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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

For the quarterly period ended June 30, 2002

Or

For the transition period from            to            

Commission File Number: 1-15639

CARBON ENERGY CORPORATION
(Exact name of registrant as specified in its charter)

(303) 863-1555
(Registrant's telephone number, including area code)

Not Applicable
(Former name, former address and former 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 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 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 1.    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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CARBON ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(in thousands)

(unaudited)

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

4

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 STATEMENTS

(Unaudited)

1.    Nature of Operations

        Nature of Operation—Carbon Energy Corporation (Carbon) is an 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 exploration and production areas in the Unites States include the Piceance Basin in Colorado, the Uintah Basin in Utah, the Permian Basin in New Mexico, Kansas and Montana. The Company's exploration and production areas in Canada include Central Alberta and Southeast Saskatchewan.

        Carbon was incorporated in September 1999 under the laws of the State of Colorado to facilitate the acquisition of Bonneville Fuels Corporation (BFC) and subsidiaries. The acquisition of BFC closed on October 29, 1999 and was accounted for as a purchase. In February 2000, Carbon completed an offer to exchange shares of Carbon for shares of CEC Resources Ltd. (CEC), an Alberta, Canada company. The exchange offer resulted in the issuance of 1,482,826 shares of Carbon stock in exchange for over 97% of the outstanding CEC shares. The acquisition closed on February 17, 2000 and was also accounted for as a purchase. In November 2000, CEC initiated an offer to purchase additional shares of CEC. The offer was completed in February 2001 with the acquisition of approximately 34,000 shares of CEC stock. Carbon currently owns 99.7% of the stock of CEC. On July 11, 2002, Carbon changed the name of BFC to Carbon Energy Corporation (USA) (Carbon USA). Collectively, Carbon, CEC, Carbon USA and its subsidiaries are referred to as the Company.

        All amounts are presented in U.S. dollars.

        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 certain information and note disclosures required by accounting principles generally accepted in the United States for complete financial statements. 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's Annual Report on Form 10-K, for the year ended December 31, 2001, as filed with the SEC. The statements reflect all adjustments that, in the opinion of management, are necessary to fairly present the Company's financial position at June 30, 2002 and the results of operations and cash flows for the periods presented.

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, except CEC, of which the Company owns approximately 99.7%. All significant intercompany transactions and balances have been eliminated.

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

        Property and Equipment—The Company follows the full cost method of accounting for its oil and gas properties. 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.

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        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. The estimated future cost of site restoration, dismantlement and abandonment activities is provided for as a component of depletion. 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, total 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 un-escalated 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 value of unproved properties included in the costs being amortized, if any; less related income tax effects. At June 30, 2002, the Company's capitalized costs exceeded the ceiling limitation in the United States and Canada by $14.0 million and $2.4 million, respectively. When pricing at June 30, 2002 is adjusted for oil and natural gas hedges in place at June 30, 2002, the Company's capitalized costs exceeded the ceiling limitation in the United States and Canada by $12.0 million and $1.2 million, respectively. Accordingly, the Company recorded a $12.0 million and $1.2 million non-cash charge in the United States and Canada, respectively, to reflect the impairments. The impairments are included as additional accumulated DD&A in the accompanying balance sheet. Due to the volatility of commodity prices, should natural gas and crude oil prices decline in the future, even if only for a brief period of time, it is possible that additional impairments of 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.

        Undistributed Revenue—Represents revenue due to other 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 (overproduced) or less (underproduced) 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 will not be sufficient to enable the underproduced owner to recoup its share of production, revenue is deferred and a liability is created.

        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 tax rates in effect for the year in which the differences are expected to reverse.

        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.

        Pursuant to Company guidelines, the Company is to engage in these activities only as a hedging mechanism and may not enter into speculative transactions. The Company has a Risk Management

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Committee to administer and approve all production hedging 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. Gains or losses from financial instruments that do not qualify for hedge accounting treatment are recognized in the current period as other income or expense. 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 months and six months ended June 30, 2002 and 2001 (in thousands):

        The table below sets forth the Company's derivative financial instrument positions relating to its natural gas and oil production that qualify for hedge accounting treatment at June 30, 2002:

        Swaps:

        Collars:

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        In addition to the derivative contracts discussed above, the Company may enter into long-term sales contracts for a portion of its natural gas and oil production. The table below sets forth fixed price sales contracts at June 30, 2002:

        Fixed price contracts:

        During the first six months of 2002, net hedging gains of $91,000 ($55,000 after tax) were transferred from accumulated other comprehensive income to earnings. The change in the fair market value of outstanding derivative contracts designated as hedges decreased by $659,000 ($389,000 after tax). Oil and natural gas prices reflective of the Company's hedge contracts were correlative with the published indices used to sell the Company's production. As a result, no ineffectiveness was recognized related to the Company's hedge contracts during the first six months of 2002. As of June 30, 2002, the Company had net unrealized derivative losses of $322,000 ($194,000 after tax). Based on future indices for oil, natural gas and interest rates in effect on June 30, 2002, the Company expects to reclassify $209,000 of these net unrealized losses to earnings during the next twelve month period.

        Interest Rate Swap Agreements—During 2002, the Company entered into interest rate swap agreements that effectively convert 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 on future income. Gains or losses from financial instruments that qualify for hedge accounting treatment are recognized as an adjustment to interest expense in the period in which the financial instrument matures. Gains or losses from interest rate swaps that do not qualify for hedge accounting treatment are recognized in the current period as other income or expense. 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 June 30, 2002:

        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

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currency translation gains/(losses) of $499,000 and ($43,000) for the six months ended June 30, 2002 and 2001, 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 which are classified as other comprehensive income. The following table sets forth the calculation of comprehensive income for the six months ended June 30, 2002 and 2001:

        In 2001, the Company entered into certain commodity derivative contracts with Enron North America Corp. (ENAC), a subsidiary of Enron Corp. (Enron). On December 2, 2001, Enron and ENAC filed for Chapter 11 bankruptcy, and the Company determined that the ENAC contracts no longer qualified for cash flow hedge accounting under Statement of Financial Accounting Standards No. 133 (SFAS No. 133). Consequently, the Company recorded a loss for the year ended December 31, 2001, based on the estimated fair value of the derivative contracts based on future commodity prices and deferred a corresponding amount in accumulated other comprehensive income.

        The amount deferred in accumulated other comprehensive income at June 30, 2002 will be reclassified to earnings during the remainder of 2002 based on the originally scheduled settlement periods of the contracts. Amounts expected to be reclassified to earnings in the second half of 2002 are $124,000. Marketing and other revenue for the three and six months ended June 30, 2002 include $70,000 and $122,000, respectively, of amounts reclassified out of accumulated other comprehensive income related to these contracts.

        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 quarter and six months 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 June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141, "Business Combinations," which addresses financial accounting and reporting for business combinations. SFAS No. 141 is effective for all business combinations initiated after June 30, 2001. The adoption of SFAS No. 141 did not have a material impact on the Company's financial position or results of operations.

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        In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets," which addresses, among other things, the financial accounting and reporting for goodwill subsequent to an acquisition. The new standard eliminates the requirement to amortize acquired goodwill; instead, such goodwill shall be reviewed at least annually for impairment. SFAS No. 142 is effective for the Company in 2002. The adoption of SFAS No. 142 did not have a material impact on the Company's financial position or results of operations.

        In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which 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 liability will be allocated to operating expense by using a systematic and rational method. The statement is effective for fiscal years beginning after June 15, 2002. The Company is currently evaluating what effect the adoption of this statement will have on its financial statements.

        In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which provides a single accounting model for long-lived assets to be disposed of and changes the criteria that would have to be met to classify an asset as held-for-sale. The statement also requires expected future operating losses from discontinued operations to be recognized in the periods in which the losses are incurred, which is a change from the current requirement of recognizing such operating losses as of the measurement date. SFAS No. 144 is effective for the Company in 2002. The adoption of SFAS No. 144 did not have a material effect on the Company's financial position or results of operations.

3.    Acquisition and Disposition of Assets

        Acquisition of CEC Resources Ltd.—In February 2000, Carbon completed an offer to exchange shares of Carbon for shares of CEC, an Alberta, Canada company. The exchange offer resulted in the issuance of 1,482,826 shares of Carbon stock in exchange for over 97% of the outstanding CEC shares. The acquisition closed on February 17, 2000 and was accounted for as a purchase. In November 2000, CEC initiated an offer to purchase additional shares of CEC. The offer was completed in February 2001 with the acquisition of approximately 34,000 shares of CEC stock. Carbon currently owns 99.7% of the stock of CEC. See Note 1 to the Consolidated Financial Statements for additional information.

        Disposition of Oil and Gas Assets—In January 2001, the Company sold its entire working interests and related leasehold rights in the San Juan Basin, receiving net proceeds of approximately $6.8 million. Proceeds from the sale were credited directly to the full cost pool and no gain or loss was recognized.

4.    Long-term Debt

        U.S. Credit Facility—The Company's credit facility is an oil and gas reserve based line-of-credit with Wells Fargo Bank West National Association (Wells Fargo). At June 30, 2002, the borrowing base was $20.0 million with outstanding borrowings of $17.7 million. The facility is secured by certain U.S. oil and gas properties of the Company. The facility bears interest at a rate equal to LIBOR plus 1.75% or Wells Fargo Prime, at the option of the Company. The Company's weighted average effective interest rate was approximately 3.8% at June 30, 2002. The borrowing base is based upon the lender's evaluation of the Company's proved oil and gas reserves, generally determined semi-annually.

        In August 2002, the Company and Wells Fargo amended the credit facility to provide for a reduction to the borrowing base of $400,000 per month from September 2002 through January 2003, at which time the borrowing base will be $18.0 million. The amended facility has a maturity date of July 1, 2005 with no principal payments required until that date.

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        As a result of the full cost ceiling impairment discussed previously, as of June 30, 2002 the Company was not in compliance with the tangible net worth covenant under the credit facility. In conjunction with the amendment discussed above, no default was asserted by Wells Fargo and the covenant was amended to reduce the minimum tangible net worth requirement. As of June 30, 2002, the Company would have had a "cushion" of approximately $900,000 based on the amended tangible net worth requirement. Based on the Company's net income projections, management expects to be in compliance with the revised tangible net worth through at least the next twelve months.

        Canadian Credit Facility—The Company's credit facility is an oil and gas reserve based line-of-credit with Canadian Imperial Bank of Commerce (CIBC). At June 30, 2002 the borrowing base was $9.2 million with outstanding borrowings of $5.5 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, 2003. 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 July 2003 at the earliest. As such, no amounts under the CIBC facility have been classified as current on the June 30, 2002 balance sheet. The Canadian facility bears interest at a rate equal to banker's acceptance rates plus 1.5% or at the CIBC Prime rate plus .5%. The Company's weighted average effective interest rate was approximately 4.75% at June 30, 2002.

        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 agreement with CIBC also provides for $3.5 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 2 to the Consolidated Financial Statements.

5.    Business and Geographical Segments

        Segment information has been prepared in accordance with SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." Carbon has two reportable business and geographic segments: Carbon USA and CEC, representing oil and gas operations in the United States and Canada, respectively. The segments are business units that operate in unique geographic locations.

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The segment data presented below for the three and six months ended June 30, 2002 and 2001 was prepared on the same basis as Carbon's consolidated financial statements.

6.    Subsequent Event

        In July 2002, the Company closed the sale of certain overriding royalty interests in the Piceance and Permian Basins, receiving net proceeds of approximately $700,000. The proceeds were used to repay amounts outstanding under the Company's credit facilities.

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Item 2.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Results of Operations

        The following table and discussion present comparative revenue, production volumes, average sales prices, expenses and percentage change between periods for the three months ended June 30, 2002 and June 30, 2001 (second quarter) for the Company's United States and Canadian operations.

        All amounts are presented in U.S. dollars.

        Revenues from oil and gas sales of Carbon USA for the second quarter of 2002 were $2.2 million, an 11% decrease from 2001. The decrease was due primarily to decreased oil and natural gas prices, partially offset by increased oil, liquids and natural gas production.

        Revenues from oil, liquids and gas sales of CEC for the second quarter of 2002 were $1.8 million, a 44% decrease from 2001. The decrease was due primarily to decreased oil, liquids and natural gas prices and a decrease in oil, liquids and natural gas production.

        Average production in the United States for the second quarter of 2002 was 242 barrels of oil and liquids per day and 8.4 million cubic feet (MMcf) of gas per day, an increase of 15% from the same period in 2001 on a Mcf equivalent (Mcfe) basis where one barrel of oil or liquids is equal to six Mcf of gas. The increase in oil, liquids and gas production was due to successful drilling activities conducted during 2001 in the Piceance and Permian Basins, partially offset by natural production declines. During the second quarter of 2002, Carbon USA participated in the drilling of one gross (.1 net) well which was completed as an oil well. During the second quarter of 2001, Carbon USA participated in the drilling of five gross (2.2 net) wells of which two gross (.3 net) wells were completed as oil wells and three gross (1.9 net) wells were completed as gas wells.

        Average production in Canada for the second quarter of 2002 was 139 barrels of oil and liquids per day and 6.4 MMcf of gas per day, a decrease of 5% on a Mcfe basis from the same period in 2001.

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The decrease was primarily due to natural production declines in all operating areas, partially offset by successful drilling activities in the Carbon and Rowley areas of Central Alberta. During the second quarter of 2002, CEC participated in the drilling of four gross (2.7 net) wells which were completed as gas wells. During the second quarter of 2001, CEC participated in the drilling of two gross (2.0 net) wells which were completed as gas wells.

        Average oil and liquids prices realized by Carbon USA decreased 13% from $26.61 per barrel for the second quarter of 2001 to $23.17 for 2002. Average natural gas prices realized by Carbon USA decreased 26% from $2.94 per Mcf for the second quarter of 2001 to $2.19 for 2002. The average natural gas price includes hedge gains of $13,000 for the second quarter of 2002 compared to hedge losses of $757,000 for 2001.

        Average oil and liquids prices realized by CEC decreased 18% from $24.48 per barrel for the second quarter of 2001 to $20.04 for 2002. Average natural gas prices realized by CEC decreased 43% from $4.86 per Mcf for the second quarter of 2001 to $2.76 for 2002. The average natural gas price includes hedge losses of $79,000 for the second quarter of 2002 compared to hedge losses of $202,000 for 2001.

        Marketing and other revenues in the United States were $101,000 for the second quarter of 2002 compared to $565,000 for 2001. Marketing revenue for the second quarter of 2001 included mark to market gains of $451,000 related to a derivative contract that did not qualify for hedge accounting treatment under Statement of Financial Accounting Standard (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." In conjunction with the adoption of SFAS No. 133, the Company recorded a derivative loss (net of tax) of $1.5 million as the cumulative effect of a change in accounting principle related to the derivative contract.

        Direct lifting costs incurred by Carbon USA were $373,000 or $.41 per Mcfe for the second quarter of 2002 compared to $489,000 or $.63 per Mcfe for 2001. The decrease in direct lifting costs was primarily due to more efficient field operating practices as well as a decrease in the number of well workovers and equipment repairs compared to the second quarter of 2001.

        Other production costs incurred by Carbon USA, consisting primarily of severance taxes and production overhead, were $455,000 for the second quarter of 2002 compared to $487,000 for 2001. The decrease was primarily due to lower severance taxes as a result of lower oil, liquids and gas prices and a credit for prior period ad valorem taxes, partially offset by increased oil, liquids and gas production.

        Direct lifting costs incurred by CEC were $382,000 or $.58 per Mcfe for the second quarter of 2002 compared to $285,000 or $.41 per Mcfe for 2001. The higher per Mcfe expense in the second quarter of 2002 was primarily due to higher compression expenses associated with the production of natural gas in Alberta and a change of estimate of certain operating expenses related to non-operated properties which were recorded in the second quarter of 2002.

        Other production costs incurred by CEC, consisting primarily of severance taxes, were $16,000 for the second quarter of 2002. There were no such other production costs incurred during the second quarter of 2001. The increase was primarily due to production during the second quarter of 2002 from wells subject to severance taxes.

        General and administrative expenses (net of overhead reimbursements on operated wells) incurred by Carbon USA decreased 3% from $767,000 for the second quarter of 2001 to $746,000 for 2002.

        General and administrative expenses (net of overhead reimbursements on operated wells) incurred by CEC decreased 8% from $451,000 for the second quarter of 2001 to $415,000 for 2002.

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        Interest expense incurred by Carbon USA increased 12% from $185,000 for the second quarter of 2001 to $207,000 for 2002. The increase was due primarily to increased average debt balances in the second quarter of 2002 relative to 2001, partially offset by a decline in interest rates.

        Interest expense incurred by CEC increased 36% from $39,000 for the second quarter of 2001 to $53,000 for 2002. The increase was due primarily to increased average debt balances in the second quarter of 2002 relative to 2001, partially offset by a decline in interest rates.

        Depreciation, depletion and amortization (DD&A) of oil and gas assets is calculated using the units of production method. DD&A is typically determined by using historical capitalized costs incurred to find, develop and recover oil and gas reserves. However, the Company's DD&A rate has been determined primarily by the purchase price incurred by the Company in its acquisitions of Carbon USA and CEC and the volume of proved reserves the Company acquired in the acquisitions.

        DD&A expense incurred by Carbon USA was $1.0 million or $1.15 per Mcfe for the second quarter of 2002 compared to $804,000 or $1.03 per Mcfe for 2001. The increased rate is due to the capitalized cost per Mcfe of reserves added to the Company's proved reserves during 2001 compared to the rate established at the time of the acquisition of Carbon USA.

        DD&A expense incurred by CEC was $663,000 or $1.01 per Mcfe compared to $644,000 or $.94 per Mcfe for 2001. The increased rate is due to the capitalized cost per Mcfe of reserves added to the Company's proved reserves during 2001 compared to the rate established at the time of the acquisition of CEC.

        For purposes of calculating the ceiling test at June 30, 2002, the Company used mainline prices of $1.10/mmbtu in Colorado and Utah and $1.43/mmbtu in Central Alberta. The negative differential of these prices when compared to a U.S. reference price set at Henry Hub at June 30, 2002, was $2.32/mmbtu for Colorado and Utah and $1.99/mmbtu for Central Alberta. This compares to a 36 month historical negative differential of $.37/mmbtu for Colorado and $.29/mmbtu for Central Alberta. Due to these large pricing differentials when compared to a U.S. reference price set at Henry Hub at June 30, 2002, the Company's capitalized costs exceeded the ceiling limitation in the United States and Canada by $14.0 million and $2.4 million, respectively. When pricing at June 30, 2002 is adjusted for oil and natural gas hedges in place at June 30, 2002, the Company's capitalized costs exceeded the ceiling limitation in the United States and Canada by $12.0 million and $1.2 million, respectively. Accordingly, the Company recorded a $12.0 million and $1.2 million non-cash charge in the United States and Canada, respectively, to reflect these impairments. See Note 2 to the Consolidated Financial Statements for additional information.

        Income tax expense recorded by Carbon USA was $1.1 million for the second quarter of 2002, an effective tax rate of (9%), compared to an expense of $113,000 and an effective tax rate of 37% for 2001. Due primarily to the low commodity prices resulting in the full cost ceiling impairment recorded during the second quarter of 2002, the Company recorded a deferred tax asset valuation allowance of $5.5 million during the second quarter of 2002.

        Income tax benefit incurred by CEC was $424,000 for the second quarter of 2002, an effective tax rate of 47%, compared to an expense of $745,000 and an effective tax rate of 40% for 2001. The increase in the effective tax rate for the second quarter of 2002 was due to an adjustment of deferred taxes related to changes in the statutory tax rates. The income tax benefit related to the above mentioned full cost ceiling impairment was $517,000.

        The following table and discussion present comparative revenue, production volumes, average sales prices, expenses and the percentage change between periods for the six months ended June 30, 2002 and 2001 for the Company's United States and Canadian operations.

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        All amounts are presented in U.S. dollars.