UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

CARBON ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

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 ý No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act)  Yes o No ý

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

CARBON ENERGY CORPORATION

INDEX

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PART I - FINANCIAL INFORMATION

Item 11.    FINANCIAL STATEMENTS.           FINANCIAL STATEMENTS

CARBON ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(in thousands)

(unaudited)

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED BALANCE SHEETS

(in thousands)

(unaudited)

The accompanying notes are an integral part of these consolidated financial statements.

3

CARBON ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONSBALANCE SHEETS

(in thousands, except per share data)thousands)

(unaudited)

The accompanying notes are an integral part of these consolidated financial statements.

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CARBON ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(unaudited)

  The accompanying notes are an integral part of these consolidated financial statements. 

5

CARBON ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

The accompanying notes are an integral part of these consolidated financial statements.

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CARBON ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTSSTATEMENTS

(unaudited)

1.         Nature of Operations

Nature of Operations –- Carbon Energy Corporation (the Company or Carbon) is an independent oil and gas company engaged in the exploration, development and production of natural gas and crude oil in the United States and Canada.  The Company’s areas of operations in the United States are the Piceance Basin in Colorado, the Uintah Basin in Utah and Montana.  The Company’s areas of operations in Canada are central and northwest Alberta and southeast Saskatchewan.

The Company’s business is comprised of the assets and properties of Carbon Energy Corporation (USA) (Carbon USA), which conducts the Company’s operations in the United States, and the assets and properties of Carbon Energy Canada Corporation (Carbon Canada), which conducts the Company’s operations in Canada.  Effective July 11, 2002, Carbon changed the name of its United States subsidiary from Bonneville Fuels Corporation (Bonneville Fuels) to Carbon Energy Corporation (USA).  Effective March 1, 2003, Carbon changed the name of its Canadian subsidiary from CEC Resources Ltd. (CEC Resources) to Carbon Energy Canada Corporation.  As the parent company, Carbon provides management services to Carbon USA and Carbon Canada.  Collectively, Carbon, Carbon Canada, Carbon USA and their subsidiaries are referred to as the Company.

Carbon was incorporated in September 1999 under the laws of the State of Colorado to facilitate the acquisition of Carbon USA and subsidiaries. The acquisition of Carbon USA closed on October 29, 1999 and was accounted for as a purchase. In February 2000, Carbon completed an offer to exchange common shares of Carbon for shares of Carbon Canada, an Alberta, Canada company. Over 97% of the shareholders of Carbon Canada accepted the offer for exchange. This acquisition closed on February 17, 2000 and was also accounted for as a purchase. In November 2000, Carbon Canada initiated an offer to purchase additional shares of Carbon Canada stock that were not owned by Carbon. The offer was completed in February 2001 with the acquisition of approximately 34,000 of the 39,000 shares of Carbon Canada stock that were not owned by Carbon. In October 2002, Carbon Canada amended its articles to consolidate its issued and outstanding common shares on a one-for-2,500 basis.  In November 2002, Carbon Canada initiated the exchange of common shares for post-consolidation shares or a cash payment in lieu of fractional post-consolidated shares.  The exchange was completed in January 2003, after which Carbon owned 100% of the stock of Carbon Canada.

On March 31, 2003, Carbon announced that it had entered into an Agreement and Plan of Reorganization (the Merger Agreement) with Evergreen Resources, Inc. (Evergreen).  Under the Merger Agreement, Carbon will merge with a subsidiary of Evergreen, and Carbon stockholders will receive .275 shares of Evergreen common stock for each outstanding share of Carbon common stock (and cash in lieu of any fractional shares).  This ratio is prior to the two-for-one split of Evergreen common stock for shareholders of record on August 29, 2003 announced by Evergreen on July 31, 2003.  As a result of the merger, Carbon will become a wholly owned subsidiary of Evergreen.  The merger is intended to be a tax-free, stock-for-stock transaction.  At the time of execution of the agreement, each of Yorktown Energy Partners III, L.P. and Patrick R. McDonald, President and Chief Executive Officer of Carbon, who own approximately 73.2%71.7% and 3.8%4.1%, respectively, of Carbon’s outstanding common stock, had executed an agreement with Evergreen obligating each of them to vote all shares over which it hasthey have voting control in favor of the merger.

