December 31, 2010	342,459		.64		5.43
Forfeited	(73,384	)	.65
Outstanding — December 31, 2011	269,075		.63		4.40
Exercisable — December 31, 2011	269,075		$	.63	4.40

61

Note 9 — Stockholders’ Equity (continued)

Warrants

Prior to January 1, 2006, the Company granted 2,446,133 warrants to an officer of the Company.  Any shares to be issued upon exercise of the warrants would be from newly issued shares.  Utilizing the minimum valuation method under the Black-Scholes option price model, the Company determined that the fair value of the warrants at the date of grant was nil.  Each warrant enabled the holder to purchase one share of common stock of the Company, at an initial exercise price of $0.61 per share of common stock until expiry on June 1, 2015.  The initial warrant exercise price of $0.61 per share of common stock was to increase annually at 6% starting June 1, 2006 and the exercise price for each of the warrants at December 31, 2010 was $0.85.  Pursuant to the merger, the exercise price was fixed at $0.85.  Inclusive of 250,000 warrants granted by SLSC prior to the merger with an exercise price of $1.00 which expire on August 31, 2017, the Company has 2,696,133 warrants outstanding at December 31, 2011.  The number of warrants have been adjusted in line with the exchange ratio of Nytis USA shares for Carbon shares in the merger.

Restricted Stock Plan

Under Nytis USA’s restricted stock plan, participants were granted stock without cost to the participant.

There were 1,956,912 shares of restricted stock outstanding at December 31, 2011 and 2010.  There was no activity with respect to the Nytis USA’s restricted stock plan during 2011 or 2010.

The Company continues to account for grants made in 2005 using variable plan accounting.  The Company accounts for grants made after 2005 at their intrinsic value, remeasured at each reporting date through the date of vesting.  The final measurement will be the intrinsic value of the instrument at the vesting date.  The accounting for grants issued subsequent to 2005 is the same because the final measurement of compensation cost will be based on the number of shares of restricted stock that ultimately vest using the market price at the date of vesting (i.e. a date performance criterion is met).  At December 31, 2011 and 2010, the Company estimated that none of the shares of restricted stock issued would vest and accordingly, no compensation cost has been recorded.

Stock Incentive Plan

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

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

There were no awards granted under the 2011 Plan as of December 31, 2011.

Share Promissory Note

On May 19, 2005, Nytis USA received a promissory note totaling approximately $500,000 due from a corporation controlled by an officer of the Company in exchange for the issuance of 815,378 shares of common stock issued to the corporation.  The promissory note bore interest at a rate of 6% per annum compounded annually and was secured under a stock pledge agreement by 815,378 shares of common stock of the Company and by a personal guarantee by the officer.  The promissory note, including accrued interest, was payable on the earlier of (i) June 1, 2012 or (ii) the date upon which Nytis USA or any successor to the Company registers any class of its securities under Section 12 of the Securities Exchange Act of 1934 (the 1934 Act), was required to file periodic reports under Section 15(d) of the 1934 Act, or file a registration statement under the Securities Act of 1933, as amended.

On December 31, 2010, the corporation controlled by an officer of the Nytis USA surrendered 740,363 shares of Nytis USA’s common stock in full settlement of the promissory note totaling approximately $694,000 including accrued interest.

Restricted Membership Plan

On March 16, 2006, a restricted membership interest plan (the Plan) was approved for Nytis LLC.  The objective of the Plan was to provide key employees equity ownership in Nytis LLC.  The Plan provided for vesting and forfeiture provisions based on (i) Nytis USA achieving a target internal rate of return upon certain changes in control with regard to the Company, Nytis LLC, or substantially all of the assets of Nytis USA and (ii) the employee’s continued employment.  In 2008 the Plan was amended so that the interests available for grant under the Plan would not exceed five percent of the membership interest in Nytis LLC.  Pursuant to the merger, all the restricted membership interests were redeemed in February 2011 for $300,000 and recorded as a general and

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Note 9 — Stockholders’ Equity (continued)

administrative expense and the plan was terminated. The following table summarizes certain information with respect to the Plan for the years ended December 31, 2011 and 2010.

	Percentage Outstanding
Outstanding at January 1, 2010	4.90	%
Forfeited	(.40	)
Outstanding at December 31, 2010	4.50
Redeemed	(4.50	)
Outstanding at December 31, 2011	0	%

Note 10 — Accounts Payable and Accrued Liabilities

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

(in thousands)	December 31, 2011		December 31, 2010
Accounts payable	$	2,789	$	342
Oil and gas revenue payable to oil and gas property owners	964		326
Production taxes payable	43		35
Accrued drilling costs	190		113
Accrued lease operating costs	582		98
Accrued ad valorem taxes	396		305
Accrued general and administrative expenses	533		169
Accrued other	359		244
Total accounts payable and accrued liabilities	$	5,856	$	1,632

Note 11 — Fair Value Measurements

Authoritative guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date.  The guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available.  Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company.  Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances.  The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

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

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

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

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Note 11 — Fair Value Measurements (continued)

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.  The Company’s policy is to recognize transfers in/and or out of 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 December 31, 2011 and 2010 by level within the fair value hierarchy:

	Fair Value Measurements Using
(in thousands)	Level 1		Level 2		Level 3		Total
December 31, 2011
Assets:
Commodity derivatives	$	—	$	308	$	—	$	308
December 31, 2010
Assets:
Commodity derivatives	$	—	$	171	$	—	$	171

As of December 31, 2011, the Company’s commodity derivative financial instruments are comprised of two natural gas swap agreements and one oil swap agreement.  As of December 31, 2010, the Company’s commodity derivative financial instruments were 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 flows model.  The valuation models require a variety of inputs, including contractual terms, published forward prices, volatilities for options, and discount rates, as appropriate.  The Company’s estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, the Company’s credit worthiness and the time value of money.  The consideration of these factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view.  All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s derivative instruments are included within the Level 2 fair value hierarchy. The counterparty in all of the Company’s commodity derivative financial instruments is the lender in the Company’s bank credit facility.

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

The 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 year ended December 31, 2011 and 2010, the Company recorded asset retirement obligations for additions of approximately $1.7 million and $98,000, 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 producing 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.

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Note 12 — Physical Delivery Contracts and Commodity Derivatives

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

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 December 31, 2011, other than the above mentioned contracts, the Company’s other gas sales contracts approximate index prices.

The Company’s swap agreements as of December 31, 2011 are summarized in the table below:

Agreement	Remaining		Fixed Price		Floating Price
Type	Term	Quantity	Counterparty Payer		Nytis Payer
Swap	1/12 – 4/12	10,000 MMBtu/month	$	5.25 /MMBtu	(a)
Swap	1/12 - 12/12	10,000 MMBtu/month	$	5.07/ MMBtu	(a)
Swap	1/12 - 6/12	1,000 Bbl/month	$	99.30/Bbl	(b)

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

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

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

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

	As of December 31,
(in thousands)	2011		2010
Commodity derivative contracts:
Current assets	$	308	$	171

The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the years ended December 31, 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.

	For the year ended December 31,
(in thousands)	2011		2010
Commodity derivative contracts:
Realized gains	$	321	$	398
Unrealized gains (losses)	138		294
Total realized and unrealized gains, net	$	459	$	692

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

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

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

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Note 13 — Commitments

The Company has entered into employment agreements with certain executives and officers of the Company.  The initial term of the agreements generally range from one to two years and provide for renewal provisions in one year increments thereafter.  The agreements provide for, among other items, severance and continuation of benefit payments upon termination of employment or certain change of control events.

