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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

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

For the quarter ended June 30, 2012

or

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

For the transition period from               to               

Commission File Number: 000-02040

CARBON NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (720) 407-7043

(Former name, address and fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Company was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES x NO o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to rule 405 of Regulations S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES x NO o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definitions of “large accelerated filer,” “accelerated filer” and ‘smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES o NO x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

At August 11, 2012, there were issued and outstanding 115,795,405 shares of the Company’s common stock, $0.01 par value.

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Carbon Natural Gas Company

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PART I. FINANCIAL INFORMATION

ITEM 1.                Financial Statements

CARBON NATURAL GAS COMPANY

Consolidated Balance Sheets

See accompanying notes to consolidated financial statements.

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CARBON NATURAL GAS COMPANY

Consolidated Statements of Operations

(Unaudited)

See accompanying notes to consolidated financial statements.

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CARBON NATURAL GAS COMPANY

Consolidated Statements of Stockholders’ Equity

(Unaudited)

(in thousands)

See accompanying notes to consolidated financial statements.

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CARBON NATURAL GAS COMPANY

Consolidated Statements of Cash Flows

(Unaudited)

See accompanying notes to consolidated financial statements.

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Carbon Natural Gas Company

Notes to Unaudited

Consolidated Financial Statements

Note 1 — Organization

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

Note 2 — Summary of Significant Accounting Policies

Basis of Presentation

The accompanying unaudited consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information.  Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements.  In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of June 30, 2012, and the Company’s results of operations for the three and six months ended June 30, 2012 and 2011, and the Company’s cash flows for the six months ended June 30, 2012 and 2011.  Operating results for the three and six months ended June 30, 2012 and 2011 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas and oil, natural production declines, the uncertainty of exploration and development drilling results and other factors.  For a more complete understanding of the Company’s operations, financial position and accounting policies, the unaudited consolidated financial statements and the notes thereto should be read in conjunction with the Company’s audited consolidated financial statements for the year ended December 31, 2011 filed on Form 10-K with the Securities and Exchange Commission (“SEC”).

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

Principles of Consolidation

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

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

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

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Note 2 — Summary of Significant Accounting Policies (continued)

Non-majority owned investments that do not meet the criteria for pro-rata consolidation are accounted for using the equity method when the Company has the ability to significantly influence the operating decisions of the investee.  When the Company does not have the ability to significantly influence the operating decisions of an investee, the cost method is used.  All transactions, if any, with investees have been eliminated in the accompanying consolidated financial statements.

Accounting for Oil and Gas Operations

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

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

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

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

The Company performs a ceiling test quarterly.  The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10.  The ceiling test is not a fair value based measurement. Rather, it is a standardized mathematical calculation.  The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties.  Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs.  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 June 30, 2012, the Company’s full cost pool exceeded the ceiling limitation.  Based on oil prices of $88.58 per barrel and gas prices of $3.11 per Mcf, for the three months ended June 30, 2012 the Company recorded a non-cash impairment of approximately $9.9 million.  For the six month period ended June 30, 2012, a non-cash impairment expense of approximately $15.4 million was recorded.  During the three months ended June 30, 2012, there was a reduction in oil and natural gas prices utilized in calculating the present value of future revenues from the Company’s proved gas reserves.  The negative effects of the price declines were partially offset by additional proved undeveloped oil reserves booked during the same period.  For the three and six months ended June 30, 2011, the Company recorded a non-cash impairment expense of approximately $1.1 million and $8.4 million, respectively.

Investments in Affiliates

Investments in non-consolidated affiliates are accounted for under either the equity or cost method of accounting as appropriate.  The cost method of accounting is used for investments in affiliates in which the Company has less than 20% of the voting interests of the affiliate and does not have significant influence.  Investments in non-consolidated

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affiliates, accounted for using the cost method of accounting, are recorded at cost and an impairment assessment of the investment is made annually to determine if a decline in the fair value of the investment, other than temporary, has occurred.  A permanent impairment is recognized if a decline in the fair value occurs.  If the Company holds between 20% and 50% of the voting interest in non-consolidated affiliates and exercises significant influence or control, the equity method of accounting is used to account for the investment.  The Company’s investment in an affiliate that is accounted for using the equity method of accounting increases or decreases by the Company’s share of the affiliate’s profits or losses and such profits or losses are recognized in the Company’s statements of operations.