Completion of the merger, which is subject to customary conditions, including approval by the stockholders of Carbon, is expected to occur in the third quarter of 2003.  The Merger Agreement contains a $2.5 million termination fee payable by Carbon if the Merger Agreement is terminated under certain circumstances.

Basis of Presentation - The unaudited financial statements presented herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). The statements do not include certainall information and note disclosures required by accounting principles generally accepted in the United States for complete financial

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statements. TheIt is suggested that the accompanying consolidated financial statements of the Company should be read in conjunction with the consolidated financial statements and notes thereto included in the Company'sCompany’s Annual Report on Form

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Forms 10-K and 10-K/A for the year ended December 31, 2002, as filed with the SEC. The statements reflect all adjustments that, in the opinion of management, are necessary to fairly present the Company'sCompany’s financial position at March 31,June 30, 2003 and the results of its operations and its cash flows for the periods presented.

All amounts are presented in U.S. dollars.

2.             Significant Accounting Policies

Principles of Consolidation - The consolidated financial statements include the accounts of Carbon and its subsidiaries, all of which are wholly owned. All significant intercompany transactions and balances have been eliminated.

Cash Equivalents – The Company considers all highly liquid instruments with original maturities of three months or less when purchased to be cash equivalents.

Property and Equipment - - The Company follows the full cost method of accounting for its oil and gas properties, whereby all costs incurred in the acquisition, exploration and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and direct overhead related to exploration and development activities) are capitalized.

Capitalized costs are accumulated for the United States and Canada as separate cost centers and are depleted using the units of production method based on proved reserves of oil and gas. For purposes of the depletion calculation, oil and gas reserves are converted to an equivalent unit of measure where six thousand cubic feet of gas is equal to one barrel of oil. For periods prior to January 1, 2003, the estimated future cost of site restoration, dismantlement and abandonment activities was provided for as a component of depletion (see discussion of asset retirement costs and obligations below). Investments in unproved properties are recorded at the lower of cost or fair market value and are not depleted pending the determination of the existence of proved reserves.

Pursuant to full cost accounting rules, capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of the present value of future net revenues from estimated production of proved oil and gas reserves using a 10% discount factor and unescalated oil and gas prices and costs as of the end of the period; plus the cost of properties not being amortized, if any; plus the lower of cost or estimated fair market value of unproved properties included in the costs being amortized, if any; less related income tax effects. At March 31,June 30, 2003, the costs reflected in the accompanying financial statements did not exceed the ceiling limitation in either the United States or Canada.  Should natural gas and oil prices decline in the future, it is possible that impairments of the Company’s oil and gas properties could occur.

Proceeds from disposal of interests in oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the rate of depletion.

Buildings, transportation and other equipment are depreciated on the straight-line method with lives ranging from three to seven years.

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Asset Retirement Costs and Obligations – - The Company adopted the provisions of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143) on January 1, 2003.  This statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made.  The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The asset retirement obligation is allocated to operating expense using a systematic and rational method.

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Upon adoption of the statement, the Company recorded an asset retirement obligation of approximately $3.0 million, an addition to oil and gas properties of approximately $3.5 million and a credit of approximately $336,000 (net of tax) for the cumulative effect of change in accounting principle. At March 31,June 30, 2003, the asset retirement obligation is recorded in other long-term liabilities.  Below is a reconciliation of the beginning and ending aggregate carrying amount of the Company’s asset retirement obligations as of March 31,June 30, 2003:

The following table summarizes the pro forma net income and earnings per share for the threesix months ended March 31,June 30, 2002 and for the years ended December 31, 2002, 2001 and 2000 had the change in accounting been implemented on January 1 of the respective years:

The difference in the as reported and pro forma net income include the effects of the accretion of the asset retirement obligation and a decrease in depletion expense as a result of adopting SFAS No. 143.

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In addition, had the Company adopted the provisions of SFAS No. 143 prior to January 1, 2003, the amount of the asset retirement obligationsobligation on a pro forma basis would have been as follows:

Undistributed Revenue - Represents revenue due to third party owners of jointly owned oil and gas properties.