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 December 31, 2011 are (i) for 2012 through 2013; approximately 7,700 dekatherms per day capacity with demand charges ranging between $0.22 and $1.40 per dekatherm, (ii) for 2014 through May 2015; 3,450 dekatherms per day with demand charges ranging between $0.22 and $0.65 and (iii) for June 2015 through 2017; 2,300 dekatherms per day with demand charges of $0.65 per dekatherm.  A liability of approximately $8.2 million related to firm transportation contracts assumed in the ING Asset acquisition (see Note 4) was recorded of which $6.8 million, which represents the remaining commitment, is reflected on the Company’s consolidated balance sheets as of December 31, 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 December 31, 2011 are (i) for 2012 through March 2013; 1,300 dekatherms per day with demand charges ranging from $0.22 to $0.80 per dekatherm and (ii) 1,000 dekatherms per day with demand charges of $0.22 from April 2013 through April 2036.

Note 14 — Retirement Savings Plan

The Company outsources certain payroll and human resource functions to an administrative company.  In conjunction with this arrangement, the Company has a 401(k) plan available to eligible employees.  The plan provides for 6% matching which vests immediately.  For the year ended December 31, 2011, the Company paid approximately $145,000 for 401(k) plan contributions and related administrative expenses.

Note 15 — Related Party Transactions

Nytis Exploration Company 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), NEC had substantially the same stockholders 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. For the years ended December 31, 2011 and 2010, NEC charged us approximately $676,000 and $1.2 million, respectively, for general and administrative expenses pursuant to this service agreement.

The Company and NEC terminated this service agreement on June 30, 2011.  Effective July 1, 2011, the parties entered into a new agreement whereby the Company will manage, direct and supervise the operations and business of 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.  For the year ended December 31, 2011, pursuant to the new service agreement, the Company charged NEC $90,000.

As of December 31, 2011, NEC and its subsidiary, Nytis Exploration Company Inc., owe us approximately $228,000.  This receivable consists primarily of charges incurred under the service agreement, short-term advances and reimbursement of other general and administrative expenses paid by Carbon on behalf of NEC and its subsidiary.  This receivable is reflected in accounts receivable on the Company’s consolidated balance sheets.

During 2011, the Company provided management services totaling approximately $214,000 to two entities in which two officers of the Company have an investment in and participate in the management of.  As of December 31, 2011, the receivable due from these two entities total $214,000.  This receivable is reflected in accounts receivable on the Company’s consolidated balance sheets.

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Note 16 — Supplemental Cash Flow Disclosure

Supplemental cash flow disclosures for the years ended December 31, 2011 and 2010 are presented below:

	For the Year Ended December 31,
(in thousands)	2011		2010
Cash paid for interest payments	$	342	$	330
Income taxes paid	$	256	$	620
Non-cash transactions:
Increase (decrease) in net asset retirement obligations	$	1,702	$	(415	)
Increase (decrease) in accounts payable and accrued liabilities included in oil and gas properties	$	1,850	$	(162	)
Increase in interest receivable on promissory note	$	—	$	39
Settlement of promissory note and surrender of shares	$	—	$	694

See Note 4 for acquisitions

Note 17 — Subsequent Events

Subsequent to December 31, 2011, the Company issued 1,450,000 restricted shares and 1,096,500 restricted performance units pursuant to the Carbon 2011 Stock Incentive Plan.

Note 18 — Supplemental Financial Data — Oil and Gas Producing Activities (unaudited)

Estimated Proved Oil and Gas Reserves

The reserve estimates as of December 31, 2011 and 2010 presented herein were made in accordance with oil and gas reserve estimation and disclosure authoritative accounting guidance.

Proved oil and gas reserves as of December 31, 2011 and 2010 were calculated based on the prices for oil and gas during the twelve month period before the reporting date, determined as an un-weighted arithmetic average of the first-day-of-the month price for each month within such period.  This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows.  Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.  The new guidance broadened the types of technologies that a company may use to establish reserve estimates and also broadened the definition of oil and gas producing activities to include the extraction of non-traditional resources, including bitumen extracted from oil sands as well as oil and gas extracted from shales.

The Company’s estimates of its net proved, net proved developed, and net proved undeveloped oil and gas reserves and changes in its net proved oil and gas reserves for 2011 and 2010 are presented in the table below.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.  Existing economic conditions include the average prices for oil and gas during the twelve month period before the reporting date of December 31, 2011 and 2010 unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.  Prices do not include the effects of commodity derivatives.  The independent petroleum engineering firm, Cawley, Gillespie & Associates, Inc. (“CGA”), evaluated and prepared independent estimated proved reserves quantities and related pre-tax future cash flows as of December 31, 2011.  To facilitate the preparation of an independent reserve study, we provided them our reserve database and related supporting technical, economic, production and ownership information.  Estimated reserves and related pre-tax future cash flows for the non-controlling interests of the consolidated partnerships included in the Company’s consolidated financial statements were based on the CGA’s estimated reserves and related pre-tax future cash flows for the specific properties in the partnerships and have been added to CGA’s reserve estimates for December 31, 2011.  (See Note 2)  Our internal petroleum engineers prepared our net proved reserve estimates and related pre-tax future cash flows in accordance with guidelines established by the SEC for December 31, 2010.

Proved developed oil and gas reserves are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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Note 18 — Supplemental Financial Data — Oil and Gas Producing Activities (unaudited) (continued)

Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

The Company’s oil and gas properties produce principally natural gas with nominal oil or natural gas liquids.

	2011						2010
			Natural						Natural
	Oil		Gas		Total		Oil		Gas		Total
	MBbls		MMcf		MMcfe		MBbls		MMcf		MMcfe
Proved reserves, beginning of year	146		54,660		55,536		—		42,411		42,411
Revisions of previous estimates	80		(24,656	)	(24,178	)	—		1,034		1,034
Extensions and discoveries	440		8,023		10,663		—		23,943		23,943
Production	(14	)	(1,797	)	(1,882	)	(2	)	(1,000	)	(1,011	)
Purchases of reserves in-place	80		26,722		27,205		148		332		1,219
Sales of reserves in-place	—		—		—		—		(12,060	)	(12,060	)
Proved reserves, end of year	732		62,952		67,344		146		54,660		55,536
Proved developed reserves at:
End of Year	411		44,103		46,572		72		17,482		17,914
Proved undeveloped reserves at:
End of Year	321		18,849		20,772		74		37,178		37,622

The estimated proved reserves for December 31, 2011 includes 4.1 Bcfe attributed to the non-controlling interests of the consolidated partnerships acquired in the ING acquisition (see Note 4).

The revisions of previous estimates in 2011 is primarily attributed to the loss of proved undeveloped natural gas locations due to marginal economics on certain locations as a result of a decline in natural gas prices and the decision by the Company to allocate proportionately more capital to oil locations in the future.  In addition, there was a reduction in natural gas reserves in certain of the Company’s locations due to updated production history information made publicly available by a third party operator in 2011 where the production in wells proximate to these locations showed that the wells were declining faster and therefore had smaller reserves than previously estimated.

Extensions and discoveries increased at December 31, 2010 due to the Company adopting a new policy of including reserves having negative discounted cash flows but positive undiscounted cash flows.  As a result, the Company included additional proved undeveloped locations totaling 18.6 Bcfe in 2010 that were not included in 2009. In addition, 2010 includes approximately 2.2 Bcfe in new or expanded horizontal proved undeveloped locations supported by reliable technology as well as the impact of a $0.40 natural gas price increase.