Asset Retirement Obligations

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

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

The following table is a reconciliation of the ARO for the six months ended June 30, 2012 and 2011:

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Note 2 — Summary of Significant Accounting Policies (continued)

Earnings Per Common Share

Basic earnings (loss) per common share is computed by dividing the net income (loss) attributable to common shareholders for the period by the weighted average number of common shares outstanding during the period.  The shares of restricted common stock granted to certain officers, directors and employees of the Company are included in the computation of basic net income (loss) per share only after the shares become fully vested.  Diluted earnings per common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise of 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, the number of common shares outstanding from the beginning of the periods presented in the accompanying consolidated financial statements to the merger date were computed on the basis of the weighted-average number of common shares of Nytis USA outstanding during the respective periods multiplied by the exchange ratio established in the merger agreement, which was approximately 1,631 common shares of SLSC for each common share of Nytis USA.  The weighted average number of shares used in the earnings per share calculations were based on historical weighted-average number of common shares outstanding multiplied by the exchange ratio.  The number of common shares outstanding from the merger date to June 30, 2012 is the actual number of common shares of the Company outstanding during that period.

At June 30, 2012 and 2011, the Company had common stock equivalents of 4,856,912 and 2,326,664, respectively, which are excluded from the calculation of diluted loss per share as the effect would be anti-dilutive.

Note 3 — Reverse Merger

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

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

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

Note 4— Acquisitions

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

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paid a total of approximately $25.9 million cash for the ING Assets which included additional purchase price adjustments and $600,000 consideration for extending the date of the final closing.

The Company acquired these assets to obtain proved developed producing reserves that were proximate and complimentary to the Company’s then current production and reserve base.  The ING Assets consisted of certain natural gas properties, natural gas gathering and compression facilities and other related assets located in eastern Kentucky and four counties in West Virginia.  Specifically, the ING Assets included (i) some but not all of ING’s leases and interests in natural gas and oil leases, 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 qualified as a business combination and, as such, the Company estimated the fair value of the assets acquired and liabilities assumed as of the acquisition date (the date on which the Company obtained control of the properties).

ING Asset Acquisition Pro Forma

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

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

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.

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

Note 5 — Property and Equipment

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

As of June 30, 2012 and December 31, 2011, the Company had approximately $1.5 million and $1.4 million, respectively, of unproved oil and gas properties not subject to depletion.  The costs not subject to depletion relate to unproved properties that are excluded from amortized capital costs until it is determined whether or not proved reserves can be assigned to such properties.  The excluded properties are assessed for impairment at least annually.  Subject to industry conditions, evaluation of most of these properties and the inclusion of their costs in amortized capital costs is expected to be completed within five years.

The Company capitalized overhead applicable to acquisition, development and exploration activities of approximately $275,000 and $198,000 for the six months ended June 30, 2012 and 2011, respectively.

Depletion expense related to oil and gas properties for the three and six months ended June 30, 2012 was approximately $826,000, or $1.28 per equivalent Mcfe, and approximately $1.8 million, or $1.36 per equivalent Mcfe, respectively and approximately $363,000, or $1.49 per equivalent Mcfe, and approximately $729,000, or $1.42 per equivalent Mcfe for the three and six months ended June 30, 2011, respectively.  Oil and natural gas property ceiling test impairments of approximately $9.9 million and $15.4 million were recognized for the three and six months ended June 30, 2012, respectively, and approximately $1.1 million and $8.4 million for the three and six months ended June 30, 2011, respectively.  Depreciation and amortization expense related to furniture and fixtures, computer hardware and software and other equipment for the six months ended June 30, 2012 and 2011 was approximately $48,000 and $18,000, respectively.

Note 6 — Equity Method Investment

The Company has a 50% interest in Crawford County Gas Gathering Company, LLC (“CCGGC”) which owns and operates pipelines and related gathering and treating facilities.  The Company’s gas production located in Illinois is gathered and transported on CCGGC’s gathering facilities.  The Company’s investment in CCGGC is accounted for under the equity method of accounting, and its share of the income or loss is recognized.  During the six month

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period ended June 30, 2012 and 2011, the Company recorded equity method income of approximately $27,000 and $41,000, respectively, related to this investment.