Revenue Recognition - - The Company follows the sales method of accounting for natural gas revenues. Under this method, revenues are recognized based on the actual volume of gas sold to purchasers. To the extent the volumes of gas sold are more (over produced) or less (under produced) than the volumes to which the Company is entitled based on its interests in its properties, a gas imbalance may be created. If the estimated remaining reserves of a property are insufficient to enable the underproduced owner to recoup its share of production, a liability is created.

Transportation Costs - - Gathering and transportation costs incurred by the Company are included as components of oil and gas production costs in the accompanying statements of operations.  Under the Company’s sales contracts for the six months ended June 30, 2003 and 2002, purchasers assumed all obligations under transportation agreements.  As a result, the Company did not incur any transportation costs during this time.

Income Taxes - The Company accounts for income taxes using the liability method which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the book and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.

Foreign Currency Translation - Foreign currency transactions and financial statements are translated in accordance with SFAS No. 52, “Foreign Currency Translation.” The Company uses the U.S. dollar as the functional currency for its U.S. operations and the Canadian dollar as the functional currency for its Canadian operations. Assets and liabilities related to the Company’s Canadian operations are generally translated at the current exchange rate in effect as of the date of the balance sheet. Translation adjustments are reported as a component of stockholders’ equity. Income statement accounts are translated at the average exchange rates during the reporting period. As a result of the change in the value of the Canadian dollar relative to the U.S. dollar, the Company reported non-cash currency translation gains/(losses)gains of $773,000$1.8 million and ($6,000)$499,000 for the threesix months ended March 31,June 30, 2003 and 2002, respectively.

Comprehensive Income - The Company follows the provisions of SFAS No. 130, “Reporting Comprehensive Income.” Comprehensive income includes net income and certain items recorded directly to stockholders’ equity and are classified as other comprehensive income.

Stock-Based Compensation - The Company applies APB Opinion (APB) No. 25 “Accounting for Stock Issued to Employees” and related interpretations in accounting for its employee stock options.  Under APB No. 25, compensation expense is recognized for the difference between the option price and market value on the measurement date.  No compensation expense was recognized for the threesix months ended March 31,June 30, 2003 and 2002 as the exercise price of the stock options granted under the plan equaled the market price of the underlying stock on the date of grant.

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The Company applies SFAS No. 123 “Accounting for Stock-Based Compensation,” and related literature in accounting for stock-based awards granted to non-employees other than directors.  Under SFAS No. 123, stock-based awards granted to non-employees other than directors are recorded at fair value and recognized in the period(s) in which goods and/or services are received from the non-employee.  To date, the Company has never granted stock-based awards to non-employees other than directors.

If compensation costs for this plan had been determined consistent with SFAS No. 123, “Accounting for Stock-Based Compensation,” the Company’s net income (loss) and earnings (loss) per share would have been as follows:

The fair value of each option grant is estimated on the date of the grant using the Black-Scholes option pricing model with the following assumptions:

Earnings (Loss) Per Share - - The Company uses the weighted average number of shares outstanding to calculate earnings per share data. When dilutive, options are included as share equivalents using the treasury stock method and are included in the calculation of diluted per share data. Due to the Company’s net loss for the three monthsmonth periods ended March 31,June 30, 2003 and 2002 and the six month period ended June 30, 2002, basic and diluted earnings per share are the same, as all potentially dilutive securities would be anti-dilutive.

Accounting Estimates - The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in these financial statements and the accompanying notes. The actual results could differ from those estimates.

Recent Accounting Pronouncements - In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated With Exit or Disposal Activities,” which provides guidance for financial accounting and reporting of costs associated with exit or disposal activities.  This statement requires the recognition of a liability for a cost associated with an exit or disposal activity when the liability is incurred, as opposed to when the entity commits to an exit plan as previously required under EITF No. 94-3.  The adoption of SFAS No. 146 on January 1, 2003, had no impact on the Company’s financial position or results of operations.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.”  SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities.”  SFAS No. 149 is generally effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003.  The Company does not expect the adoption of this statement to have a material effect on its financial statements.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.”  SFAS No. 150 establishes standards for how an issuer measures certain financial instruments with characteristics of both liabilities and equity and requires that an issuer classify a financial instrument within its scope as a liability (or asset in some circumstances).  SFAS No. 150 was effective for financial instruments entered into or modified after May 31, 2003 and otherwise was effective and adopted by the Company on July 1, 2003.  As the Company has no such instruments, the Company’s adoption of this statement did not have an

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impact on its financial condition or results of operation.