Aggregate Capitalized Costs

The aggregate capitalized costs relating to oil and gas producing activities at the end of each of the years indicated were as follows:

	2011			2010
	(In thousands)
Oil and gas properties
Proved oil and gas properties	$	89,392		$	43,535
Unproved properties not subject to depletion	1,369			2,164
Accumulated depreciation, depletion, amortization and impairment	(40,502		)	(22,121		)
Net oil and gas properties	$	50,259		$	23,578

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Note 18 — Supplemental Financial Data — Oil and Gas Producing Activities (unaudited) (continued)

Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities

The following costs were incurred in oil and gas property acquisition, exploration, and development activities during the years ended December 31, 2011 and 2010:

	2011		2010
	(In thousands)
Property acquisition costs:
Unevaluated properties	$	276	$	81
Proved and unproved properties and gathering facilities	27,058		1,806
Development costs	3,305		2,987
Gathering facilities	163		—
Asset retirement obligation	1,702		98
Total costs incurred	$	32,504	$	4,972

The above capital expenditures do not include non-cash acquisition activities of non-controlling interests in consolidating partnerships of approximately $6.0 million and approximately $5.1 million, net, of firm transportation contracts receivables and payables assumed in the Company’s acquisition of certain assets from ING.  See Note 4 regarding acquisitions.

The Company’s investment in unproved properties as of December 31, 2011, by the year in which such costs were incurred is set forth in the table below:

	2011		2010		2009 and Prior
	(In thousands)
Acquisition costs	$	276	$	81	$	1,012

Results of Operations from Oil and Gas Producing Activities

Results of operations from oil and gas producing activities for the years ended December 31, 2011 and 2010 are presented below:

	2011			2010
	(In thousands)
Oil and gas sales, including commodity derivative gains	$	9,477		$	5,572
Expenses:
Production expenses	3,858			1,927
Depletion expense	2,612			1,490
Ceiling test write-down of oil and gas properties	15,769			—
Accretion of asset retirement obligations	95			18
Total expenses	22,334			3,435
Results of operations from oil and gas producing activities	$	(12,857	)	$	2,137
Depletion rate per Mcfe	$	1.39		$	1.47

Standardized Measure of Discounted Future Net Cash Flows

Future oil and gas sales are calculated applying the prices used in estimating the Company’s proved oil and gas reserves to the year-end quantities of those reserves.  Future price changes were considered only to the extent provided by contractual arrangements in existence at each year-end.  Future production and development costs, which include costs related to plugging of wells, removal of facilities and equipment, and site restoration, are calculated by estimating the expenditures to be incurred in producing and developing the proved oil and gas reserves at the end of each year, based on year-end costs and assuming continuation of existing economic conditions.  Future income tax expenses are computed by applying the appropriate year-end

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Note 18 — Supplemental Financial Data — Oil and Gas Producing Activities (unaudited) (continued)

statutory tax rates to the estimated future pretax net cash flows relating to proved oil and gas reserves, less the tax basis of the properties involved.  The future income tax expenses give effect to tax deductions, credits, and allowances relating to the proved oil and gas reserves.  All cash flow amounts, including income taxes, are discounted at 10%.

Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision.  This table should not be construed to be an estimate of the current market value of the Company’s proved reserves.  Management does not rely upon the information that follows in making investment decisions.

	December 31,
	2011			2010
	(In thousands)
Future cash inflows	$	343,020		$	265,393
Future production costs	(108,394		)	(70,659		)
Future development costs	(42,613		)	(60,632		)
Future income taxes	(49,264		)	(41,138		)
Future net cash flows	142,749			92,964
10% annual discount	(93,860		)	(72,012		)
Standardized measure of discounted future net cash flows	$	48,889		$	20,952

Changes in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

An analysis of the changes in the standardized measure of discounted future net cash flows during each of the last two years is as follows:

	December 31,
	2011			2010
	(In thousands)
Standardized measure of discounted future net cash flows, beginning of year	$	20,952		$	26,421
Sales of oil and gas, net of production costs and taxes	(5,160		)	(2,951		)
Price revisions	(10,151		)	2,270
Extensions, discoveries and improved recovery, less related costs	6,427			(1,915		)
Changes in estimated future development costs	33,297			1,214
Development costs incurred during the period	2,329			753
Quantity revisions	(25,350		)	903
Accretion of discount	2,095			2,642
Net changes in future income taxes	—			—
Purchases of reserves-in-place	29,279			2,178
Sales of reserves-in-place	—			(8,834		)
Changes in production rates timing and other	(4,829		)	(1,729		)
Standardized measure of discounted future net cash flows, end of year	$	48,889		$	20,952

The twelve month weighted averaged adjusted prices in effect at December 31, 2011 and 2010 were as follows:

	2011		2010
Oil (per Bbl)	$	89.07	$	75.41
Natural Gas (per Mcf)	$	4.37	$	4.65

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Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

On March 10, 2011, we dismissed Braver P.C.  On March 10, 2011, our Board of Directors engaged Ehrhardt Keefe Steiner & Hottman PC as the Company’s independent registered public accounting firm.  The decision to engage Ehrhardt Keefe Steiner & Hottman PC was approved by our Board of Directors on March 9, 2011.

The dismissal of Braver P.C. was the result of the Merger transaction and our belief that it was appropriate for Ehrhardt Keefe Steiner & Hottman PC to serve as the Company’s auditors on a post-merger transaction basis.

Item 9A.    Controls and Procedures.

Evaluation of Disclosure Controls and Procedures.

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

Our Chief Executive Officer, Patrick R. McDonald, and our Chief Financial Officer, Kevin D. Struzeski, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of the end of the period covered by this Annual Report on Form 10-K (the “Evaluation Date”). Based on this evaluation, they believe that as of the Evaluation Date our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (i) is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms; and (ii) is accumulated and communicated to Carbon’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Changes in Internal Control Over Financial Reporting.

There has not been any change in our internal control over financial reporting that occurred during the year ended December 31, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Annual Report on Internal Control Over Financial Reporting

The Company’s management is responsible for establishing internal control over financial reporting as defined in Rules 13a-15(f) and 15(d)-15(f) under the Securities Exchange Act of 1934.

The Company’s internal controls over financial reporting are intended to be designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. The Company’s internal controls over financial reporting are expected to include those policies and procedures that management believes are necessary that:

(i)pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

(ii)provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

(iii)provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

As of December 31, 2011, management assessed the effectiveness of the Company’s internal control over financial reporting (“ICFR”) based on the criteria for effective ICFR established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and SEC guidance on conducting such assessments by smaller reporting companies and non-accelerated filers.

Based on that assessment, management concluded that, during the period covered by this report, such internal controls and procedures were effective based on those criteria.

This Annual Report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting due to the permanent exemption from such requirement for smaller reporting companies.

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A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the internal control system are met.  Because of the inherent limitations of any internal control system, no evaluation of controls can provide assurance that all control issues, if any, within a company have been detected.

Item 9B.    Other Information.

None.

PART III

Item 10.    Directors, Executive Officers and Corporate Governance.

The following persons serve as executive officers and directors of Carbon.

Name	Age	Position
Patrick R. McDonald	55	Chairman of the Board, Director, President and Chief Executive Officer
Kevin D. Struzeski	53	Chief Financial Officer, Treasurer and Secretary
Bryan H. Lawrence	69	Director
Peter A. Leidel	55	Director
Mark D. Pierce	58	Senior Vice President of Nytis LLC

Executive Officer/Director

Patrick R. McDonald.  Mr. McDonald is Chairman, Chief Executive Officer and President of Carbon Natural Gas Company.  Mr. McDonald is also Chairman of the Board of Directors of Nytis Exploration Company, Inc., a company involved in the oil and natural gas exploration and production business in Alberta, British Columbia and Northwest Territories, Canada.  From 1998 to 2003, Mr. McDonald was Chief Executive Officer, President and Director of Carbon Energy Corporation, a publicly traded, AMEX listed oil and gas exploration and production company which in 2003 was merged with Evergreen Resources, Inc.  From 1987 to 1997 Mr. McDonald was Chief Executive Officer, President and Director of Interenergy Corporation, a natural gas gathering, processing and marketing company which in December 1997 was merged with KN Energy Inc.  Prior to that he worked as an exploration geologist with Texaco International Exploration Company where he was responsible for oil and gas exploration efforts in the Middle East and Far East.  Mr. McDonald received a Bachelor’s degree in Geology and Economics from Ohio Wesleyan University and a Masters degree in Business Administration Finance from New York University.  Mr. McDonald serves as a member of the Board of Directors of Forest Oil Corporation (NYSE:FST), is Chairman of the Board of Directors of Lone Pine Resources and is a member of the Board of Directors of other privately held companies involved in the natural resources industry in the United States and Canada.  Mr. McDonald is a Certified Petroleum Geologist and is a member of the American Association of the Petroleum Geologists and of the Canadian Society of Petroleum Geologists.