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

Note 7 — Bank Credit Facility

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

No repayments of principal are required until maturity, except to the extent that outstanding balances exceed the borrowing base then in effect; however, the Company has the right both to repay principal at any time and to reborrow.  Subject to the agreement of the Company and the lender, the size of the credit facility may be increased up to $50.0 million.  The borrowing base is redetermined semi-annually, and the available borrowing amount could be increased or decreased as a result of such redeterminations.  Under certain circumstances the lender may request an interim redetermination.  The facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base.  Interest rates are based on either an Alternate Base Rate or LIBOR.  The portion of the loan based on an “Alternate Base Rate” is determined by the rate per annum equal to 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. The credit facility includes a hedging component that provides a line of credit under commodity swap, exchange, collar, cap and fixed price agreements and agreements designated to protect the Company against changes in interest and currency exchange rates.

At June 30, 2012, there were approximately $13.8 million in outstanding borrowings and approximately $6.2 million of additional borrowing capacity available under the credit facility.  The Company’s effective borrowing rate at June 30, 2012 was 4.6%.  The credit facility is collateralized by substantially all of the Company’s oil and gas assets.  The credit facility includes terms that place limitations on certain types of activities and the payment of dividends, and requires satisfaction of a current ratio (the ratio of current assets (including borrowing base capacity) to current liabilities as defined) of 1.0 to 1.0 and a maximum Funded Debt Ratio (the ratio of the outstanding balance of all interest bearing indebtedness to the sum of EBITDAX (net income plus interest expense, income taxes, depreciation, depletion, amortization, exploration and impairment expenses and other non-cash charges) for the most recently completed fiscal quarter times four) of 4.25 to 1.0 as of the end of any fiscal quarter.

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

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

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Note 8 — Income Taxes

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

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

Note 9 — Stockholders’ Equity

Authorized and Issued Capital Stock

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

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

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

Stock Incentive Plan

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

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

Restricted Stock

The Company granted 80,000 and 1,610,000 shares of restricted stock for the three and six months ended June 30, 2012, respectively.  Restricted stock awards for employees vest ratably over a three-year service period and one-year for non-employee directors.  Compensation for restricted shares is measured at the grant date based on the fair value of the awards, determined by the closing price of the Company’s common stock on the grant date and the fair value is recognized on a straight line basis over the requisite service period (generally the vesting period).

Compensation cost recognized for restricted stock grants was approximately $112,000 and $216,000 for the three and six months ended June 30, 2012, respectively.  As of June 30, 2012, there was approximately $781,000 of total unrecognized compensation costs related to restricted stock.  This cost is expected to be recognized over the next 2.8 years.

Restricted Performance Units

During the first quarter of 2012 and for the six months ended June 30, 2012, the Company granted 1,290,000 restricted performance units.  The performance units represent a contractual right to receive one share of the Company’s common stock subject to the terms and conditions of the agreement including the relative achievement of the performance and the lapse of forfeiture restrictions pursuant to the terms and conditions of the agreement.

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The Company accounts for grants of restricted performance units at their intrinsic value, re-measured at each reporting period.  The final measurement of compensation costs is based on the performance units that ultimately vest and the market price at the date the performance criteria are met.  At June 30, 2012, the Company estimated that none of the performance units would vest and accordingly, no compensation cost has been recorded.  As of June 30, 2012, if all performance goals are achieved and forfeiture restrictions pursuant to the terms and conditions of the agreement are met, estimated unrecognized compensation cost would be approximately $400,000.

Note 10 — Accounts Payable and Accrued Liabilities

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

Note 11 — Fair Value Measurements

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

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

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

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

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.  The Company’s policy is to recognize transfers in or out of fair value hierarchies as of the end of the reporting period for which the event or change in circumstances caused the transfer.  The Company has consistently applied the valuation techniques discussed below for all periods presented.

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Note 11 — Fair Value Measurements (continued)

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2012 and December 31, 2011 by level within the fair value hierarchy:

As of June 30, 2012, the Company’s commodity derivative financial instruments are comprised of two natural gas swap agreements and two oil swap agreements.  The fair values of the swap agreements are determined under the income valuation technique using a discounted cash flow model.  The valuation model requires a variety of inputs, including contractual terms, published forward prices, volatilities for options, and discount rates, as appropriate.  The Company’s estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, the Company’s credit worthiness and the time value of money.  The consideration of these factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view.  All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s derivative instruments are included within the Level 2 fair value hierarchy. The counterparty in all of the Company’s commodity derivative financial instruments is the lender in the Company’s bank credit facility.

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

The Company uses the income valuation technique to estimate the fair value of asset retirement obligations using the amounts and timing of expected future dismantlement costs, credit-adjusted risk-free rates and time value of money.  Accordingly, the fair value is based on unobserverable pricing inputs and therefore, is included with the Level 3 fair value hierarchy.

Note 12 — Physical Delivery Contracts and Gas Derivatives

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

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

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

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Note 12 — Physical Delivery Contracts and Gas Derivatives (continued)

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

(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:

The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the three and six months ended June 30, 2012 and 2011.  These realized and unrealized gains and losses are recorded and included in commodity derivative gain in the accompanying consolidated statements of operations.

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

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

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

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Note 13 — Commitments

The Company assumed long-term firm transportation contracts in the ING Asset acquisition.  Capacity levels and related demand charges for the remaining term of the contracts at June 30, 2012 are (i) for the remainder of 2012 through 2013; approximately 7,700 dekatherms per day capacity with demand charges ranging between $0.22 and $1.40 per dekatherm, (ii) for 2014 through May 2015; 3,450 dekatherms per day with demand charges ranging between $0.22 and $0.65 and (iii) for June 2015 through 2017; 2,300 dekatherms per day with demand charges of $0.65 per dekatherm.  A liability of approximately $5.4 million related to firm transportation contracts assumed in the ING Asset acquisition, which represents the remaining commitment, is reflected on the Company’s consolidated balance sheets as of June 30, 2012.

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

Note 14 — Related Party Transactions

The Company previously engaged Nytis Exploration Company (“NEC”) to assist in the management, direction and supervision of the operations and business functions of the Company.  A service agreement between the Company, NEC and other related entities provided for the compensation of NEC in performing these duties. For the three and six months ended June 30, 2011, NEC charged the Company approximately $302,000 and $673,000 for general and administrative expenses pursuant to this service agreement.

The services agreement was terminated on June 30, 2011.  Effective July 1, 2011, the parties entered into a new agreement whereby the Company manages, directs and supervises the operations and business of NEC and other related entities.  The new agreement’s initial term of one year is automatically renewable for successive one-year terms.  For the three and six month period ended June 30, 2012, pursuant to the new service agreement, the Company charged NEC $45,000 and $90,000, respectively.

As of June 30, 2012, NEC and the other related entities owe the Company approximately $620,000.  This receivable consists primarily of charges incurred under the service agreement, short-term advances and reimbursement of other general and administrative expenses paid by Carbon.  This receivable is reflected in accounts receivable on the Company’s consolidated balance sheets.

Note 15 — Supplemental Cash Flow Disclosure

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

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

General Overview

All expectations, forecasts, assumptions and beliefs about our future results, condition, operations and performance are forward-looking statements as described under the heading “Forward Looking Statements” at the end of this Item.  Our actual results may differ materially because of a number of risks and uncertainties.  The following discussion and analysis should be read in conjunction with the Company’s Consolidated Financial Statements and Notes thereto and the information included or incorporated by reference in the Company’s 2011 Annual Report on Form 10-K as filed with the Securities and Exchange Commission (“SEC”) under the headings “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The Company is an independent natural gas and oil company engaged in the acquisition, exploration, development and production of natural gas and oil properties located in the Appalachian and the Illinois Basin of the United States.  The Company’s business is comprised of the assets and properties of Nytis USA and its subsidiaries Nytis LLC and Nytis Pennsylvania which conduct the Company’s operations in the Appalachian and Illinois Basins.  The Company focuses on conventional and unconventional reservoirs, including shale gas formations, tight gas sands and coalbed methane.  Our corporate headquarters are in Denver, Colorado.

At December 31, 2011, 93% of our estimated proved reserves were natural gas and, as a result, our financial results will be more sensitive to fluctuations in natural gas prices.  However as demonstrated by our recent capital expenditure programs, the Company is focused on developing its oil reserves while continuing to pursue acquisitions that complement our existing core programs.  We believe that our drilling inventory, combined with our operating expense and cost structure, provides us with meaningful organic growth opportunities.  Our growth plan is centered on the following activities:

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

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

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

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

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

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

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Results of Operations

The following discussion and analysis relates to items that have affected our results of operations for the three and six months ended June 30, 2012 and 2011.  The following tables set forth, for the periods presented, selected historical statements of operations data.  The information contained in the table below should be read in conjunction with the Company’s Consolidated Financial Statements and Notes thereto and the information under “Forward Looking Statements” below.

Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011