The Financial Accounting Standards Board (FASB) and representatives of the accounting staff of the Securities and Exchange Commission are currently engaged in discussions regarding the application of certain provisions of SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets,” to companies in the extractive industries, including oil and gas companies.  The FASB and the SEC staff are considering whether the provisions of SFAS No. 141 and SFAS No. 142 require registrants to classify costs associated with mineral rights, including both proved and unproved lease acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures.

Historically, the Company has included oil and gas lease acquisition costs as a component of oil and gas properties. In the event it is determined that costs associated with mineral rights are required to be classified as intangible assets, a substantial portion of the Company’s oil and gas property acquisition costs since the June 30, 2001 effective date of SFAS Nos. 141 and 142 would be separately classified on the balance sheets as intangible assets.  However, the Company’s results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full cost accounting rules.  Further, the Company does not believe the classification of oil and gas lease acquisition costs as intangible assets would have any impact on the Company’s compliance with covenants under its debt agreements.

3.         Acquisition and Disposition of Assets

Disposition of Oil and Gas Assets - In July 2002, the Company sold certain overriding royalty interests in the Piceance and Permian Basins, receiving net proceeds of approximately $700,000.  Proceeds from the sale were credited directly

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to the full cost pool and no gain or loss was recognized.  The proceeds were used to repay amounts outstanding under the Company’s credit facilities.

In September 2002, the Company sold its entire working interests and related leasehold rights in Kansas, receiving net proceeds of approximately $2.1 million.  Proceeds from the sale were credited directly to the full cost pool and no gain or loss was recognized.  The proceeds were used to repay amounts outstanding under the Company’s credit facilities.

On March 24, 2003, Carbon USA closed on the sale of its interests in oil and gas properties located primarily in the Permian Basin of southeast New Mexico.  Net proceeds from the sale, after normal closing adjustments, were $14.4 million.  Proceeds from the sale were credited directly to the full cost pool and no gain or loss was recognized.  A portion of the proceeds from the sale were used to repay borrowings under the Company’s U.S. credit facility.

4.         Long-term Debt

U.S. Facility – On December 31, 2002, the Company obtained a credit facility from the Bank of Oklahoma, National Association (Bank of Oklahoma).  Borrowings under the Bank of Oklahoma credit facility were used to repay outstanding borrowings under the Company’s previous credit facility with Wells Fargo Bank West National Association.  The facility had an initialhas a borrowing base of $19.0 million that was reduced to $14.0 million on March 24, 2003 as a result of the Company’s sale of its interests in oil and gas properties located primarily in the Permian Basin of southeast New Mexico.  The Company used a portion of the proceeds from the Permian Basin sale to repay outstanding borrowings under the new credit facility and at March 31,June 30, 2003 outstanding borrowings under the new credit facility were $10.7$4.7 million.

The facility has a maturity date of October 2005 with no principal payments required until maturity.  The interest rates on amounts borrowed under the facility vary depending upon outstanding borrowings as a percentage of the borrowing base.  The Company’s weighted average interest rate was 3.9%3.2% at March 31,June 30, 2003.

The facility is secured by certain U.S. oil and gas properties of the Company and contains various convenants which prohibit or limit the Company’s ability to pay dividends, purchase treasury shares, incur indebtedness, sell properties or merge with another entity.  The Company is also be required to maintain certain financial ratios.  The Company was in compliance with all debt covenants at March 31,June 30, 2003.

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The Company has been informed by Evergreen that the credit facility with the Bank of Oklahoma is expected to be repaid in full at the time of the proposed merger of the Company with Evergreen.

Canadian Credit Facility – Carbon Canada’s credit facility is an oil and gas reserve based line-of-credit with Canadian Imperial Bank of Commerce (CIBC). In May 2003, the Company secured an increase in the borrowing base of the facility with CIBC to approximately $15.0$16.2 million from approximately $10.9$11.8 million.  At March 31,June 30, 2003 outstanding borrowings were $10.5$11.6 million.  The Canadian facility is secured by the Canadian oil and gas properties of the Company. The revolving phase of the Canadian facility expires on March 31, 2004. If the revolving commitment is not renewed, the loan will be converted into a term loan and will be reduced by consecutive monthly payments over a period not to exceed 24 months. Subject to possible changes in the borrowing base, CIBC has agreed that it will not require the Company to make principal payments under the term loan section of the facility until AprilJuly 2004 at the earliest. As such, no amounts under the CIBC facility have been classified as current at March 31,June 30, 2003.  The Canadian facility bears interest at a rate equal to banker’s acceptance rates plus 1.25% or at the CIBC Prime rate plus .5%. The Company’s weighted average interest rate was 5.25%5.5% at March 31,June 30, 2003.