Our Board of Directors believes that Mr. McDonald, as our Chief Executive Officer and President and as a co-founder of Nytis USA, should serve as a director because of his unique understanding of the opportunities and challenges that we face and his in-depth knowledge about the natural gas and oil business, and our long-term growth strategies.

Other Directors

The following information pertains to our non-employee directors, their principal occupations and other public company directorships for at least the last five years and information regarding their specific experiences, qualifications, attributes and skills.

Bryan H. Lawrence.  Mr. Lawrence has been a Director of the Company since February 14, 2011 and of Nytis USA since 2005.  Mr. Lawrence is a founder and member of Yorktown Partners LLC which was established in September 1990.  Yorktown Partners LLC is the manager of private equity partnerships that invest in the energy industry.  Mr. Lawrence had been employed at Dillon, Read & Co. Inc. since 1966, serving as a Managing Director until the merger of Dillon Read with SBC Warburg in September 1997.  Mr. Lawrence also serves as a Director of Crosstex Energy, Inc. (NASDAQ-XTEX), Hallador Petroleum Company (OTC-HPCO.OB), Star Gas Partners, L.P. (NYSE:SGU), Approach Resources, Inc. (NASDAQ: AREX) Winstar Resources Ltd. (TSE-WIX), Compass Petroleum Ltd. (CDNX:CPO.V) and certain non-public companies in the energy industry in which the

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Yorktown partnerships hold equity interests.  Mr. Lawrence served as a director of Carbon Energy Corporation and Interenergy Corporation.

Our Board of Directors believes that Mr. Lawrence should serve as a director because of his experience on the Board of Directors of other public companies, which our Board of Directors believes will be beneficial to us as we move forward as a public company, as well as Mr. Lawrence’s relevant business experience in the energy industry and his extensive financial expertise, which he has acquired through his years of experience in the investment banking industry.

Peter A. Leidel.  Mr. Leidel has been a Director of the Company since February 14, 2011 and of Nytis USA since 2005.  Mr. Leidel is a founder and member of Yorktown Partners LLC which was established in September 1990.  Yorktown Partners LLC is the manager of private equity partnerships that invest in the energy industry.  Previously, he was a partner of Dillon, Read & Co. Inc.  He was previously employed in corporate treasury positions at Mobil Corporation and worked for KPMG Peat Marwick and the U.S. Patent and Trademark Office.  Mr. Leidel is a director of certain non-public companies in the energy industry in which the Yorktown partnerships hold equity interests.  Mr. Leidel served as a director of Carbon Energy Corporation and Interenergy Corporation.

Our Board of Directors believes that Mr. Leidel should serve as a director because of his significant knowledge of our industry, his prior experience with our business and his financial expertise, which will be important as our Board of Directors exercises its oversight responsibility regarding the quality and integrity of our accounting and financial reporting processes and the auditing of our financial statements.

Other Executive Officers

Kevin D. Struzeski.  Mr. Struzeski was appointed as the Company’s Chief Financial Officer, Treasurer and Secretary on February 14, 2011 and has been the CFO, Treasurer and Secretary of Nytis USA since 2005.  From 2003 to 2004, Mr. Struzeski was a director of treasury of Evergreen Resources, Inc., and from 1998 to 2003, he was Chief Financial Officer, Secretary and Treasurer of Carbon Energy Corporation.  Mr. Struzeski was also Chief Financial Officer, Secretary and Treasurer of Carbon Energy Canada Corporation.  Mr. Struzeski served as Accounting Manager for Media One Group from 1997 to 1998 and prior to that was employed as Controller for Interenergy Corporation from 1995 to 1997.  Mr. Struzeski is a Certified Public Accountant.

Mark D. Pierce.  Mark Pierce is the general manager and Senior Vice President for Nytis LLC.  From 2005 until 2009 he was Operations Manager for Nytis LLC.  Mr. Pierce has 30 years of oil and gas experience.  He began his career at Texaco, Inc. and worked 20 years with Ashland Exploration, Inc.  At Ashland Exploration, Inc., he spent 12 years in the production/reservoir engineering area and then moved into the executive level with oversight at various times of marketing, finance, business development, external affairs, operations and land.  His experience includes domestic and international.  Mr. Pierce has a B.S. in Civil Engineering from Rose-Hulman Institute of Technology and has successfully completed Indiana University’s Executive Development Program and Harvard University’s Graduate School of Business Advanced Management Program.  He is a registered Petroleum Engineer in Kentucky, West Virginia and Ohio.

Terms of Office

Our Board of Directors currently consists of three directors, each of whom is elected annually at the annual meeting of our stockholders, the most recent of which was held on December 8, 2011.  Each Director will continue to serve as a Director until such Director’s successor is duly elected and qualified or until his earlier resignation, removal or death.

Family Relationships

There are no family relationships between or among any of the current directors or executive officers.

Section 16(a) Beneficial Ownership Reporting Compliance:

Section 16(a) of the 1934 Act requires the Company’s directors and officers and any persons who own more than ten percent of the Company’s equity securities, to file reports of ownership and changes in ownership with the Securities and Exchange Commission (the “SEC”).  All directors, officers and greater than ten-percent stockholders are required by SEC regulation to furnish the Company with copies of all Section 16(a) reports files.  Based solely on our review of the copies of Forms 3, 4 and any amendments thereto furnished to us during the fiscal year completed December 31, 2011, and subsequently, we believe that during the Company’s 2011 fiscal year all filing requirements applicable to our officers, directors and greater-than-ten-percent stockholders were complied with; except with regard to Paul Isaac.

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Code of Ethics

The Board of Directors has adopted a Code of Ethics, as defined under the federal securities laws that applies to all directors and officers of the Company.  A copy of the Code of Ethics has been filed with the SEC as Exhibit 14 to the Company’s Annual Report on Form 10-K for 2004.

No Audit Committee

The Company does not have a separately designated audit committee.  Instead, the entire Board as a whole acts as the Company’s audit committee.  Consequently the Company does not currently have a designated audit committee financial expert.

No Nominating Committee; Procedures by which Security Holders May Recommend Nominees to the Board of Directors; Communications with Members of the Board of Directors

The Company does not have a separately designated nominating committee.  The Company does not have such a committee because we currently believe that given our small size and the fact that none of the members of our Board are currently considered “independent”, that such a committee is not currently necessary.  Unless and until the Company establishes a separate nominating committee, when a Board vacancy occurs, the remaining Board members will participate in deliberations concerning director nominees.  In the future the Company may determine that it is appropriate to designate a separate nominating committee of the Board of Directors comprised solely of independent directors.

To date, the Board of Directors has not adopted a formal procedure by which shareholders may recommend nominees to the Board of Directors.  In considering candidates for membership on the Board of Directors, the Board of Directors will take into consideration the needs of the Company and its Board of Directors and the qualifications of the candidate.  With respect to potential new Board members the Board will require and/or review information such as the following:

·The name and address of the proposed candidate;

·The proposed candidate’s resume or a listing of his or her qualifications to be a director of the Company;

·A description of any relationship that could affect such person’s qualifying as an independent director, including identifying all other public company board and committee memberships;

·A confirmation of such person’s willingness to serve as a director if selected by the Board of Directors; and

·Any information about the proposed candidate that would, under the federal proxy rules, be required to be included in the Company’s proxy statement if such person were a nominee.

Item 11.    Executive Compensation.

Summary Compensation Table

The following table sets forth information relating to compensation awarded to, earned by or paid to our Chairman, President and Chief Executive Officer and our Chief Financial Officer, Treasurer and Secretary by the Company, and the highest paid employee of Nytis LLC, whose total compensation exceeded $100,000 during the fiscal year ended December 31, 2011, for all services rendered in all capacities during the years ended December 31, 2011and 2010.

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Name andPrincipalPosition	Year	Salary($)	Bonus($)	StockAwards($)	OptionAwards($)	Non-Equity Incentive Plan Compensation($)	Nonqualified Deferred Compensation($)	All OtherCompensation($)(2)	Total($)
Patrick R.	2011	339,000	135,000					84,671	558,671
McDonald	2010	307,125	135,000		—	—	—	98,520	540,645
Chairman, President and Chief Executive Officer (1)
Kevin D.	2011	206,544	115,000					65,521	387,065
Struzeski Chief	2010	188,114	85,000		—	—	—	59,997	333,111
Financial Officer, Treasurer and Secretary (1)
Mark D. Pierce	2011	172,143	75,000					22,576	269,719
Senior Vice	2010	169,804	99,360		—	—	—	18,421	287,585
President of Nytis LLC

(1)During the year ended December 31, 2010 and the six months ended June 30, 2011, Mr. McDonald and Mr. Struzeski were employees of Nytis Exploration Company and provided service to Nytis USA pursuant to an agreement between Nytis Exploration Company and Nytis USA.  Under this agreement, Nytis USA funded, by way of full reimbursement to Nytis Exploration Company, the cash compensation paid to Mr. McDonald and Mr. Struzeski for services provided to Nytis USA.  The amounts set forth in the “salary”, “bonus” and “all other compensation” columns in the table reflect both the amounts allocated and paid to Mr. McDonald and Mr. Struzeski by Nytis Exploration Company, Nytis USA and the Company.  For the six months ended June 30, 2011 and the year ended December 31, 2010, Nytis USA’s portion of Mr. McDonald’s compensation was approximately 71% and 67% of his total compensation, respectively; Nytis USA’s portion of Mr. Struzeski’s compensation during such time periods were approximately 75% and 62% of his total compensation, respectively.  These percentages reflect the amount of time these persons spent in service to Nytis USA.  Although Messrs. McDonald and Struzeski are officers of both companies, these companies do not compete for business; as provided in their respective Certificates of Incorporation, Nytis Exploration Company may not operate in the United States, and Nytis USA operates exclusively in the United States.

Prior to the closing of the Merger, all of the persons providing services to Nytis USA were employees of Nytis Exploration Company.  Effective as of July 1, 2011, all of these persons, including Mr. McDonald and Mr. Struzeski, became employees of Carbon.  However, the Company will allow these persons, including Mr. McDonald and Mr. Struzeski, to continue to provide services to Nytis Exploration Company; the Company will be paid a flat fee of $15,000 per month for the costs associated with such persons’ service to Nytis Exploration Company.

(2)All Other Compensation in 2011 and 2010 was comprised of (i) unused vacation, (ii) contributions made by the Company or Nytis Exploration Company to its 401(k) plans, (iii) premiums paid on life insurance policies on such employee’s life, and (iv) other taxable fringe benefits.

Narrative Disclosure to Summary Compensation Table

To date, the Board of Directors has been charged with reviewing and approving the terms and structure of the compensation of the Company’s executive officers.  The Company has not yet retained an independent compensation consultant to assist the Company to review and analyze the structure and terms of the Company’s executive officers.

The Company considers various factors when evaluating and determining the compensation terms and structure of its executive officers, including the following:

1.The executive’s leadership and operational performance and potential to enhance long-term value to the Company’s stockholders;

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2.The Company’s financial resources, results of operations, and financial projections;

3.Performance compared to the financial, operational and strategic goals established for the Company;

4.The nature, scope and level of the executive’s responsibilities;

5.Competitive market compensation paid by other companies for similar positions, experience and performance levels; and

6.The executive’s current salary and the appropriate balance between incentives for long-term and short-term performance.

Company management is responsible for reviewing the base salary, annual bonus and long-term compensation levels for other Company employees, and the Company expects this practice to continue going forward.  The entire Board of Directors remains responsible for significant changes to, or adoption, of new employee benefit plans.

The Company believes that the compensation environment for qualified professionals in the industry in which we operate is highly competitive.  In order to compete in this environment, the compensation of our executive officers is primarily comprised of the following four components:

·Base salary;

·2011 Stock Incentive Plan benefits;

·Discretionary cash bonuses; and

·Other employment benefits.

Base Salary. Base salary, paid in cash, is the first element of compensation to our officers. In determining base salaries for our key executive officers, the Company aims to set base salaries at a level we believe enables us to hire and retain individuals in a competitive environment and to reward individual performance and contribution to our overall business goals. The Board of Directors believes that base salary should be relatively stable over time, providing the executive a dependable, minimum level of compensation, which is approximately equivalent to compensation that may be paid by competitors for persons of similar abilities. The Board of Directors believes that base salaries for our executive officers are appropriate for persons serving as executive officers of public companies similar in size and complexity similar to the Company.

Stock Incentive Plan Benefits. Each of the Company’s executive officers is eligible to be granted awards under the Company’s equity compensation plans.  The Company believes that equity based compensation helps align management and executives’ interests with the interests of our stockholders. Our equity incentives are also intended to reward the attainment of long-term corporate objectives by our executives. We also believe that grants of equity-based compensation are necessary to enable us to be competitive from a total remuneration standpoint.  At the present time, we have one equity incentive plan for our management and employees, the 2011 Stock Incentive Plan, although as of December 31, 2011 no awards had been made pursuant to this plan.  We have no set formula for granting awards to our executives or employees. In determining whether to grant awards and the amount of any awards, we take into consideration discretionary factors such as the individual’s current and expected future performance, level of responsibilities, retention considerations, and the total compensation package.

Subsequent to December 31, 2011, the Company has issued 1,450,000 restricted shares and 1,096,500 restricted performance units pursuant to the Plan of which 960,000 restricted shares and 680,000 restricted performance units were granted to named executive officers and directors.

Annual Bonus.Discretionary cash bonuses are another prong of our compensation plan.  The Board of Directors believes that it is appropriate that executive officers and other employees have the potential to receive a portion of their annual cash compensation as a cash bonus to encourage performance to achieve key corporate objectives and to be competitive from a total remuneration standpoint.

For annual bonus payments made in 2011 and 2010 we had no set formula for determining or awarding discretionary cash bonuses to our executives or employees. In determining whether to award bonuses and the amount of any bonuses, we took into consideration discretionary factors such as the individual’s current and expected future performance, level of responsibilities, retention considerations, and the total compensation package, as well as the Company’s overall performance including cash flow, significant acquisitions or divestitures and other operational factors.

Annual bonus payments in 2012 will be paid under the provisions of the Carbon Natural Gas Company 2011 Annual Incentive Plan (“Annual Incentive Plan”) whereby fifty percent of annual bonuses will be at the discretion of the Board taking into consideration the factors listed above and fifty percent of annual bonuses will be determined and weighed based upon the performance measures and objectives as follows:

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Performance Measure	Weighting		Objective
Total Shareholder Return	25	%	7.5% Increase
EBITDA per Debt Adjusted Share Growth	25	%	7.5% Increase
Net Total Proved Reserves	25	%	7.5% Increase
Net Annual Production Growth	25	%	7.5% Increase

The Annual Incentive Plan period for annual bonuses paid in 2012 is from July 1, 2011 and December 31, 2011.

Once the pool has been established, the CEO shall have the discretion to allocate awards to individuals based on his assessment as to individual or group performances.

The employment agreements we have entered into with certain of our executive officers provide that each is eligible to receive a discretionary cash bonus.  Such bonuses are to be considered and determined by the Board of Directors.

Other Compensation/Benefits. Another element of the overall compensation is through providing our executive officers various employment benefits, such as the payment of health and life insurance premiums on behalf of the executive officers.  Our executive officers are also eligible to participate in our 401(k) plans on the same basis as other employees and the Company historically has made matching contributions to the 401(k) plan, including for the benefit of our executive officers.

Employment Contracts and Termination of Employment and Change-in-Control Arrangements

As of December 31, 2011, both Mr. McDonald and Mr. Struzeski were parties to an employment agreement with Nytis Exploration Company.  Although neither the Company nor any of its subsidiaries are a party to these agreements, if there is a change of control event (as defined in the agreements) at Nytis USA, Messrs. McDonald and Struzeski may be entitled to certain payments.  Mr. McDonald and Mr. Struzeski are each employed by the Company pursuant to oral arrangements that are described below.  The Company and these officers are in the process of negotiating the final terms and conditions of written employment agreements.

The agreement with Patrick R. McDonald allows for the termination of Mr. McDonald’s employment upon 90 days written notice (the date of expiration of such notice to be the “Termination Date”).  In the event of the termination of Mr. McDonald’s employment, Mr. McDonald is to receive (a) on the Termination Date, a lump sum of money equal to 150% of Mr. McDonald’s “Compensation,” defined as the arithmetic average of Mr. McDonald’s annual base salary, bonus and other cash compensation for each of the three years prior to the Termination and (b) for a period of 24 months from the Termination Date, his medical, dental, disability and life insurance coverage at the same levels of coverage as in effect immediately prior to the Termination Date.

In the event of a change in control of the Company supported by Mr. McDonald, he is to receive 200% of the Compensation (as defined above).  In the event of a change in control not supported by Mr. McDonald, he is entitled to receive 300% of the Compensation (as defined above).

The agreement with Kevin D. Struzeski allows for the termination of Mr. Struzeski’s employment upon 90 days written notice.  In the event of the termination of Mr. Struzeski’s employment, Mr. Struzeski is to receive on the Termination Date:  (a) a lump sum of money equal to 100% of Mr. Struzeski’s then base salary, less required statutory deductions; and (b) a lump sum equal to the cost to provide benefits for a period of 12 months from the Termination Date at the same levels of coverage as in effect immediately prior to the Termination Date.

In the event of a change in control of the Company, Mr. Struzeski is entitled to receive a sum of money equal to: (a) 200% of his base salary, bonus and other cash compensation and incentive compensation; and (b) 100% of the annual cost to the Company of the benefits provided to Mr. Struzeski.

Mark D. Pierce is employed as the Senior Vice President of Nytis LLC pursuant to an employment agreement dated May 9, 2005.  Pursuant to such employment agreement Mr. Pierce may be terminated by Nytis LLC upon 90 days written notice.  In the event of the termination of Mr. Pierce’s employment, Mr. Pierce is to receive on the Termination Date: (a) a lump sum of money equal to 100% of Mr. Pierce’s then base salary, less required statutory deductions; and (b) a lump sum equal to the cost to provide benefits for a period of 12 months from the Termination Date at the same levels of coverage as in effect immediately prior to the Termination Date.

Pursuant to the employment agreements with Messrs. McDonald, Struzeski and Pierce such officers are entitled to certain payments upon termination of employment.  Other than these arrangements, we currently do not have any compensatory plans or arrangements that provide for any payments or benefits upon the resignation, retirement or any other termination of any of our executive officers, as the result of a change in control, or from a change in any executive officer’s responsibilities following a change in control.

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Risk/Reward Issues

The Board of Directors does not believe that the current structure of the Company’s compensation policies promotes unnecessary or inappropriate short-term or long-term risks.  The cash compensation paid to the Company’s executive officers consists of fixed salaries and possible performance bonuses.  These performance bonuses (if any) will be granted by the Board of Directors based on operational and financial performance.  See “Executive Compensation — Narrative Disclosure to Summary Compensation Table — Annual Bonus” for a description of operational and financial performance objectives for determined performance bonuses.

Grants of Plan-Based Awards in Fiscal 2011

There were no option or other equity grants in 2011.

Outstanding Equity Awards at December 31, 2011

The following table reflects the outstanding equity awards as of December 31, 2011.  Other than the warrant awards issued to former SLSC officers and directors noted below, each of the following awards were made by Nytis USA prior to the Merger and were assumed as a result of the Merger; the number of shares and the option exercise price, have been adjusted in line with the exchange ratio of Nytis USA shares for Company shares in the Merger.  There have been no equity awards for the year ended December 31, 2011.

OPTION AWARDS

Award Recipient	Option for # of Shares	# Vested	Exercise Price per Share		Date Granted	Expiration
Kevin Struzeski (Officer)	163,076	163,076	$	0.61	3/16/2006	1/1/2016
David H. Kennedy (Former Director)	40,769	40,769	$	0.61	5/20/2005	5/20/2015
	32,615	32,615	$	0.71	1/1/2008	1/1/2018
Paul G. McDermott (Former Director)	32,615	32,615	$	0.71	1/1/2008	1/1/2018
	269,075	269,075

WARRANT AWARDS

Award Recipient	Option for # of Shares	# Vested	Exercise Price per Share		Date Granted	Expiration
Patrick R. McDonald (Officer) (1)	2,446,133	2,446,133	$	0.85	05/19/2005	05/19/2015
Former SLSC Officers and Directors	250,000	250,000	$	1.00	01/10/2007	01/10/2017
	2,696,133	2,696,133

(1) Grantee is McDonald Energy LLC, over which Mr. McDonald has voting and investment power.

Option Exercises and Stock Vested in Fiscal 2011

There were no option exercises or stock vested in 2011.

Compensation of Directors

Directors who are not employees of the Company or of its affiliates are currently paid $2,500 per quarter.  Directors who are employed by the Company or its affiliates are not compensated additionally for their directorships.  The only non-employee

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director who received compensation in accordance with this arrangement was David Kennedy.  Mr. Kennedy received total director fees of $10,000 during the year ended December 31, 2011.

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

As of March 12, 2012 the Company had 114,185,405 shares of common stock outstanding.  The following sets forth certain information about the number of common shares owned by (i) each person (including any group) known to us that beneficially owns five percent or more of the common shares (the only class of the Company’s voting securities), (ii) each of our directors and named executive officers, and (iii) all named executive officers and directors as a group.  Unless otherwise indicated, the stockholders possess sole voting and investment power with respect to the shares shown.  The business address for each of the Company’s officers and directors is 1700 Broadway, Suite 1170, Denver, Colorado 80290.

Name and Address of Beneficial Owner	Amount of Beneficial Ownership(1)	Percent of Class(2)
5% Stockholders
Yorktown Energy Partners V, L.P. 410 Park Avenue, 19th Floor New York, NY 10022	17,938,309	15.7	%
Yorktown Energy Partners VI, L.P., 410 Park Avenue, 19th Floor New York, NY 10022	17,938,309	15.7	%
Yorktown Energy Partners IX, L.P., 410 Park Avenue, 19th Floor New York, NY 10022	22,222,222	19.5	%
Paul J. Isaac (3) 75 Prospect Avenue Larchmont, New York 10538	13,066,667	11.4	%
Austin Marxe and David M. Greenhouse (4) 527 Madison Avenue Suite 2600 New York, New York 10022	10,888,889	9.5	%
RBCP Energy Fund Investments, LP c/o Cadent Energy Partners, LLC 4 High Ridge Park, Suite 303 Stamford, CT 06905	8,153,777	7.1	%
Wynnefield Capital (5) 450 Seventh Avenue Suite 509 New York, New York 10123	6,444,445	5.6	%

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Name of Beneficial Owner	Amount of Beneficial Ownership(1)	Percentage(2)		Options and Warrants Exercisable Within 60 Days	Total	Percent of Total
Executive Officers and Directors
Bryan H. Lawrence, Director (6)	58,098,840	50.9	%	—	58,098,840	50.9	%
Peter A. Leidel, Director (7)	58,098,840	50.9	%	—	58,098,840	50.9	%
Patrick R. McDonald, Director, President and Chief Executive Officer (8)	1,991,153	1.7	%	2,446,133	4,437,286	3.8	%
Kevin D. Struzeski, Chief Financial Officer, Treasurer and Secretary	407,689	*		163,076	570,765	*
Mark D. Pierce, Senior Vice President of Nytis Exploration Company LLC	40,769	*		—	40,769	*
All directors and executive officers as a group (five persons) (9)	60,538,451	53.0	%	2,609,209	63,147,660	54.1	%

* less than 1%

(1)  Under Rule 13d-3, a beneficial owner of a security includes any person who, directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares: (i) voting power, which includes the power to vote, or to direct the voting of shares; and (ii) investment power, which includes the power to dispose or direct the disposition of shares.  Certain shares may be deemed to be beneficially owned by more than one person (if, for example, persons share the power to vote or the power to dispose of the shares).  In addition, shares are deemed to be beneficially owned by a person if the person has the right to acquire the shares (for example, upon exercise of an option) within 60 days of the date as of which the information is provided.  In computing the percentage ownership of any person, the amount of shares outstanding is deemed to include the amount of shares beneficially owned by such person (and only such person) by reason of these acquisition rights.

(2)  Percentages are rounded to the nearest one-tenth of one percent.  The percentage is based on 114,185,405 shares of common stock outstanding as of March 12, 2012.

(3)  Includes (i) 8,888,889 common stock shares owned by Arbiter Partners QP, L.P., (ii) 2,222,222 common stock shares owned by Isaac Brothers, LLC and (iii) 1,955,556 common stock shares owned by 75 Prospect Partners, LLC, over which Mr. Isaac has voting and investment power.

(4)  Consists of (i) 7,555,556 common stock shares owned by Special Situations Fund III QP, L.P. (“SSFQP”), (ii) 2,222,222 common stock shares owned by Special Situations Cayman Fund, L.P. (“SSF Cayman”) and (iii) 1,111,111 common stock shares owned by Special Situations Private Equity Fund, L.P. (“SSFPE”).  MGP Advisers Limited Partnership (“MGP”) is the general

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partner of SSFQP.  AWM Investment Company, Inc. (“AWM”) is the general partner of MGP, the general partner of and investment adviser to SSF Cayman and the investment adviser to SSFPE.  Austin W. Marxe and David M. Greenhouse are the principal owners of MGP and AWM.  Through their control of MGP and AWM, Messrs. Marxe and Greenhouse share voting and investment control over the portfolio securities of each of the funds listed above.

(5)  Includes (i) 2,887,111 common stock shares owned by Wynnefield Partners Small Cap Value, LP I, (ii) 1,997,778 common stock shares owned by Wynnefield Partners Small Cap Value, LP and (iii) 1,559,556 common stock shares owned by Wynnefield Small Cap Value Offshore Fund, Ltd., over which Wynnefield Capital has voting and investment power.

(6)  Includes (i) 17,938,309 common stock shares owned by Yorktown Energy Partners V, L.P., (ii) 17,938,309 common stock shares owned by Yorktown Energy Partners VI, L.P. and (iii) 22,222,222 common stock shares owned by Yorktown Energy Partners IX, L.P. over which Mr. Lawrence and Mr. Leidel have voting and investment power.

(7)  Includes (i) 17,938,309 common stock shares owned by Yorktown Energy Partners V, L.P., (ii) 17,938,309 common stock shares owned by Yorktown Energy Partners VI, L.P. and (iii) 22,222,222 common stock shares owned by Yorktown Energy Partners IX, L.P. over which Mr. Lawrence and Mr. Leidel have voting and investment power.

(8)  Includes (i) 482,704 shares owned by McDonald Energy, LLC over which Mr. McDonald has voting and investment power, and (ii) stock purchase warrants held by McDonald Energy, LLC exercisable for 2,446,133 shares of common stock.

(9)  The shares over which both Mr. Lawrence and Mr. Leidel have voting and investment power are the same shares and the percentage of total shares has not been aggregated for purposes of these calculations.

Equity Compensation Plans

Our Board of Directors has adopted the 2011 Stock Incentive Plan (the “Plan”) and such Plan was approved by the stockholders on December 8, 2011 at the annual meeting of stockholders.  As of December 31, 2011 no awards of common stock shares were made under the Plan.  Subsequent to December 31, 2011, the Company has issued 1,450,000 restricted shares and 1,096,500 restricted performance units pursuant to the Plan.  Information regarding options outstanding as December 31, 2011 is set forth under the heading “Market for Common Equity and Related Stockholder Matters - Securities Authorized for Issuance Under Equity Compensation Plans” above.

Item 13.    Certain Relationships and Related Transactions, and Director Independence.

Certain Relationships

Nytis Exploration Company is an independent oil and gas company that engages in the exploration, development, production, marketing and sale of oil, gas, coalbed methane and other hydrocarbons in locations outside of the United States.  Carbon and Nytis Exploration Company are related in that the same individuals serve as directors of both corporations and, prior to the closing of the Private Placement, a majority of the outstanding stock of each corporation was owned by the same stockholders.  However, Nytis Exploration Company is not currently a direct or indirect subsidiary of the Company.  Through June 30, 2011 the Company engaged Nytis Exploration Company to assist in the management, direction and supervision of the operations and business functions of the Company.  A service agreement between the Company and Nytis Exploration Company provided for certain restrictions on Nytis Exploration Company’s authority to perform acts in connection with the business of the Company and established provisions for the compensation of Nytis Exploration Company in performing these duties.  Under this arrangement from time to time, Nytis Exploration Company provided personnel (including Mr. McDonald and Mr. Struzeski) and funding for the operations of Nytis USA, Nytis PA and Nytis LLC.  As of July 1, 2011, Nytis Exploration Company personnel providing services to the Company (including Mr. McDonald and Mr. Struzeski) became Company employees.  However, the Company will allow these persons, including Mr. McDonald and Mr. Struzeski, to continue to provide services to Nytis Exploration Company; and the Company will be paid a flat fee of $15,000 per month for the costs associated with such persons’ service to Nytis Exploration Company.

Related Transactions

The following sets forth information regarding transactions between the Company (and its subsidiaries) and its officers, directors and significant stockholders since January 1, 2011.

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Employment Agreements

See the Executive Compensation section of this Annual Report for a discussion of the employment agreement with Mr. Pierce and Nytis LLC and between Messrs. McDonald and Struzeski and Nytis Exploration Company.

Private Placement of Securities

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 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 Yorktown Energy Partners IX, L.P. (“Yorktown IX”), an institutional investor and affiliate of (i) Yorktown Energy Partners V, L.P. and (ii) Yorktown Energy Partners VI, L.P. (collectively with Yorktown IX, the “Yorktown Entities”), as well as of (iii) two of our directors, Bryan Lawrence and Peter Leidel, for the private placement of 100 shares of the Company’s Series A Convertible Preferred Stock at a price of $100,000 per share (aggregate purchase price by Yorktown IX was $10,000,000).

The shares of Series A Convertible Preferred Stock issued in the Private Placement automatically converted into 22,222,222 shares of common stock on July 18, 2011, the effective date of an amendment to the Company’s Amended and Restated Certificate of Incorporation to increase the number of common stock shares the Company is authorized to issue.  Upon such conversion, Carbon issued 66,666,666 shares of common stock at $0.45 per share, for $30 million in gross proceeds.

As a result of Yorktown IX’s purchase of such shares of Series A Convertible Preferred Stock, the Yorktown Entities collectively control a majority of our voting capital stock.

The purchase price of the shares of common stock issued in the private placement of securities described above, and thus by extension, the price at which the Series A Convertible Preferred Stock converted into shares of our common stock, was determined by a special pricing committee of our Board (the “Pricing Committee”).  Patrick McDonald and David Kennedy were the members of the Pricing Committee.  No member of the Pricing Committee purchased any shares of common stock or Series A Convertible Preferred Stock in connection with the private placement.

Director Independence

The Company’s Board consists of Messrs. Lawrence, Leidel, and McDonald.  The Company utilizes the definition of “independent” as it is set forth in Rule 5605(a)(2) of the Nasdaq Listing Rules.  Further, the Board considers all relevant facts and circumstances in its determination of independence of all members of the board (including any relationships).  Based on the foregoing criteria, Messrs. McDonald, Lawrence and Leidel are not considered to be independent directors.

Item 14.    Principal Accountant Fees and Services.

Audit Fees

Our independent registered public accounting firm, Ehrhardt Keefe Steiner & Hottman PC, (“EKSH”) billed us aggregate fees in the amount of approximately $234,000 for the fiscal year ended December 31, 2011, and billed Nytis USA approximately $88,000 for the fiscal year ended December 31, 2010.  These amounts were billed for professional services that EKSH provided for the audit of our annual financial statements, review of the interim consolidated financial statements included in our reports on Forms 10-Q, reviews of registration statements, issuance of consents and letters to underwriters, services performed in conjunction with our Private Placement, reverse merger and acquisition of assets from ING, and other services typically provided by an auditor in connection with statutory and regulatory filings or engagements for those fiscal years.

Tax Fees

EKSH did not bill us for any tax fees for the fiscal years ended December 31, 2011 and 2010.

All Other Fees

EKSH billed us for information technology support fees of $31,000 for the fiscal years ended December 31, 2011 and 2010.

Audit Committee’s Pre-Approval Practice.

Inasmuch as the Company does not have an audit committee, the Company’s Board of Directors performs the functions of its audit committee.  Section 10A(i) of the 1934 Act prohibits our auditors from performing audit services for us as well as any services not considered to be “audit services” unless such services are pre-approved by the Board of Directors (in lieu of the audit committee) or

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unless the services meet certain de minimis standards.

The Board of Directors has adopted resolutions that provide that the Board must:

Pre-approve all audit services that the auditor may provide to us or any subsidiary (including, without limitation, providing comfort letters in connection with securities underwritings or statutory audits) as required by §10A(i)(A) of the 1934 Act.

Pre-approve all non-audit services (other than certain de minimis services described in §10A(i)(1)(B) of the 1934 Act that the auditors propose to provide to us or any of our subsidiaries.

The Board of Directors considers at each of its meetings whether to approve any audit services or non-audit services.  In some cases, management may present the request; in other cases, the auditors may present the request.  The Board of Directors approved EKSH performing our audit for the 2011 fiscal year.

PART IV

Item 15.    Exhibits, Financial Statement Schedules.

(a)

The following documents are filed as part of this report or are incorporated by reference:

(1)       Financial Statements:

1.        Report of Independent Registered Public Accounting Firm

2.        Consolidated Balance Sheets—December 31, 2011 and 2010

3.        Consolidated Statements of Operations—Years Ended December 31, 2011 and 2010

4.        Consolidated Statements of Shareholders’ Equity—Years Ended December 31, 2011and 2010

5.        Consolidated Statements of Cash Flows—Years Ended December 31, 2011 and 2010

6.        Notes to Consolidated Financial Statements—Years Ended December 31, 2011 and 2010

(2)       Financial Statement Schedules: All schedules have been omitted because the information is either not required or is set forth in the financial statements or the notes thereto.

(3)       Exhibits: See the Index of Exhibits listed in Item 15(b) hereof for a list of those exhibits filed as part of this Annual Report on Form 10-K.

(b)

Index of Exhibits:

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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 from exhibit 10.2(a) to Form 8-K/A for St. Lawrence Seaway Corporation filed on March 31, 2010.
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 21.1 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 21.1 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.
10.9	Employment Agreement between Nytis LLC and Mark D. Pierce, incorporated by reference to exhibit 10.9 to Form S-1/A for Carbon Natural Gas Company filed on September 16, 2011.
10.10	Carbon Natural Gas Company 2011 Annual Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 8-K for Carbon Natural Gas Company filed on December 13, 2011
10.11	Carbon Natural Gas Company 2011 Stock Incentive Plan, incorporated by reference to Exhibit 10.2 to Form 8-K for Carbon Natural Gas Company filed on December 13, 2011
14	Code of Ethics, incorporated by reference to Exhibit 14 to Form 10-K filed on June 29, 2004.
16.1	Letter from Braver P.C., incorporated by reference from exhibit 16.1 to Form 8-K for St. Lawrence Seaway Corporation filed on March 14, 2011.
21.1	Subsidiaries of the Company, incorporated by reference to Exhibit 21.1 to Form S-1 for Carbon Natural Gas Company filed on August 12, 2011.
23.1*	Consent of Ehrhardt Keefe Steiner & Hottman, P.C. regarding the Form S-8 Financials
23.2*	Consent of Cawley, Gillespie & Associates, Inc.
31.1*	Rule 13a-14(a)/15d-14(a) - Certification of Chief Executive Officer. Filed herewith.
31.2*	Rule 13a-14(a)/15d-14(a) - Certification of Chief Financial Officer. Filed herewith.
32.1*	Section 1350 Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the SARBANES-OXLEY ACT of 2002. Filed herewith.

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32.2*	Section 1350 Certification Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the SARBANES-OXLEY ACT of 2002. Filed herewith.
99.1*	Report of Cawley, Gillespie & Associates, Inc., Independent Petroleum Engineers.
101*	Interactive data files pursuant to Rule 405 of Regulation S-T

*  Filed herewith.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.

Date: March 30, 2012	CARBON NATURAL GAS COMPANY
	(Registrant)
	By:	/s/ Patrick R. McDonald
		Patrick R. McDonald
		Chief Executive Officer and President

Power of Attorney

The officers and directors of Carbon Natural Gas Company, whose signatures appear below, hereby constitute and appoint Patrick R. McDonald, the true and lawful attorney-in-fact to sign and execute, on behalf of the undersigned, any amendment(s) to this Annual Report on Form 10-K Annual Report for the year ended December 31, 2011, and any instrument or document filed as part of, as an exhibit to or in connection with any amendment, and each of the undersigned does hereby ratify and confirm as his own act and deed all that said attorneys shall do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.

Signatures	Title	Date
/s/ Patrick R. McDonald	Director, Chief Executive Officer, President and Chairman of the Board (Principal Executive Officer)	March 30, 2012
Patrick R. McDonald
/s/ Kevin D. Struzeski	Chief Financial Officer, Treasurer and Secretary (Principal Financial Officer and Principal Accounting Officer)	March 30, 2012
Kevin D. Struzeski
/s/ Patrick R. McDonald	Director	March 30, 2012
for
Peter A. Leidel

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