The Canadian facility contains various covenants that limit the Company’s ability to pay dividends, purchase treasury shares, incur indebtedness, sell properties, or merge with another entity.  The Company was in compliance with all debt covenants at March 31,June 30, 2003.

The agreement with CIBC also provides for $5.0 million of credit which can be utilized for  financial derivative instruments used to hedge a portion of the Company’s oil and gas production, currency exchange contracts and fixed price gas sales transactions with CIBC.  The Company currently utilizes the swap facility to hedge a portion of its Canadian production as described in Note 5.

11The Company has obtained the consent of CIBC to the merger of the Company with Evergreen.

5.     ��                     Derivative Instruments

Interest Rate Swap Agreements - During 2002, the Company entered into interest rate swap agreements that effectively converted a portion of its variable rate borrowings in the United States to fixed rate debt for periods of up to two years, reducing the impact of interest rate increases or decreases on future income. Quarterly settlements from interest rate swaps that qualify for hedge accounting treatment are recognized as an adjustment to interest expense. Changes in the fair value of interest rate swaps that do not qualify for hedge accounting treatment are recognized in the current period as a component of other revenue.revenues, net. The cash flows from such agreements are included in operating activities in the consolidated statements of cash flow. The table below sets forth the Company’s interest rate derivative contracts in place at March 31,June 30, 2003:

During the first threesix months of 2003, net hedging losses of $59,000$68,000 ($37,00042,000 after tax) relating to interest rate derivative contracts designated as hedges were transferred from accumulated other comprehensive income to earnings.  The fair value of outstanding interest rate derivative contracts designated as hedges decreased by $17,000 ($10,000 after tax). In March 2003, Carbon USA closed on the sale of its interest in oil and gas properties located primarily in the Permian Basin of southeast New Mexico.  Proceeds from the sale were used to repay borrowings under the

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Company’s U.S. credit facility with Bank of Oklahoma.  As a result of this use of proceeds, the Company no longer had variable rate borrowings underlying certain of its interest rate swap agreements. As a result, the Company discontinued hedge accounting for these interest rate swaps and recorded a non-cash chargeduring the first six months of $175,0002003 recognized expenses of $182,000 ($109,000113,000 after tax).  As of June 30, 2003, the Company had net unrealized interest derivative losses of $138,000 ($86,000 after tax) that have been recorded to income, related to the change in the fair value of these interest rate swap agreements. As of March 31, 2003, the Company also had net unrealized derivative losses of $19,000 ($12,000 after tax) related to its interest rate swap agreements.  The Company expects to reclassify these unrealized losses to earnings during the next twelve month period.

Commodity Derivative Instruments and Hedging Activities - The Company may use certain financial instruments including swaps, collars, futures and other contracts in an attempt to reduce exposure to market fluctuations in the price of oil and natural gas.

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Pursuant to Company guidelines, the Company is to engage in these activities only as a hedging mechanism and may not enter into speculative transactions. Gains or losses from financial instruments that qualify for hedge accounting treatment are recognized as an adjustment to sales revenue in the period in which the financial instrument matures. Changes in the fair value of financial instruments that do not qualify for hedge accounting treatment are recognized during the current period as a component of other revenue.revenues, net. The cash flows from such agreements are included in operating activities in the consolidated statements of cash flows. The following table sets forth the hedge gains (losses) realized by the Company for the three monthsand six-month periods ended March 31,June 30, 2003 and 2002 (in thousands):

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The table below sets forth the Company’s derivative financial instrument positions relating to its natural gas and oil production at March 31,June 30, 2003:

Swaps:

The Company periodically enters into long-term physical sales contracts for a portion of its natural gas and oil production. The table below sets forth physical fixed price and costless collar sales contracts at March 31,June 30, 2003: