**SECURITES AND EXCHANGE COMMISSION**

**Washington D.C. 20549**

 

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###### **FORM10-K**

 

**Annual Report Pursuant to Section13 or 15(d)of the Securities Exchange Act of 1934**

 

**For the FiscalYear Ended December 31, 2002**

 

**Commission File Number 1-15639**

 

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| **CARBON ENERGY CORPORATION**                                                |
|------------------------------------------------------------------------------|
| (Exact name of  Registrant as specified in its Charter)                      |
|                                                                         |   |   |
| **Colorado**                                                                 |   | **84-1515097** |
| (State of Incorporation)                                                     |   | (I.R.S.  Employer  Identification No.) |
|                                                                         |   |   |
| **1700 Broadway, Suite 1150  Denver, Colorado**                              |   | **80290** |
| (Address of principal executive offices)                                     |   | (Zip Code) |
|                                                                         |   |   |
| Registrants telephone number, including area code:  **(303)  863-1555** |
|                                                                         |   |   |
| Securities registered pursuant to Section 12(b) of the Act:                  |

 

| **Title of each class**      |   | **Name of Exchange on which registered** |
|------------------------------|--------|------------------------------------------|
|                         |   |                                     |
| Common Stock, (no par value) |   | American Stock Exchange                  |

 

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

 

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Indicateby check mark whether the registrant (1) has filed all reports required to befiled by Section 13 or 15(d) of the Securities Exchange Act of 1934 during thepreceding 12 months, and (2) has been subject to such filing requirements forthe past 90 days.  Yes ý  No o

 

Indicateby check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K is not contained herein, and will not be contained, to the bestof registrant’s knowledge, in definitive proxy or information statementsincorporated by reference in Part III of this Form 10-K or any amendment tothis Form 10-K.  ý

 

Indicateby check mark whether the registrant is an accelerated filer (as defined inRule 12b-2 of the Exchange Act).  Yes o  No ý

 

Theaggregate market value of the 1,107,714 shares of voting stock held bynon-affiliates of the registrant, based upon the closing sale price of thecommon stock on June 30, 2002 of $9.69 per share as reported on the AmericanStock Exchange, was $10,733,749.  Sharesof common stock held by each officer and director and by each person who owns5% or more of the outstanding common stock have been excluded in that such personsmay be deemed affiliates.  This determinationof affiliate status is not necessarily a conclusive determination for otherpurposes.

 

Asof March 19, 2003, the registrant had 6,150,323 shares of common stockoutstanding.

 

TheCompany’s Proxy Statement for the 2003 Annual Meeting of Shareholders isincorporated by Reference into Part III

 

 

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**PART I**

 

# **ITEM 1.                 BUSINESS**

 

## GENERAL

 

Carbon Energy Corporation (the Company or Carbon) was incorporated onSeptember 14, 1999 under the Colorado Business Corporation Act.  The Company’s business is comprised of theassets and properties of Carbon Energy Corporation (USA) (Carbon USA), whichconducts the Company’s operations in the United States and the assets andproperties of Carbon Energy Canada Corporation (Carbon Canada), which conductsthe Company’s operations in Canada. Effective July 11, 2002, Carbon changed the name of its United Statessubsidiary from Bonneville Fuels Corporation (Bonneville Fuels) to CarbonEnergy Corporation (USA).  EffectiveMarch 1, 2003, Carbon changed the name of its Canadian subsidiary from CECResources Ltd. (CEC Resources) to Carbon Energy Canada Corporation.  As the parent company, Carbon providesmanagement services to Carbon USA and Carbon Canada.

 

Carbonis an independent oil and gas company engaged in the exploration, developmentand production of natural gas and crude oil in the United States andCanada.  The Company’s areas ofoperations in the United States are the Piceance Basin in Colorado, the UintahBasin in Utah, the Permian Basin in New Mexico and Texas, and Montana.  The Company’s areas of operations in Canadaare central Alberta and southeast Saskatchewan.

 

Allamounts are presented in U.S. dollars unless otherwise noted.

 

AtDecember 31, 2002, the Company had 67.4 billion cubic feet of natural gasequivalent (“Bcfe” where one barrel of oil is equivalent to six thousand cubicfeet of gas) proved reserves compared to 59.0 Bcfe at December 31,2001.  Proved reserves atDecember 31, 2002 increased by 8.4 Bcfe or 14% compared toDecember 31, 2001.  Net proved naturalgas reserves totaled 62.5 Bcf of gas at December 31, 2002 compared to 53.9Bcf at year end 2001, an increase of 8.6 Bcf or 16%.  Crude oil and natural gas liquids at December 31, 2002totaled 822,000 barrels compared to 851,000 barrels at year end 2001, adecrease of 29,000 barrels or 3%.  Ofthese proved reserves, approximately 93% on a Mcfe basis are gas andapproximately 74% are categorized as proved developed.  At December 31, 2002, the pretax netpresent value of the reserves using year end prices and costs held constant anddiscounted at 10% was $106 million.

 

At December 31, 2002, Carbon USA’sexploration and production operations were comprised of working interests in246 producing oil and gas wells.  CarbonUSA operates 151 of these wells.  At December 31,2002, Carbon USA had an interest in over 179,000 net acres of oil and gasleases primarily located in the Piceance Basin of Colorado, the Uintah Basin ofUtah, the Permian Basin of New Mexico and Texas, and Montana.  During 2002, Carbon USA produced 3.0 Bcf ofgas and 91,300 barrels of oil and natural gas liquids, amounting to 3.6 Bcfe oran average of 9.9 MMcfe per day.  Theaddition during 2002 of 7.0 Bcfe to Carbon USA’s net proved reserves resulted ina reserve replacement of 194% of the Company’s 2002 production in the UnitedStates.

 

InSeptember 2002, Carbon USA sold its interest in 20 producing natural gas andoil wells located primarily in Stanton and Morton counties, Kansas for $2.1million in cash.  On March 24, 2003,Carbon USA closed the sale of its interest in 97 gross (23.3 net) wells and26,300 gross (8,000 net) acres located primarily in southeast New Mexico.  The sale price was $15.7 million in cash,with an effective date of January 1, 2003. Daily average net production from the New Mexico properties wasapproximately 3,300 Mcf of gas per day and 130 barrels of oil per day.  These asset sales completed Carbon’s programto sell assets acquired in the 1999 purchase of Bonneville Fuels that did notfit with the Company’s focus on the development of its natural gas propertiesin the Piceance and Uintah Basins and in central Alberta.

 

At December 31, 2002, the estimated provedreserves attributed to the properties divested in March 2003 were 172,000barrels and 7.3 Bcf of gas.  The pretaxnet present value of these reserves using year end 2002 prices (except to theextent provided by contractual arrangement in existence at year end) and costsheld constant and discounted at 10% was $15.9 million.

 

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At December 31, 2002, Carbon Canada’s exploration and productionoperations were comprised of working interests in 94 producing oil and naturalgas wells located in Alberta and Saskatchewan. Carbon Canada operates 51 of these wells.  The Company had an interest in over 49,000 net acres of oil andgas leases.  During 2002, Carbon Canadaproduced 2.2 Bcf of gas and 50,300 barrels of oil and natural gas liquids,amounting to 2.5 Bcfe or an average of 6.9 MMcfe per day.  The addition of 9.2 Bcfe to Carbon’s netproved reserves resulted in a reserve replacement of 368% of the Company’s 2002production in Canada.

 

Forinformation regarding Carbon’s geographic segments, see Note 7 to theConsolidated Financial Statements.

 

OnAugust 11, 1999, Carbon Canada entered into a stock purchase agreementwith Bonneville Pacific Corporation (BPC), parent company of Carbon USA, forthe purchase of all outstanding shares of Carbon USA.  Rights and obligations of Carbon Canada under the stock purchaseagreement were assigned to Carbon. Yorktown Energy Partners III, LP (Yorktown) purchased 4,500,000 sharesof Carbon for $24.8 million.  Thefunds from this purchase were used to acquire, on October 29, 1999, the CarbonUSA shares under the stock purchase agreement and to pay expenses incurred inconnection with the purchase and related transactions.  The total cash purchase price afteradjustments for Carbon USA was $23.5 million.

 

OnJanuary 21, 2000, Carbon commenced an exchange offer for shares of CarbonCanada.  Through the exchange offer,Carbon offered to exchange one share of Carbon stock for each share of CarbonCanada stock.  On February 18,2000, the Company completed its offer to exchange Carbon shares for shares ofCarbon Canada.  Of the 1.5 millionoutstanding shares of Carbon Canada, over 97% of the shares wereexchanged.  Carbon began trading itsshares on the American Stock Exchange on February 24, 2000 under thetrading symbol CRB.  OnFebruary 28, 2000, at the request of Carbon Canada, the Securities andExchange Commission (SEC) approved the delisting of Carbon Canada’s commonstock from the American Stock Exchange.

 

OnNovember 22, 2000, at the direction of its Board of Directors, CarbonCanada initiated an offer to purchase shares (the Offer) of Carbon Canada stockthat were not owned by Carbon.  TheOffer was completed on February 6, 2001. Carbon Canada conducted the Offer in order to avoid the administrativecosts and time involved in corresponding with a small number of minorityshareholders.  The Board of Directors ofCarbon Canada maintained a neutral position in regard to the Offer because ofpotential conflicts of interest.  Of theapproximate 39,000 shares of Carbon Canada that were not acquired by Carbon inthe original exchange offer, approximately 34,000 shares of Carbon Canada stockwere purchased by Carbon Canada pursuant to the Offer.

 

OnOctober 30, 2002, at a special meeting of the holders of Carbon Canada commonstock, a special resolution was passed to amend the articles of Carbon Canadato consolidate its issued and outstanding common shares on a one-for-2,500basis.  The Board of Directors of CarbonCanada recommended the consolidation in order to avoid the administrative costsand time involved in corresponding with a small number of minorityshareholders.  On November 15, 2002,Carbon Canada initiated the exchange of common shares for post-consolidationshares or a cash payment in lieu of fractional post-consolidation shares.  The exchange was completed on January 13,2003.  After the completion of theexchange, Carbon owns 100% of the stock of Carbon Canada.

 

OnMarch 31, 2003, Carbon announced that it had entered into an Agreement and Planof Reorganization (the Merger Agreement) with Evergreen Resources(Evergreen).  Under the MergerAgreement, Carbon will merge with a subsidiary of Evergreen, and Carbonshareholders will receive .275 shares of Evergreen common stock for eachoutstanding share of Carbon common stock (and cash in lieu of any fractionalshares).  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.

 

TheBoard of Directors of Carbon and Evergreen each unanimously approved the MergerAgreement. At the time of execution of the agreement, each of Yorktown andPatrick R. McDonald, President and Chief Executive Officer of Carbon, whobeneficially own approximately 73.2% and 6.0%, respectively, of Carbon'soutstanding common stock, has executed an agreement with Evergreen obligatingeach of them to vote all shares over which it has voting control in favor ofthe merger.

 

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RBCCapital Markets acted as the financial advisor to Carbon and rendered afairness opinion to the Board of Directors of Carbon.

 

Completionof the merger, which is subject to customary conditions, including approval bythe shareholders of Carbon, is expected to occur late in the second quarter orin the third quarter of 2003.  TheMerger Agreement contains a $2.5 million termination fee payable by Carbon ifthe Merger Agreement is terminated under certain circumstances.

 

## BUSINESS STRATEGY

 

TheCompany’s objective is to build shareholder value through consistent growth inreserves and production and to increase net asset value, cash flow, andearnings per share.  Our businessstrategy is to grow through the exploration and development of oil and gasproperties, by the acquisition of complementary properties and through theoptimization of gathering, compression and processing facilities.  In addition we seek opportunities to acquireadditional oil and gas mineral leases and create drilling opportunities basedon internally generated geological and engineering concepts.  Management believes that the Company’sexisting infrastructure and its acreage position in the Piceance Basin inColorado and the Uintah Basin in Utah and the Carbon and Rowley areas ofAlberta, Canada provide the Company with an excellent opportunity to achieveits objectives.  The Company may alsopursue property acquisition opportunities in its areas of operations.  The Company’s objective and businessstrategy is subject to the proposed merger described above.

 

## EMPLOYEES AND OFFICES

 

Asof December 31, 2002, the Company had 24 employees located in Denver,Colorado and 12 in Calgary, Alberta. None of these employees are represented by a labor union.  The Company’s executive offices are locatedat 1700 Broadway, Suite 1150, Denver, Colorado 80290, and its telephonenumber is (303) 863-1555.

 

# **ITEM 2.                 PROPERTIES**

 

United States

Piceanceand Uintah Basins - At December 31, 2002, Carbon owned working interestsin 148 gross (128.7 net) producing wells in the Piceance Basin of Colorado andUintah Basin of Utah.  Carbon operates132 of these wells.  For the year endedDecember 31, 2002, the Company participated in the drilling of three gross(2.7 net) wells, all of which were completed as natural gas wells.  The Company has leasehold rights inapproximately 147,000 gross (126,000 net) acres of which approximately 108,000gross (93,000 net) acres are undeveloped. Approximately 77,000 gross (62,000 net) undeveloped acres are held byproduction.  Subject to completion ofthe proposed merger described previously, Carbon USA’s focus in the UnitedStates during 2003 is to continue the development of its natural gas propertiesin the Rocky Mountains, with emphasis on the Piceance and Uintah Basins.

 

PermianBasin - At December 31, 2002, Carbon owned working interests in 97 gross(23.3 net) producing wells in the Permian Basin of New Mexico and Texas.  Carbon operates 18 of these wells.  For the year ended December 31, 2002,the Company participated in the drilling of six gross (.7 net) wells, of whichone gross (.1 net) was completed as a natural gas well, four gross (.3 net)were completed as oil wells and one gross (.3 net) was abandoned as a dryhole.  The Company has leasehold rightsin approximately 25,000 gross (8,000 net) acres of which approximately 8,000gross (4,000 net) acres are undeveloped. Approximately 8,000 gross (2,000 net) undeveloped acres are held byproduction.  In March 2003, Carbon USAsold its working and related leasehold interests in these properties.

 

Montana- At December 31, 2002, Carbon owned a working interest and operated onegross (1.0 net) producing well in Montana. For the year ended December 31, 2002, the Company participated inthe drilling of two gross (2.0 net) wells both of which were abandoned as dryholes.  The Company has leasehold rightsin approximately 47,000 gross (44,000 net) acres, approximately all of whichare undeveloped.

 

## Canada

Alberta- At December 31, 2002, Carbon owned working interests in 85 gross (58.4net) producing wells primarily in

 

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theCarbon and Rowley areas of Alberta. Carbon operates 51 of these wells. For the year ended December 31, 2002, the Company participated inthe drilling of 17 gross (10.5 net) wells, resulting in 16 gross (10.0 net)natural gas wells and one gross (.5 net) dry hole.  The Company has leasehold rights in approximately 76,000 gross(49,000 net) acres of which approximately 27,000 gross (22,000 net) acres areundeveloped.  Subject to completion ofthe proposed merger described previously, Carbon’s focus in Canada during 2003is to continue the development of its natural gas properties in centralAlberta, with emphasis on the Carbon and Rowley areas.

 

Saskatchewan- At December 31, 2002, Carbon owned non-operating working interests innine gross (2.8 net) producing wells in southeast Saskatchewan.  For the year ended December 31, 2002,the Company did not participate in any drilling activities in this area.  The Company has leasehold rights inapproximately 2,000 gross (500 net) acres of which approximately 160 gross (40net) acres are undeveloped.

 

## RESERVES

 

Thetable below sets forth the Company’s estimated quantities of historical provedreserves after royalty burdens and the present values attributable to thosereserves as of December 31, 2002, 2001 and 2000.  The estimates for the Company’s reserves in the United Stateswere prepared by Ryder Scott Company, an independent reservoir engineeringfirm.  The estimates for the Company’sreserves in Canada were prepared by Sproule Associates Limited, independentgeological and petroleum engineering consultants.  Additional information regarding the Company’s proved and proveddeveloped oil and gas reserves and the standardized measure of discounted netcash flow and changes therein are described in Note 13 to the ConsolidatedFinancial Statements.

 
|                                                                                          |   | **United States**                             |   | **Canada** |   |
|-----------------------------------------------------------------------------------------------|--------|-----------------------------------------------|--------|------------|--------|
|                                                                                          |   | **2002**                                      |   | **2001**   |   | **2000** |   | **2002** |   | **2001** |   | **2000** |   |
|                                                                                          |   | **(dollars in thousands, except price data)** |   |
|                                                                                          |   |                                          |   |       |   |   |   |   |   |   |   |   |   |
| Estimated proved reserves                                                                     |   |                                          |   |       |   |   |   |   |   |   |   |   |   |
| Natural gas (MMcf)                                                                            |   | 36,677                                        |   | 33,992     |   | 32,100 |   | 25,805 |   | 19,868 |   | 18,867 |   |
| Oil and liquids (MBbl)                                                                        |   | 265                                           |   | 412        |   | 507 |   | 557 |   | 439 |   | 461 |   |
| Total MMcfe                                                                                   |   | 38,267                                        |   | 36,464     |   | 35,142 |   | 29,147 |   | 22,502 |   | 21,633 |   |
|                                                                                          |   |                                          |   |       |   |   |   |   |   |   |   |   |   |
| Proved developed reserves (MMcfe)(1)                                                          |   | 29,991                                        |   | 31,355     |   | 28,714 |   | 19,959 |   | 16,822 |   | 18,659 |   |
|                                                                                          |   |                                          |   |       |   |   |   |   |   |   |   |   |   |
| Natural gas price as of December 31 ($/Mcf)                                                   |   | $                                             | 3.14   |       | $      | 2.25 |   | $ | 9.76 |   | $ | 3.84 |   | $ | 2.30 |   | $ | 9.00 |   |
| Oil and liquids price as of December 31 ($/Bbl)                                               |   | 29.84                                         |   | 18.45      |   | 25.50 |   | 24.68 |   | 13.02 |   | 21.73 |   |
|                                                                                          |   |                                          |   |       |   |   |   |   |   |   |   |   |   |
| Present value of estimated future net revenues before  future income taxes, discounted at 10% |   | $                                             | 42,264 |       | $      | 31,107 |   | $ | 153,528 |   | $ | 63,912 |   | $ | 24,684 |   | $ | 111,461 |   |

 

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(1)          Proved developed oil and gas reserves are reserves that can be expectedto be recovered through existing wells with existing equipment and operatingmethods.

 

Theestimate of net proved reserves in the United States at December 31, 2000included volumes attributed to the Company’s working interest in 40 natural gaswells located in the San Juan Basin of New Mexico.  These properties were sold in January 2001.  The estimated proved reserves attributed tothese properties were 38,000 barrels of oil and 5.6 Bcf of natural gas.  The pretax net present value of thesereserves using year end 2000 prices (except to the extent provided bycontractual arrangements in existence at year end) and costs held constant anddiscounted at 10% was $24.0 million.

 

Theestimate of proved reserves in the United States at December 31, 2002 includedvolumes attributed to the Company’s working interest in 97 gross (23.3 net)wells located primarily in southeast New Mexico.  These properties were sold in March 2003.  The estimated proved reserves for theseproperties were 172,000 barrels of oil and 7.3 Bcf of gas.  The pretax net present value of thesereserves using year end 2002 prices (except to the extent provided bycontractual arrangements in existence at year end) and costs held constant anddiscounted at 10% was $15.9 million.

 

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Inaccordance with applicable requirements of the SEC, estimates of the Company’sfuture net revenues are determined using sale prices estimated to be in effectas of the date of the reserve estimates and are held constant throughout thelife of the properties (except to the extent provided by contractualarrangements in existence at year end). Also in accordance with the applicable SEC guidelines, future productioncosts are held constant at the level observed at the date of the reserveestimates.  Declines in the price of oilor gas decrease reserve values by lowering the future net revenues attributableto the reserves and may also reduce the quantities of reserves that arerecoverable on an economic basis.  Priceincreases may have the opposite effect. A significant decline in prices of natural gas or oil could have amaterial adverse effect on the Company’s financial condition and results ofoperations.  Prices received for futureproduction and future production costs may vary, perhaps significantly, fromthe prices and costs assumed for purposes of the estimates.

 

Thereare numerous uncertainties inherent in estimating quantities of proved reservesand in projecting future rates of production and timing of developmentexpenditures.  Oil and gas reserveengineering is a subjective process of estimating underground accumulations ofnatural gas and oil that cannot be measured in an exact way, and estimates ofother engineers might differ materially from those shown above.  The accuracy of any reserve estimate is afunction of the quality of available data and engineering and geologicalinterpretations and judgment.  Resultsof drilling, testing and production may justify revisions.  Accordingly, reserve estimates are oftenmaterially different from the quantities of oil and natural gas that areultimately recovered.  Themeaningfulness of such estimates depends primarily on the accuracy of theassumptions upon which they were based. In general, the volume of production from Carbon’s oil and gas propertiesdecline as reserves of oil and gas are depleted.  Except to the extent the Company acquires additional propertiescontaining proved reserves or conducts successful exploration and developmentactivities or both, the proved reserves of the Company will decline as reservesare produced.  Reserves generated fromfuture activities of the Company are highly dependent upon the level of successin acquiring or discovering additional reserves and the costs incurred in doingso.

 

SinceJanuary 1, 2002, the Company has filed the Department of Energy FormEIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” as required byoperators of oil and gas properties in the United States.  There are differences between the reservesas reported on Form EIA-23 and reserves as reported herein.  Form EIA-23 requires that operators reporton total proved reserves for operated wells only and that reported reserves bereported on a gross basis rather than on a net basis.

 

## PRODUCTION

 

Thefollowing table sets forth information regarding net oil and natural gasproduction, average sales prices and other production information.  Average sales prices for natural gas, oiland liquids are inclusive of hedging gains and losses for the years endedDecember 31, 2002, 2001 and 2000:

 
|                                        |   | **United States** |   | **Canada(1)** |   |
|---------------------------------------------|--------|-------------------|--------|---------------|--------|
|                                        |   | **2002**          |   | **2001**      |   | **2000** |   | **2002** |   | **2001** |   | **2000** |   |
|                                        |   |              |   |          |   |   |   |   |   |   |   |   |   |
| Quantities produced and sold                |   |              |   |          |   |   |   |   |   |   |   |   |   |
| Natural gas (MMcf)                          |   | 3,049             |   | 2,810         |   | 3,374 |   | 2,232 |   | 2,419 |   | 1,312 |   |
| Oil and liquids (Bbl)                       |   | 91,297            |   | 81,091        |   | 69,394 |   | 50,274 |   | 58,615 |   | 39,662 |   |
| Total MMcfe                                 |   | 3,597             |   | 3,297         |   | 3,790 |   | 2,534 |   | 2,771 |   | 1,550 |   |
|                                        |   |              |   |          |   |   |   |   |   |   |   |   |   |
| Average sales price                         |   |              |   |          |   |   |   |   |   |   |   |   |   |
| Natural gas ($/Mcf)                         |   | $                 | 2.17   |          | $      | 2.94 |   | $ | 2.80 |   | $ | 2.95 |   | $ | 4.05 |   | $ | 3.41 |   |
| Oil and liquids ($/Bbl)                     |   | 21.92             |   | 25.49         |   | 23.03 |   | 19.62 |   | 21.76 |   | 22.65 |   |
|                                        |   |              |   |          |   |   |   |   |   |   |   |   |   |
| Average production (lifting) costs ($/Mcfe) |   | $                 | 0.45   |          | $      | 0.50 |   | $ | 0.42 |   | $ | 0.67 |   | $ | 0.58 |   | $ | 0.51 |   |

 

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(1)          Canadian results for 2000 are the results of Carbon Canada subsequent toits acquisition by Carbon in February 2000.

 

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## PRODUCTIVE WELLS

 

Thefollowing table sets forth information regarding the number of productive wellsin which the Company held a working interest at December 31, 2002:

 
|                     |   | **Productive Wells (1)** |   |
|--------------------------|--------|--------------------------|--------|
|                     |   | **Gas Wells**            |   | **Oil Wells** |   |
|                     |   | **Gross(2)**             |   | **Net(3)** |   | **Gross** |   | **Net** |   |
| United States            |   |                     |   |   |   |   |   |   |   |
| Permian Basin            |   | 61                       |   | 13.6 |   | 36 |   | 9.7 |   |
| Piceance/Uintah Basins   |   | 145                      |   | 125.7 |   | 3 |   | 3.0 |   |
| Montana                  |   | —                   |   | — |   | 1 |   | 1.0 |   |
| Total                    |   | 206                      |   | 139.3 |   | 40 |   | 13.7 |   |
|                     |   |                     |   |   |   |   |   |   |   |
| Canada                   |   |                     |   |   |   |   |   |   |   |
| Alberta                  |   | 85                       |   | 58.4 |   | — |   | — |   |
| Saskatchewan             |   | —                   |   | — |   | 9 |   | 2.8 |   |
| Total                    |   | 85                       |   | 58.4 |   | 9 |   | 2.8 |   |
|                     |   |                     |   |   |   |   |   |   |   |
| United States and Canada |   | 291                      |   | 197.7 |   | 49 |   | 16.5 |   |

 

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(1)          Each well completed to more than one producing zone is counted as asingle well.  The Company has royaltyinterests in certain wells that are not included in this table.

(2)          A gross well is a well in which a working interest is owned.  The number of gross wells is the totalnumber of wells in which a working interest is owned.

(3)          A net well is deemed to exist when the sum of fractional ownershipworking interests in gross wells equals one. The number of net wells is the sum of the fractional working interestowned in gross wells.

 

Thenumber of productive wells in which the Company held a working interest atDecember 31, 2002 included 61 gross (13.6 net) gas wells and 36 gross (9.7 net)oil wells attributed to properties located primarily in southeast NewMexico.  These properties were sold inMarch 2003.

 

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## DRILLING ACTIVITY

 

TheCompany engages in exploratory and developmental drilling on its own and inassociation with other oil and gas companies. The following table sets forth the wells drilled for the years endedDecember 31, 2002, 2001 and 2000:

 
|              |   | **United States** |   | **Canada (1)** |   |
|-------------------|--------|-------------------|--------|----------------|--------|
|              |   | **2002**          |   | **2001**       |   | **2000** |   | **2002** |   | **2001** |   | **2000** |   |
|              |   |              |   |           |   |   |   |   |   |   |   |   |   |
| Gross wells(2)    |   |              |   |           |   |   |   |   |   |   |   |   |   |
| Development       |   |              |   |           |   |   |   |   |   |   |   |   |   |
| Natural gas       |   | 2                 |   | 6              |   | — |   | 14 |   | 11 |   | 8 |   |
| Oil               |   | 4                 |   | 7              |   | 6 |   | — |   | — |   | — |   |
| Non-productive(3) |   | —            |   | —         |   | — |   | 1 |   | — |   | — |   |
| Total             |   | 6                 |   | 13             |   | 6 |   | 15 |   | 11 |   | 8 |   |
|              |   |              |   |           |   |   |   |   |   |   |   |   |   |
| Exploratory       |   |              |   |           |   |   |   |   |   |   |   |   |   |
| Natural gas       |   | 2                 |   | 16             |   | — |   | 2 |   | — |   | — |   |
| Oil               |   | —            |   | 3              |   | 4 |   | — |   | — |   | — |   |
| Non-productive    |   | 3                 |   | 3              |   | 5 |   | — |   | — |   | — |   |
| Total             |   | 5                 |   | 22             |   | 9 |   | 2 |   | — |   | — |   |
|              |   |              |   |           |   |   |   |   |   |   |   |   |   |
| Net wells(4)      |   |              |   |           |   |   |   |   |   |   |   |   |   |
| Development       |   |              |   |           |   |   |   |   |   |   |   |   |   |
| Natural gas       |   | 1.8               |   | 4.7            |   | — |   | 9.0 |   | 10.5 |   | 4.9 |   |
| Oil               |   | 0.3               |   | 2.5            |   | 0.4 |   | — |   | — |   | — |   |
| Non-productive    |   | —            |   | —         |   | — |   | 0.5 |   | — |   | — |   |
| Total             |   | 2.1               |   | 7.2            |   | 0.4 |   | 9.5 |   | 10.5 |   | 4.9 |   |
|              |   |              |   |           |   |   |   |   |   |   |   |   |   |
| Exploratory       |   |              |   |           |   |   |   |   |   |   |   |   |   |
| Natural gas       |   | 1.0               |   | 10.1           |   | — |   | 1.0 |   | — |   | — |   |
| Oil               |   |              |   | 2.5            |   | 2.5 |   | — |   | — |   | — |   |
| Non-productive    |   | 2.3               |   | 2.5            |   | 3.8 |   | — |   | — |   | — |   |
| Total             |   | 3.3               |   | 15.1           |   | 6.3 |   | 1.0 |   | — |   | — |   |

 

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(1)          The results for 2000 are the results of Carbon Canada subsequent to itsacquisition by Carbon in February 2000.

(2)          A gross well is a well in which a working interest is owned.  The number of gross wells is the totalnumber of wells in which a working interest is owned.

(3)          A non-productive hole is a well deemed to be incapable of producingeither natural gas or oil in sufficient quantities to justify completion as anatural gas or oil well.

(4)          A net well is deemed to exist when the sum of the fractional ownershipworking interests in gross wells equals one. The number of net wells is the sum of the fractional working interestowned in gross wells.

 

AtDecember 31, 2002, the Company was participating in the drilling of onegross (.1 net) well in the United States and three gross (2.8 net) wells inCanada.

 

8

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## DEVELOPED AND UNDEVELOPED ACREAGE

 

Thefollowing table sets forth the leasehold acreage held by the Company atDecember 31, 2002:

 
|                       |   | **Developed Acreage(1)** |   | **Undeveloped Acreage(2)** |   |
|----------------------------|--------|--------------------------|--------|----------------------------|--------|
|                       |   | **Gross(3)**             |   | **Net(4)**                 |   | **Gross** |   | **Net** |   |
|                       |   |                     |   |                       |   |   |   |   |   |
| United States              |   |                     |   |                       |   |   |   |   |   |
| Permian Basin              |   | 17,201                   |   | 4,664                      |   | 8,150 |   | 3,550 |   |
| Piceance and Uintah Basins |   | 38,208                   |   | 32,735                     |   | 108,424 |   | 92,786 |   |
| Montana                    |   | 40                       |   | 40                         |   | 46,748 |   | 43,706 |   |
| Wyoming                    |   | 1,120                    |   | 560                        |   | 2,221 |   | 1,111 |   |
| Total                      |   | 56,569                   |   | 37,999                     |   | 165,543 |   | 141,153 |   |
|                       |   |                     |   |                       |   |   |   |   |   |
| Canada                     |   |                     |   |                       |   |   |   |   |   |
| Alberta                    |   | 48,480                   |   | 27,448                     |   | 27,360 |   | 21,564 |   |
| Saskatchewan               |   | 1,520                    |   | 432                        |   | 160 |   | 40 |   |
| Total                      |   | 50,000                   |   | 27,880                     |   | 27,520 |   | 21,604 |   |

 

----

(1)          Developed acres are those acres which are spaced or assigned toproductive wells.

(2)          Undeveloped acres are considered to be those acres on which wells havenot been drilled or completed to a point that would permit the production ofcommercial quantities of oil and natural gas regardless of whether such acreagecontains proved reserves.  It should notbe confused with undrilled acreage held by production under the terms of alease.

(3)          A gross acre is an acre in which a working interest is owned.  The number of gross acres is the totalnumber of acres in which a working interest is owned.

(4)          A net acre is deemed to exist when the sum of the fractional ownershipworking interests in gross acres equals one. The number of net acres is the sum of the fractional working interestsowned in gross acres.

 

Thedeveloped and undeveloped acreage position in the United States at December 31,2002 included 17,201 gross (4,664 net) developed acres, and 8,150 gross (3,550net) undeveloped acres attributed to lands located primarily in southeast NewMexico.  These properties were sold inMarch 2003.

 

## MARKETING

 

The Company sells natural gas, oil andnatural gas liquids production from wells that it operates directly topurchasers including end users, marketers and refiners.  Where the Company is not the operator of thewell, it may directly market the production or it may contract to sell itsshare of production through the operator of the well.

 

The Company generally enters into short-term natural gas salescontracts and is typically paid a price based on the regional price set by themarket place for natural gas deliveries to the regional interstate mainlinetransportation pipeline, a price which is generally less than the price set fornatural gas deliveries to Henry Hub, the principal point for natural gasproduction in the Gulf Coast region of the United States and the point at whichthe price of the natural gas contract of the New York Mercantile Exchange(NYMEX) is set.  The Company istypically paid on an index basis, net of mainline transportation chargesincurred by the buyer.  As ofDecember 31, 2002, Carbon Canada is a party to various natural gastransportation contracts in Canada. Carbon Canada typically assigns these transportation contracts to thebuyer of the Company’s natural gas production for the term of the particularcontract.  The rights and obligationsunder these transportation agreements revert to the Company upon expiration ofthe natural gas sales contracts.

 

Inthe United States, oil is sold under contracts extending up to a year basedupon monthly refiner price postings, which generally approximate the price ofWest Texas Intermediate crude oil adjusted to reflect transportation costs andquality.  In Canada, oil and natural gasliquids are sold under short-term contracts at refiner posted prices forAlberta

 

9

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andSaskatchewan, adjusted to reflect transportation costs and quality.

 

Forinformation regarding major purchasers of the Company’s oil and natural gas,see Note 8 to the Consolidated Financial Statements.

 

## COMPETITION

 

Theoil and natural gas industry is highly competitive.  The Company encounters competition from other oil and natural gascompanies including major oil companies, other independent oil and natural gasconcerns and individual producers and operators for the acquisition ofproducing properties and exploration and development prospects.  The Company also competes with other oil andnatural gas companies in attempting to secure drilling rigs and other equipmentnecessary for drilling and completion of wells.  The Company competes with a large number of companies havingsubstantially larger technical staffs and greater financial and operationalresources.  The ability of the Companyto increase reserves in the future will be dependent on its ability to generatesuccessful prospects on its existing lands, to acquire producing properties andto acquire additional leases and prospects for future development and exploration.

 

## TITLE TO PROPERTIES

 

Titleto the Company’s properties is subject to royalty, overriding royalty, carried,net profits, working and similar interests customary in the oil and gasindustry.  The Company’s properties mayalso be subject to liens incident to operating agreements, as well as othercustomary encumbrances, easements and restrictions and for current taxes notyet due.  For acquisitions ofproperties, the Company will conduct a title examination on all materialproperties.  Prior to the commencementof drilling operations, a title examination and, if necessary, curative workwill be performed.  The methods of titleexamination adopted by the Company are reasonable in the opinion of managementand are designed to insure that production from its properties, if obtained,will be salable for the account of the Company.

 

## GOVERNMENT REGULATION

 

## United States

TheCompany’s United States operations are regulated at the federal, state andlocal levels.  Natural gas and oilexploration, development, production and marketing activities are subject tovarious laws and regulations which may be periodically changed for a variety ofpolitical, economical and other reasons.

 

Inthe past, the federal government has regulated the prices at which oil andnatural gas could be sold.  The NaturalGas Wellhead Decontrol Act of 1989 removed all price controls affectingproducing wellhead sales effective January 1, 1993.  While sales by producers of oil, naturalgas, and natural gas liquids can currently be made at uncontrolled marketprices, Congress could reenact price controls in the future.  The Company’s natural gas sales are affectedby regulation of intrastate and interstate transportation.  In recent years the Federal EnergyRegulatory Commission (FERC) has issued a series of orders that has increasedcompetition by, among other things, removing the transportation barriers tomarket access.  These orders have had asignificant impact upon gas markets in the United States and have fostered thedevelopment of a large spot market for gas and increased competition for gasmarkets.  As a result of the FERCorders, producers can access gas markets directly but face increasedcompetition for these markets.  TheCompany believes that these changes have generally improved the Company’saccess to transportation and has enhanced the marketability of its natural gasproduction.  To date the Companybelieves it has not experienced any material adverse effects as a result ofthese FERC orders; however the Company cannot predict what new regulations maybe adopted by FERC and other regulatory authorities and the effect, if any,subsequent regulations may have on the Company.

 

TheCompany’s oil and natural gas operations are regulated by administrativeagencies under statutory provisions of the states where such operations areconducted and by certain agencies of the Federal government for operations onfederal oil and gas leases.  All of thejurisdictions in which the Company owns or operates producing oil and naturalgas properties have statutory provisions regulating the exploration for andproduction of crude oil and natural gas. These statutes include the regulation of the size of drilling andspacing units and the number of wells which may be drilled in an area and theunitization or pooling of oil and natural gas properties.  In addition, state conservation lawsestablish

 

10

----

 

maximumrates of production from oil and natural gas wells, typically prohibit theventing or flaring of natural gas, and impose certain requirements regardingthe apportionment of production from fields and individual wells.  The effect of these regulations may limitthe amount of oil and natural gas the Company can produce from its wells andlimit the number of wells or location at which the Company can drill.  State commissions establish rules forreclamation of sites, plugging bonds, reporting and other matters.

 

Increasingly,a number of city and county governments have enacted oil and natural gas regulationswhich have increased the involvement of local governments in the permitting ofoil and natural gas operations and impart additional restrictions or conditionson the conduct of operators to mitigate the impact of operations on the localcommunity.  These local restrictionshave the potential to delay and increase the cost of oil and natural gasoperations.

 

## Canada

Theoil and natural gas industry in Canada is subject to extensive controls andregulations imposed by various levels of government.  Federal authorities do not regulate the price of oil and gas inexport trade but instead rely on market forces to establish these prices.  Legislation exists that regulates thequantities of oil and natural gas which may be removed from the provinces andexported from Canada.  The Company doesnot expect that any of these controls and regulations will affect the Companyin a manner significantly different than other oil and natural gas companies ofsimilar size.

 

Theprovinces in which the Company operates have legislation and regulation whichgovern land tenure, royalties, production rates and environmentalprotection.  The royalty regime in theprovinces in which the Company operates is a significant factor in the profitabilityof the Company’s production.  Crownroyalties are determined by government regulation and are typically calculatedas a percentage of the value of production. The value of the production and the rate of royalties payable depends onprescribed reference prices, well productivity, geographical location and thetype or quality of the product produced.

 

InAlberta, the Company is entitled to a credit against Crown royalties on most ofthe properties in which the Company has an interest in by virtue of the AlbertaRoyalty Tax Credit (ARTC).  The creditis determined by applying a rate to a maximum of CDN $2.0 million of Crownroyalties payable in Alberta for each company or associated group ofcompanies.  The rate is a function ofthe royalty tax credit par prices which is determined quarterly by the AlbertaDepartment of Energy.  The rate rangesfrom 25% to 75% depending upon petroleum prices for the previous quarter.

 

## ENVIRONMENTAL REGULATION

 

## United States

TheCompany, as a lessee and operator of natural gas and oil properties, is subjectto various federal, state and local laws and regulations in the United Statesthat provide for restriction and prohibition on releases or emissions ofvarious substances produced in association with certain oil and gas industryoperations which can affect the location of wells and facilities and candetermine the extent to which exploration and development is permitted.  In addition, legislation requires that welland facility sites and access be abandoned and reclaimed to the satisfaction offederal or state authorities, as applicable. These laws and regulations may, among other things, impose liability andpenalties on the lessee for the cost of pollution cleanup resulting fromoperations, subject the lessee to liability for pollution damages, requiresuspension or cessation of operations in affected areas, and imposerestrictions on the injection of liquids into subsurface aquifers that maycontaminate ground water.

 

TheCompany has made, and will continue to make, expenditures in its efforts tocomply with environmental regulations. The Company believes it is in compliance with applicable environmentallaws and regulations in effect and that continued compliance with existingrequirements will not have a material adverse impact on the Company.  The Company has not been notified of, norhas any knowledge of any existing or pending environmental claims.  Changes in existing environmental laws orthe adoption of new environmental laws could have the potential to adverselyaffect the Company’s operations.  In connectionwith the Company’s acquisition of Carbon USA, environmental assessments ofCarbon USA’s oil and gas properties were performed.  No material noncompliance or clean-up liabilities requiringaction were discovered.  However,environmental assessments were performed on only a percentage of the Company’sproperties according to the value of the properties established at the time ofacquisition.

 

11

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TheCompany believes that it is reasonably likely that the trend in environmentallegislation and regulation will continue toward stricter standards.  No assurance can be given as to futurecapital expenditures which may be required for compliance with prospectiveenvironmental regulations.

 

## Canada

InCanada, the oil and natural gas industry is currently subject to environmentalregulations pursuant to provincial and federal legislation.  Environmental legislation provides forrestrictions on releases or emissions of various substances produced orutilized in association with certain oil and gas industry operations.  In addition, legislation requires that welland facility sites be abandoned and reclaimed to the satisfaction of provincialauthorities.  A breach of suchregulations may result in the imposition of fines and penalties, the suspensionof operations and potential civil liability. The Environmental Protection and Enhancement Act imposes environmentalstandards and requires compliance with various legislative criteria includingreporting and monitoring in Alberta. The Alberta Energy and Utility Board, pursuant to its governinglegislation, also plays a role with respect to the regulation of environmentalimpacts of oil and gas activities.

 

## OPERATING HAZARDS

 

Theoil and gas industry involves a variety of operating risks including the riskof fire, explosion, blow-outs, pipe failure, casing collapse, abnormallypressured formations, and environmental hazards such as oil spills, gas leaks,ruptures and discharge of toxic substances. The occurrence of any of these events might result in substantial lossesto the Company due to injury and loss of life, severe damage to and destructionof property and natural resources and investigation and penalties andsuspension of operations.  The Companymaintains insurance against some, but not all, potential risks.  There can be no assurance that any suchinsurance that is obtained will be adequate to cover all losses or exposure forliability.  Furthermore, the Companycannot predict whether such insurance will continue to be available at premiumlevels that justify its purchase.

 

# **ITEM 3.                 LEGAL PROCEEDINGS**

 

Neitherthe Company nor its subsidiaries are engaged in any material legal proceedings.

 

**ITEM 4.                 SUBMISSION OF MATTERS TO A VOTEOF SECURITY HOLDERS**

 

None.

12

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**PART II**

 

**ITEM 5.                 MARKETFOR REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER MATTERS**

 

OnFebruary 24, 2000, Carbon Energy shares began trading on the AmericanStock Exchange under the trading symbol CRB. The Company’s equity securities consist of common stock with no parvalue.  The range of the high and lowclosing prices of the Company’s common stock for each quarterly period during2002 and 2001 is as follows:

 
| **Quarter Ended**  |   | **High** |   | **Low** |   |
|--------------------|--------|----------|--------|---------|--------|
|               |   |     |   |    |   |
| March 31, 2002     |   | $        | 8.69   |    | $      | 7.90 |   |
| June 30, 2002      |   | 9.90     |   | 8.60    |   |
| September 30, 2002 |   | 9.89     |   | 9.50    |   |
| December 31, 2002  |   | 10.25    |   | 9.70    |   |
|               |   |     |   |    |   |
| March 31, 2001     |   | $        | 8.80   |    | $      | 6.81 |   |
| June 30, 2001      |   | 12.31    |   | 8.80    |   |
| September 30, 2001 |   | 9.90     |   | 8.20    |   |
| December 31, 2001  |   | 9.59     |   | 8.60    |   |

 

OnMarch 19, 2003, the closing price of the common stock was $10.50.  There were approximately 40 holders ofrecord of the common stock and 6.1 million shares outstanding.

 

TheCompany has not paid dividends on its common stock since inception and does notanticipate doing so in the future. Future payments of dividends, if any, will depend on the Company’searnings, capital requirements, loan restrictions, financial condition andother relevant factors.  There is noassurance that the Company will ever pay dividends.

 

13

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# **ITEM 6.  SELECTED FINANCIAL DATA**

 

Thetable below sets forth selected historical financial and operating data forCarbon and its predecessor, Bonneville Fuels, as of or for each of the years inthe five-year period ended December 31, 2002.  For 1999, the table presents the activities of the Company forNovember and December 1999 (the Company’s operating activities prior toNovember 1, 1999 were minimal) and Carbon’s predecessor, Bonneville Fuels,for the period January through October 1999, and a pro forma presentationfor the combined operating and cash flow data for the year endedDecember 31, 1999.  The twelvemonth figures as of or for the year ended December 31, 1998 are for Carbon’spredecessor, Bonneville Fuels.  Futureresults may differ substantially from historical results because of changes inoil and natural gas prices, production increases or declines and other factors.  This information should be read inconjunction with the financial statements and notes thereto and “Management’sDiscussion and Analysis of Financial Condition and Results of Operations,”presented elsewhere herein.  Please seeNote 7 and Note 14 to the Consolidated Financial Statements forinformation on geographic segments and quarterly data for 2002 and 2001.

 
|                                                    |   |                                              |          |     |   |         |   | **Pro Forma  for the  Year Ended  December 31,** |   | **As of or  for the  Two Months  Ended  December 31,** |   | **As of or  for the  Ten Months  Ended  October 31,** |   | **As of or  for the  Year  Ended  December 31,** |   |
|---------------------------------------------------------|--------|---------------------------------------------------|---------------|----------|--------|--------------|--------|--------------------------------------------------|--------|--------------------------------------------------------|--------|-------------------------------------------------------|--------|--------------------------------------------------|--------|
| **As of or for the Year Ended  December 31,**           |
|                                                    |   | **2002**                                          |          | **2001** |   | **2000**     |   | **1999**                                         |   | **1999**                                               |   | **1999**                                              |   | **1998**                                         |   |
|                                                    |   | **(dollars in thousands, except per share data)** |          |
| Operating Data:                                         |   |                                              |          |     |   |         |   |                                             |   |                                                   |   |                                                  |   |                                             |   |
| Revenues                                                |   | $                                                 | 16,520        |     | $      | 21,955       |   | $                                                | 16,603 |                                                   | $      | 10,299                                                |   | $                                                | 1,775  |   | $ | 8,524 |   | $ | 7,281 |   |
| Net earnings (loss)                                     |   | (14,555                                           | )             | 1,573    |   | 1,456        |   | 147                                              |   | (491                                                   | )      | 638                                                   |   | (2,191                                           | )      |
| Earnings (loss) per share:                              |   |                                              |          |     |   |         |   |                                             |   |                                                   |   |                                                  |   |                                             |   |
| Basic                                                   |   | $                                                 | (2.39         | )        | $      | 0.26         |   | $                                                | 0.25   |                                                   | n/a    |                                                  | $      | (0.12                                            | )      | n/a |   | n/a |   |
| Diluted                                                 |   | (2.39                                             | )             | 0.25     |   | 0.25         |   | n/a                                              |   | (0.12                                                  | )      | n/a                                                   |   | n/a                                              |   |
|                                                    |   |                                              |          |     |   |         |   |                                             |   |                                                   |   |                                                  |   |                                             |   |
| Cash Flow Data:                                         |   |                                              |          |     |   |         |   |                                             |   |                                                   |   |                                                  |   |                                             |   |
| Cash provided by (used in) operating activities         |   | $                                                 | 2,657         |     | $      | 14,232       |   | $                                                | 3,755  |                                                   | $      | (713                                                  | )      | $                                                | 999    |   | $ | (1,712 | ) | $ | 4,696 |   |
| Cash used in investing activities                       |   | (7,572                                            | )             | (17,297  | )      | (8,266       | )      | (28,841                                          | )      | (24,110                                                | )      | (4,731                                                | )      | (5,948                                           | )      |
| Cash provided by financing activities                   |   | 4,875                                             |          | 3,089    |   | 3,526        |   | 28,056                                           |   | 24,106                                                 |   | 3,950                                                 |   | 3,450                                            |   |
| EBITDA(1)                                               |   | 6,606                                             |          | 10,734   |   | 8,763        |   | 3,483                                            |   | 239                                                    |   | 3,244                                                 |   | 1,816                                            |   |
|                                                    |   |                                              |          |     |   |         |   |                                             |   |                                                   |   |                                                  |   |                                             |   |
| Balance Sheet Data:                                     |   |                                              |          |     |   |         |   |                                             |   |                                                   |   |                                                  |   |                                             |   |
| Total assets                                            |   | $                                                 | 52,304        |     | $      | 62,368       |   | $                                                | 62,480 |                                                   | n/a    |                                                  | $      | 39,298                                           |   | $ | 22,912 |   | $ | 22,840 |   |
| Working capital                                         |   | (3,671                                            | )             | (5,051   | )      | (267         | )      | n/a                                              |   | 232                                                    |   | 1,954                                                 |   | 562                                              |   |
| Long-term debt                                          |   | 22,709                                            |          | 17,870   |   | 15,082       |   | n/a                                              |   | 9,100                                                  |   | 9,800                                                 |   | 5,850                                            |   |
| Stockholders’ equity                               |   | 18,608                                            |          | 33,854   |   | 32,235       |   | n/a                                              |   | 24,315                                                 |   | 9,701                                                 |   | 9,063                                            |   |
|                                                    |   |                                              |          |     |   |         |   |                                             |   |                                                   |   |                                                  |   |                                             |   |
|                                                         |   |
| (1)  Net earnings (loss) to EBITDA reconciliation: |   |
|                                                    |   |                                              |          |     |   |         |   |                                             |   |                                                   |   |                                                  |   |                                             |   |
| Net earnings (loss)                                     |   | $                                                 |  (14,555 | )        | $      |  1,573  |   | $                                                | 1,456  |                                                   | $      | 147                                                   |   | $                                                | (491   | ) | $ | 638 |   | $ | (2,191 | ) |
| Interest                                                |   | 1,054                                             |          | 836      |   | 1,104        |   | 556                                              |   | 102                                                    |   | 454                                                   |   | 238                                              |   |
| Income taxes                                            |   | 747                                               |          | 2,091    |   | 667          |   | —                                           |   | —                                                 |   | —                                                |   | (175                                             | )      |
| Depreciation,  depletion & amortization             |   | 6,142                                             |          | 6,234    |   | 5,536        |   | 2,720                                            |   | 628                                                    |   | 2,092                                                 |   | 2,086                                            |   |
| Full cost ceiling  adjustment                           |   | 13,218                                            |          | —   |   | —       |   | 60                                               |   | —                                                 |   | 60                                                    |   | 1,858                                            |   |
| EBITDA                                                  |   | $                                                 |  6,606   |     | $      |  10,734 |   | $                                                | 8,763  |                                                   | $      | 3,483                                                 |   | $                                                | 239    |   | $ | 3,244 |   | $ | 1,816 |   |

 

EBITDA(as used herein) is defined as net income (loss) before interest expense,income taxes, depletion, depreciation and amortization, and impairment of oiland gas properties.  While EBITDA shouldnot be considered in isolation or as a substitute for net income (loss),operating income (loss), cash flow provided by operating activities or otherincome or cash flow data prepared in accordance with generally acceptedaccounting principles or as an indicator of a company’s financial performance,the Company

 

14

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believesthat it provides additional information with respect to its ability to meet itsfuture debt service, capital expenditures and working capitalrequirements.  When evaluating EBITDA,readers should consider, among other factors, (i) increasing or decreasingtrends in EBITDA, (ii) whether EBITDA has remained at positive levelshistorically and (iii) how EBITDA compares to levels of interestexpense.  Because EBITDA excludes some,but not all, items that affect net income and may vary among companies, theEBITDA presented above may not be comparable to similarly titled measures ofother companies.  While the Companybelieves that EBITDA may provide additional information with respect to itsability to meet its future debt service, capital expenditures and workingcapital requirements, certain functional or legal requirements of its businessmay require it to utilize its available funds for other purposes.

 

**ITEM 7.                 MANAGEMENT’SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

 

RESULTSOF OPERATIONS—COMPARISON OF 2002 RESULTS TO 2001

 

Thefollowing table and discussion present comparative revenue, sales volumes,average sales prices, expenses and the percentage change between periods forthe years ended December 31, 2002 and 2001.

 
|                                     |   | **United States  For the Year Ended  December 31,**                 |   | **Canada  For the Year Ended  December 31,**                        |   |
|------------------------------------------|--------|---------------------------------------------------------------------|--------|---------------------------------------------------------------------|--------|
|                                     |   | **2002**                                                            |   | **2001**                                                            |   | **Change** |   | **2002** |   | **2001** |   | **Change** |   |
|                                     |   | **(Dollars in thousands, except  prices and per Mcfe information)** |   | **(Dollars in thousands, except  prices and per Mcfe information)** |   |
| Revenues:                                |   |                                                                |   |                                                                |   |   |   |   |   |   |   |   |   |
| Oil and gas revenues                     |   | $                                                                   | 8,603  |                                                                | $      | 10,341 |   | -17 | % | $ | 7,573 |   | $ | 11,080 |   | -32 | % |
| Marketing and other, net                 |   | 344                                                                 |   | 532                                                                 |   | -35 | % | — |   | 2 |   | n/a |   |
| Total revenues                           |   | 8,947                                                               |   | 10,873                                                              |   | -18 | % | 7,573 |   | 11,082 |   | -32 | % |
|                                     |   |                                                                |   |                                                                |   |   |   |   |   |   |   |   |   |
| Daily sales volumes:                     |   |                                                                |   |                                                                |   |   |   |   |   |   |   |   |   |
| Natural gas (MMcf)                       |   | 8.4                                                                 |   | 7.7                                                                 |   | 9 | % | 6.1 |   | 6.6 |   | -8 | % |
| Oil and liquids (Bbl)                    |   | 250                                                                 |   | 222                                                                 |   | 13 | % | 138 |   | 161 |   | -14 | % |
| Equivalents production (MMcfe 6:1)       |   | 9.9                                                                 |   | 9.0                                                                 |   | 10 | % | 6.9 |   | 7.6 |   | -9 | % |
|                                     |   |                                                                |   |                                                                |   |   |   |   |   |   |   |   |   |
| Average price realized:                  |   |                                                                |   |                                                                |   |   |   |   |   |   |   |   |   |
| Natural gas (Mcf)                        |   | $                                                                   | 2.17   |                                                                | $      | 2.94 |   | -26 | % | $ | 2.95 |   | $ | 4.05 |   | -27 | % |
| Oil and liquids (Bbl)                    |   | 21.92                                                               |   | 25.49                                                               |   | -14 | % | 19.62 |   | 21.76 |   | -10 | % |
|                                     |   |                                                                |   |                                                                |   |   |   |   |   |   |   |   |   |
| Direct lifting costs                     |   | $                                                                   | 1,623  |                                                                | $      | 1,654 |   | -2 | % | $ | 1,703 |   | $ | 1,612 |   | 6 | % |
| Average direct lifting costs/Mcfe        |   | 0.45                                                                |   | 0.50                                                                |   | -10 | % | 0.67 |   | 0.58 |   | 16 | % |
| Other production costs                   |   | 1,619                                                               |   | 1,901                                                               |   | -15 | % | 82 |   | 14 |   | 486 | % |
| General and administrative, net          |   | 2,868                                                               |   | 2,767                                                               |   | 4 | % | 2,019 |   | 1,736 |   | 16 | % |
| Depreciation, depletion and amortization |   | 3,626                                                               |   | 3,536                                                               |   | 3 | % | 2,516 |   | 2,698 |   | -7 | % |
| Full cost ceiling impairment             |   | 12,003                                                              |   | —                                                              |   | n/a |   | 1,215 |   | — |   | n/a |   |
| Interest and other expense, net          |   | 804                                                                 |   | 653                                                                 |   | 23 | % | 250 |   | 210 |   | 19 | % |
| Income tax provision                     |   | 746                                                                 |   | 135                                                                 |   | 453 | % | 1 |   | 1,956 |   | -100 | % |

 

Revenuesfor oil and gas sales of Carbon USA for the year ended December 31, 2002were $8.6 million, a 17% decrease from 2001.  The decrease was due to a decline in oil and natural gas pricespartially offset by increased oil, liquids and natural gas production.

 

Revenuesfor oil, liquids and gas sales of Carbon Canada for the year endedDecember 31, 2002 were $7.6 million, a 32% decrease from 2001.  The decrease was due primarily to a declinein oil, liquids and natural gas prices and a decrease in oil, liquids andnatural gas production largely due to the voluntary curtailment in the thirdquarter of 2002

 

15

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ofover 200 MMcf of the Company’s natural gas and associated natural gas liquidsproduction due to low natural gas prices.

 

Average production in the United States for the year endedDecember 31, 2002 was 250 barrels of oil per day and 8.4 millioncubic feet (MMcf) of gas per day, an increase of 10% from 2001 on a Mcfequivalent (Mcfe) basis where one barrel of oil or liquids is equal to six Mcfof gas.  The increase in oil, liquidsand gas production was due to successful drilling activities conducted in thePiceance and Permian Basins, partially offset by natural productiondeclines.  Due to low natural gas pricesin the Piceance and Uintah Basins, the Company delayed the completion andpipeline connection of several newly drilled wells until the latter part of2002.  For the year ended December 31,2002, Carbon USA participated in the drilling of 11 gross (5.4 net) wells ofwhich four gross (.3 net) were completed as oil wells, four gross (2.8 net)were completed as gas wells, and three gross (2.3 net) wells were abandoned asdry holes.  For the year ended December31, 2001, Carbon USA participated in the drilling of 35 gross (22.3 net) wellsof which ten gross (5.0 net) were completed as oil wells, 22 gross (14.8 net)were completed as gas wells and three gross (2.5 net) wells were abandoned asdry holes.

 

Averageproduction in Canada for the year ended December 31, 2002 was 138 barrelsof oil and liquids per day and 6.1 MMcf of gas per day, a decrease of 9% from2001 on an Mcfe basis.  The decrease wasdue primarily to the voluntary curtailment of natural gas and liquidsproduction during the third quarter of 2002 and natural production declines inall operating areas, partially offset by successful drilling activities in theCarbon and Rowley areas of central Alberta. In addition, due to low natural gas prices in central Alberta, theCompany delayed the completion and pipeline connection of several newly drilledwells until the fourth quarter of 2002. For the year ended December 31, 2002, Carbon Canada participated in thedrilling of 17 gross (10.5 net) wells of which 16 gross (10.0 net) werecompleted as gas wells and one gross (.5 net) well was abandoned as a dryhole.  For the year ended December 31,2001, Carbon Canada participated in the drilling of 11 gross (10.5 net) wellsall of which were completed as gas wells.

 

Averageoil and liquids prices realized by Carbon USA decreased 14% from $25.49 perbarrel for the year ended December 31, 2001 to $21.92 for 2002.  The average oil price includes hedge lossesof $83,000 or $.90 per barrel for the year ended December 31, 2002compared to hedge gains of $25,000 or $.30 per barrel for 2001.  Average natural gas prices realized byCarbon USA decreased 26% from $2.94 per Mcf for the year ended December 31,2001 to $2.17 per Mcf for 2002.  Theaverage natural gas price includes hedge gains of $400,000 or $.14 per Mcf forthe year ended December 31, 2002 compared to hedge losses of$1.5 million or $.53 per Mcf for 2001.

 

Averageoil and liquids prices realized by Carbon Canada decreased 10% from $21.76 perbarrel for the year ended December 31, 2001 to $19.62 for 2002.  The average oil and liquids price includeshedge losses of $8,000 or $.16 per barrel for the year ended December 31,2002 compared to hedge gains of $33,000 or $.56 per barrel for 2001.  Average natural gas prices realized byCarbon Canada decreased 27% from $4.05 per Mcf for the year endedDecember 31, 2001 to $2.95 for 2002. The average natural gas price includes hedge gains of $3,000 for theyear ended December 31, 2002 compared to hedge losses of $571,000 or $.24per Mcf for 2001.

 

Marketingand other revenues for Carbon USA decreased 35% from $532,000 for the yearended December 31, 2001 to $344,000 for 2002.  Marketing revenue for the year ended December 31, 2001 includedmark-to-market gains of $1.2 million related to a derivative contract thatdid not qualify for hedge accounting treatment under provisions of Statement ofFinancial Accounting Standards (SFAS) No. 133, “Accounting for DerivativeInstruments and Hedging Activities.” In conjunction with the adoption of SFASNo. 133, on January 1, 2001, the Company recorded a derivative loss (netof tax) of $1.5 million as the cumulative effect of a change in accountingprinciple related to this derivative contract. During the third quarter of 2001, the Company recorded a $625,000impairment for an outstanding account receivable from a purchaser of theCompany’s gas production.  In addition,during 2001, the Company entered into certain commodity derivative contractswith Enron North America Corporation (ENAC), a subsidiary of Enron Corporation(Enron).  During the fourth quarter of2001, Enron and ENAC filed for Chapter 11 bankruptcy, and the Companydetermined that the ENAC contracts no longer qualified for cash flow hedgeaccounting treatment under SFAS No. 133. Consequently, in 2001 the Company recorded a loss of $328,000 consistingof $82,000 related to oil and gas hedge contracts that had or would havesettled in 2001 and $246,000 related to contracts that would have settled in2002.  The amount deferred inaccumulated other comprehensive income at December 31, 2001 of $246,000 wasreclassified to earnings during 2002 based on the originally scheduledsettlement periods of the contracts.

 

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Directlifting costs incurred by Carbon USA were $1.6 million or $.45 per Mcfefor the year ended December 31, 2002 compared to $1.7 million or $.50per Mcfe for 2001.  The decrease indirect lifting costs was primarily due to a decrease in the number of wellworkovers and equipment repairs compared to the year ended December 31, 2001.

 

Other production costs incurred by Carbon USA consisting primarily ofseverance taxes and production overhead were $1.6 million for the yearended December 31, 2002 compared to $1.9 million for 2001.  The decrease was primarily due to lowerseverance taxes as a result of lower oil, liquids and gas prices and a creditfor prior period ad valorem taxes, partially offset by increased oil, liquidsand gas production.

 

Directlifting costs incurred by Carbon Canada were $1.7 million or $.67 per Mcfefor the year ended December 31, 2002 compared to $1.6 million or $.58 perMcfe for 2001.  The higher per Mcfeexpense for the year ended December 31, 2002 was primarily due to compressionexpenses associated with the production of natural gas in Alberta and theeffect of fixed operating costs that were not reduced during the voluntarycurtailment of production during the third quarter of 2002.

 

Generaland administrative expenses incurred by Carbon USA (net of overheadreimbursements on operated wells), increased 4% from $2.8 million for theyear ended December 31, 2001 to $2.9 million for 2002.  The increase was primarily due to one timelegal expenses of $160,000 related to unsuccessful litigation in which theCompany was a plaintiff that was concluded in 2002.  For the years ending December 31, 2001 and 2002, Carbon USAcapitalized $196,000 and $162,000, respectively, of G&A related togeological and geophysical activities.

 

Generaland administrative expenses incurred by Carbon Canada (net of overheadreimbursements on operated wells) increased 16% from $1.7 million for the yearended December 31, 2001 to $2.0 million for 2002.  The increase was primarily due to salary increases, personneladditions and increased consulting costs in conjunction with the Company’shigher level of capital expenditures.

 

Interestand other expense incurred by Carbon USA increased 23% from $653,000 for theyear ended December 31, 2001 to $804,000 for 2002.  The increase was due primarily to increasedaverage debt balances during the year ended December 31, 2002 relative to 2001,partially offset by lower borrowing rates.

 

Interestand other expense incurred by Carbon Canada increased 19% from $210,000 for theyear ended December 31, 2001 to $250,000 for 2002.  The increase was due primarily to increasedaverage debt balances during the year ended December 31, 2002 relative to 2001,partially offset by lower borrowing rates.

 

Depreciation,depletion and amortization (DD&A) of oil and gas assets is calculated usingthe units of production method. DD&A is typically determined by usinghistorical capitalized costs incurred to find, develop and recover oil and gasreserves. However, the Company’s DD&A rate has been determined primarily bythe purchase price incurred by the Company in its acquisitions of Carbon USAand Carbon Canada, the volume of proved reserves the Company acquired in theacquisitions and a ceiling test impairment recorded by the Company in thesecond quarter of 2002.

 

DD&Aexpense incurred by Carbon USA was $3.6 million or $1.01 per Mcfe for the yearended December 31, 2002 compared to $3.5 million or $1.07 per Mcfe for 2001.The decreased rate is primarily due to the ceiling test impairment recorded bythe Company in the second quarter of 2002, partially offset by an increase inthe DD&A rate per Mcfe due to the capitalized cost per Mcfe of reservesadded in 2001.

 

DD&Aexpense incurred by Carbon Canada was $2.5 million or $.99 per Mcfe compared to$2.7 million or $.97 per Mcfe for 2001. The increased rate for the year ended December 31, 2002 compared to 2001is due to the capitalized cost per Mcfe of reserves added during 2001,partially offset by a ceiling test impairment recorded by the Company in thesecond quarter of 2002.

 

The non-cash ceiling test impairment of the Company’s full cost poolwas recorded because the capitalized cost of its oil and natural gas reservesin the United States and Canada exceeded the ceiling limitation established forthose reserves.  The United StatesSecurities and Exchange Commission (SEC) requires that public companiesutilizing

 

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the full cost method of accounting for oil and gas properties perform aceiling test at the end of each quarterly reporting period.  The ceiling test limitation requires thatcapitalized costs less related accumulated depletion and deferred income taxesmay not exceed the sum of the present value of future net revenue fromestimated production of proved oil and gas reserves using a 10% discount factorand unescalated oil and gas prices and costs as of the end of the period; plusthe cost of properties not being amortized, if any; plus the lower of cost orestimated fair value of unproved properties included in the costs beingamortized, if any; less related income tax effects.  Under the SEC guidelines, the natural gas and oil prices used todetermine the future value of the Company’s oil and gas reserves is the pricereceived for production on the last day of the reporting period (withconsideration of price changes only to the extent provided by contractualarrangements).  The SEC allows the useof hedge adjusted prices in the full cost ceiling test and the Company’sceiling test was reflective of that methodology.

 

At June 30, 2002, the methodology requiredthe Company to use natural gas prices of $1.10 per MMBtu for Colorado and Utahand $1.43 per MMBtu for central Alberta. These prices were $2.32 per MMBtu for Colorado and Utah and $1.99 perMMBtu for Alberta less than the price for natural gas delivered to Henry Hub,the principal reference price for natural gas in the United States.  The differential was considerably greaterthan the 36 month average historical differential at June 30, 2002 of $.37 perMMBtu for Colorado and Utah and $.29 per MMBtu for Alberta.  The Company’s capitalized costs exceeded theceiling limitation in the United States and Canada by $14.0 million and $2.4 million,respectively. When product prices were adjusted for oil and natural gas hedgesin place at June 30, 2002, the Company’s capitalized costs exceeded theceiling limitation in the United States and Canada by $12.0 million and $1.2million, respectively.  At June 30,2002, the Company recorded a $12.0 million and $1.2 million non-cashcharge in the United States and Canada, respectively, to reflect theseimpairments. See Note 1 to the Consolidated Financial Statements foradditional information.

 

During the fourth quarter of 2002, natural gas prices received byCarbon for production in Colorado and Utah, where approximately 60% of theCompany’s domestic production is located, averaged approximately $2.50 perMMBtu, nearly $1.50 per MMBtu less than the price posted for natural gasdelivered to Henry Hub.  For most of2002, natural gas prices for production in these areas were low relative to therest of the producing areas in the United States.  Lack of regional seasonal demand and inadequate pipeline transportationcapacity necessary to transport natural gas to consuming regions is theprincipal factor contributing to the large price differentials.  The prospect of additional pipeline capacityout of the region is expected to help alleviate the high price differentialsreceived by Carbon and other Rocky Mountain gas producers.  Continued volatility is expected to affectthe price received for natural gas produced by Carbon in the United States andCanada.

 

Incometax expense incurred by Carbon USA was $746,000 for the year ended December 31,2002 compared to $135,000 for 2001.  Dueprimarily to the low commodity prices resulting in the full cost ceilingimpairment recorded during the second quarter of 2002, the Company recorded adeferred tax asset valuation allowance of $5.6 million for the year endedDecember 31, 2002.

 

Income tax expense incurred by Carbon Canada was $1,000 for the yearended December 31, 2002 compared to $2.0 million for 2001.  The decrease in the effective tax rate forthe year ended December 31, 2002 was due to permanent differences in thedeductibility of Canadian royalties for oil, liquids, and natural gas versus aresource allowance, that was magnified due to the small ($212,000) loss beforeincome taxes for the year ended December 31, 2002.

 

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RESULTSOF OPERATIONS - COMPARISON OF 2001 RESULTS TO 2000

 

Thefollowing table and the discussion that follows present comparative revenue,sales volumes, average sales prices, expenses and the percentage change betweenperiods for the years ended December 31, 2001 and 2000.  The Company’s Canadian operations wereestablished in February 2000 through an exchange offer of Carbon sharesfor shares of Carbon Canada.  Theresults for the Company’s Canadian operations for 2000 in the following tableare pro forma to reflect the acquisition of Carbon Canada as if it had occurredon January 1, 2000.  No otheradjustments from reported net income were made in the preparation of thisschedule.

 
|                                     |   | **United States  For the Year Ended  December 31,**                 |   | **Canada  For the Year Ended  December 31,**                        |   |
|------------------------------------------|--------|---------------------------------------------------------------------|--------|---------------------------------------------------------------------|--------|
|                                     |   | **2001**                                                            |   | **2000**                                                            |   | **Change** |   | **2001** |   | **2000** |   | **Change** |   |
|                                     |   | **(Dollars in thousands, except  prices and per Mcfe information)** |   | **(Dollars in thousands, except  prices and per Mcfe information)** |   |
| Revenues:                                |   |                                                                |   |                                                                |   |   |   |   |   |   |   |   |   |
| Oil and gas revenues                     |   | $                                                                   | 10,341 |                                                                | $      | 11,054 |   | -6 | % | $ | 11,080 |   | $ | 5,945 |   | 86 | % |
| Marketing and other, net                 |   | 532                                                                 |   | 245                                                                 |   | 117 | % | 2 |   | (70 | ) | n/a |   |
| Total revenues                           |   | 10,873                                                              |   | 11,299                                                              |   | -4 | % | 11,082 |   | 5,875 |   | 89 | % |
|                                     |   |                                                                |   |                                                                |   |   |   |   |   |   |   |   |   |
| Daily sales volumes:                     |   |                                                                |   |                                                                |   |   |   |   |   |   |   |   |   |
| Natural gas (MMcf)                       |   | 7.7                                                                 |   | 9.2                                                                 |   | -16 | % | 6.6 |   | 4.0 |   | 65 | % |
| Oil and liquids (Bbl)                    |   | 222                                                                 |   | 190                                                                 |   | 17 | % | 161 |   | 122 |   | 32 | % |
| Equivalents production (MMcfe 6:1)       |   | 9.0                                                                 |   | 10.3                                                                |   | -13 | % | 7.6 |   | 4.7 |   | 62 | % |
|                                     |   |                                                                |   |                                                                |   |   |   |   |   |   |   |   |   |
| Average price realized:                  |   |                                                                |   |                                                                |   |   |   |   |   |   |   |   |   |
| Natural gas (Mcf)                        |   | $                                                                   | 2.94   |                                                                | $      | 2.80 |   | 5 | % | $ | 4.05 |   | $ | 3.34 |   | 21 | % |
| Oil and liquids (Bbl)                    |   | 25.49                                                               |   | 23.03                                                               |   | 11 | % | 21.76 |   | 23.33 |   | -7 | % |
|                                     |   |                                                                |   |                                                                |   |   |   |   |   |   |   |   |   |
| Direct lifting costs                     |   | $                                                                   | 1,654  |                                                                | $      | 1,602 |   | 3 | % | $ | 1,612 |   | $ | 873 |   | 85 | % |
| Average direct lifting costs/Mcfe        |   | 0.50                                                                |   | 0.42                                                                |   | 19 | % | 0.58 |   | 0.50 |   | 16 | % |
| Other production costs                   |   | 1,901                                                               |   | 2,172                                                               |   | -12 | % | 14 |   | — |   | n/a |   |
| General and administrative, net          |   | 2,767                                                               |   | 1,989                                                               |   | 39 | % | 1,736 |   | 1,373 |   | 26 | % |
| Depreciation, depletion and amortization |   | 3,536                                                               |   | 4,042                                                               |   | -13 | % | 2,698 |   | 1,698 |   | 59 | % |
| Interest and other expense, net          |   | 653                                                                 |   | 917                                                                 |   | -29 | % | 210 |   | 234 |   | -10 | % |
| Income tax provision                     |   | 135                                                                 |   | 44                                                                  |   | 207 | % | 1,956 |   | 681 |   | 187 | % |

 

Revenuesfor oil and gas sales of Carbon USA for the year ended December 31, 2001were $10.3 million, a 6% decrease from 2000.  The decrease was due primarily to decreased gas sales and naturalproduction declines in all operating areas partially offset by increased oilproduction and increased oil and gas prices.

 

Revenuesfor oil, liquids and gas sales of Carbon Canada for the year endedDecember 31, 2001 were $11.1 million, an increase of 86% from2000.  The increase was due primarily toincreased oil, liquids and gas production and higher gas prices.

 

CarbonUSA’s average production for the year ended December 31, 2001 was 222barrels of oil per day and 7.7 million cubic feet (MMcf) of gas per day, adecrease of 13% from 2000 on a Mcf equivalent (Mcfe) basis where one barrel ofoil is equal to six Mcf of gas.  InJanuary 2001, the Company divested its entire working interests andrelated leasehold rights in the San Juan Basin.  Exclusive of this disposition, the Company would have increasedits production for the year ended December 31, 2001 compared to 2000 by 4%on an Mcfe basis.  The increase inproduction was due to successful drilling activities conducted during 2001 inthe Piceance and Permian Basins, offset by natural production declines in alloperating areas.  For the year endedDecember 31, 2001, Carbon USA participated in the drilling of 35 gross (22.3net) wells of which ten gross (5.0 net) were completed as oil wells, 22 gross(14.8 net) were completed as gas wells and three gross (2.5 net) wells wereabandoned as dry holes.  For the yearended December 31, 2000, Carbon USA

 

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participatedin the drilling of 15 gross (6.7 net) wells of which ten gross (2.9 net) werecompleted as oil wells and five gross (3.8 net) wells were abandoned as dryholes.

 

CarbonCanada’s average production for the year ended December 31, 2001 was 161barrels of oil and liquids per day and 6.6 MMcf of gas per day, an increase of62% from 2000 on an Mcfe basis.  Theincrease was due primarily to successful drilling and recompletion activitiesin the Carbon and Rowley areas of central Alberta.  For the year ended December 31, 2001, Carbon Canada participatedin the drilling of 11 gross (10.5 net) wells all of which were completed as gaswells.  For the year ended December 31,2000, Carbon Canada participated in the drilling of eight gross (4.9 net) wellsall of which were completed as gas wells.

 

Averageoil prices realized by Carbon USA increased 11% from $23.03 per barrel for theyear ended December 31, 2000 to $25.49 for 2001.  The average oil price includes hedge gains of $25,000 or $.30 perbarrel for the year ended December 31, 2001 compared to hedge losses of$414,000 or $5.98 per barrel for 2000. Average natural gas prices realized by Carbon USA increased 5% from$2.80 per Mcf for the year ended December 31, 2000 to $2.94 per Mcf for2001.  The average natural gas priceincludes hedge losses of $1.5 million or $.53 per Mcf for the year endedDecember 31, 2001 compared to hedge losses of $2.6 million or $.78per Mcf for 2000.

 

Averageoil and liquids prices realized by Carbon Canada decreased 7% from $23.33 perbarrel for the year ended December 31, 2000 to $21.76 for 2001.  The average oil and liquids price includeshedge gains of $33,000 or $.56 per barrel for the year ended December 31,2001 compared to hedge losses of $186,000 or $3.51 per barrel for 2000.  Average natural gas prices realized byCarbon Canada increased 21% from $3.34 per Mcf for the year endedDecember 31, 2000 to $4.05 for 2001. The average natural gas price includes hedge losses of $571,000 or $.24per Mcf for the year ended December 31, 2001 compared to hedge losses of$987,000 or $.59 per Mcf for 2000.

 

Marketingand other revenues for Carbon USA increased 117% from $245,000 for the yearended December 31, 2000 to $532,000 for 2001.  Marketing revenue for the year ended December 31, 2001 includedmark-to-market gains of $1.2 million related to a derivative contract thatdid not qualify for hedge accounting treatment under provisions of SFAS No.133, “Accounting for Derivative Instruments and Hedging Activities.” Inconjunction with the adoption of SFAS No. 133, on January 1, 2001, theCompany recorded a derivative loss (net of tax) of $1.5 million as thecumulative effect of a change in accounting principle related to this derivativecontract.  During the third quarter of2001, the Company recorded a $625,000 impairment for an outstanding accountreceivable from a purchaser of the Company’s gas production.  In addition, during 2001, the Companyentered into certain commodity derivative contracts with Enron North AmericaCorporation (ENAC), a subsidiary of Enron Corporation (Enron).  During the fourth quarter of 2001, Enron andENAC filed for Chapter 11 bankruptcy, and the Company determined that the ENACcontacts no longer qualified for cash flow hedge accounting treatment underSFAS No. 133.  Consequently, the Companyrecorded a loss of $328,000 consisting of $82,000 related to oil and gas hedgecontracts that had or would have settled in 2001 and $246,000 related tocontracts that would have settled in 2002.

 

Directlifting costs incurred by Carbon USA were $1.7 million or $.50 per Mcfefor the year ended December 31, 2001 compared to $1.6 million or $.42per Mcfe for 2000.  The per Mcfeincrease was primarily due to well and equipment repairs in the Permian andPiceance Basins performed in 2001.

 

Otherproduction costs incurred by Carbon USA consisting primarily of severance taxesand production overhead were $1.9 million for the year endedDecember 31, 2001 compared to $2.2 million for 2000.  The decrease was primarily due to lowerseverance taxes due to declines in gas production.

 

Directlifting costs incurred by Carbon Canada were $1.6 million or $.58 per Mcfefor the year ended December 31, 2001 compared to $873,000 or $.50 per Mcfefor 2000.  The increase was primarilydue to increased compression costs in the Carbon area which contributed to acorresponding increase in gas production.

 

Generaland administrative expenses incurred by Carbon USA, net of overheadreimbursements, increased 39% from $2.0 million for the year endedDecember 31, 2000 to $2.8 million for 2001.  The increase was primarily due to a reduction in overheadreimbursements as a result of the sale of the Company’s San Juan Basinproperties, salary increases, personnel additions and increased consultingcosts in conjunction with the Company’s higher level of capital

 

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expendituresand legal expenses related to the case of Bonneville Fuels Corporation vs.Williams Production RMT Company.

 

Generaland administrative expenses incurred by Carbon Canada, net of overheadreimbursements, increased 26% from $1.4 million for the year endedDecember 31, 2000 to $1.7 million for 2001.  The increase was primarily due to salary increases, personneladditions and increased consulting costs in conjunction with the Company’shigher level of capital expenditures.

 

Interestand other expense incurred by Carbon USA decreased 29% from $917,000 for theyear ended December 31, 2000 to $653,000 for 2001.  The decrease was due primarily to areduction in average debt balances throughout 2001 as a result of proceedsreceived from the divestiture of the Company’s San Juan Basin properties,decreased margin deposits related to the Company’s derivative positions and adecrease in interest rates, partially offset by increased funding requirementsfor capital expenditures.

 

Interestand other expense incurred by Carbon Canada decreased 10% from $234,000 for theyear ended December 31, 2000 to $210,000 for 2001.  The decrease was due primarily to areduction in debt as a result of increased cash flow from operating activitiesand a decline in interest rates, partially offset by increased fundingrequirements for capital expenditures.

 

Depreciation,depletion and amortization (DD&A) of oil and gas assets is calculated usingthe units of production method. DD&A is typically determined by using historical capitalized costsincurred to find, develop and recover oil and gas reserves.  However, the Company’s current DD&A hasbeen determined primarily by the purchase price incurred in its acquisition ofCarbon USA and Carbon Canada, and the volume of proved reserves the Companyacquired in the acquisitions.  Forinformation regarding full cost accounting and DD&A, see Note 1 to theConsolidated Financial Statements.

 

DD&A expense incurred by Carbon USA decreased 13% from$4.0 million for the year ended December 31, 2000 to$3.5 million for 2001.  Thedecrease was due primarily to decreased production.  DD&A was $1.07 per Mcfe for the years ended December 31,2000 and 2001.

 

DD&Aexpense incurred by Carbon Canada increased 59% from $1.7 million for theyear ended December 31, 2000 to $2.7 million for 2001.  The increase resulted primarily fromincreased production.  DD&A expensewas $.98 per Mcfe for the year ended December 31, 2000 compared to $.97per Mcfe for 2001.

 

Incometax expense incurred by Carbon USA was $135,000 for the year endedDecember 31, 2001, an effective rate of 37%.  This compares to income tax expense of $44,000 or an effectiverate of 8% for 2000.  The effective ratein 2000 was the result of a reversal of an income tax valuation allowance of$192,000.

 

Incometax expense incurred by Carbon Canada was $2.0 million for the year endedDecember 31, 2001 compared to $681,000 for 2000.  The effective rate was 40% for both years.

 

## LIQUIDITY AND CAPITAL RESOURCES

 

AtDecember 31, 2002, the Company had $52.3 million of assets.  Total capitalization was $41.3 million,consisting of 45% of stockholders’ equity and 55% of debt.

 

Fora discussion of the Company’s credit facilities, see Note 3 to the ConsolidatedFinancial Statements in this report.

 

Netcash provided by operations for the year ended December 31, 2002 was $2.7million compared to $14.2 million in 2001. Net cash provided by operations prior to changes in working capital forthe year ended December 31, 2002 was $5.5 million compared to $8.6 million in2001.  The decrease in operating cashflow in 2002 compared to 2001 was primarily due to declines in oil, liquids andnatural gas prices in all areas and voluntary curtailments of production in thethird quarter of 2002 because of low gas prices, partially offset by increasedoil, liquids and gas production in the United States for 2002.

 

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Netcash provided by operations for the year ended December 31, 2001 was $14.2million compared to $3.8 million in 2000. Net cash provided by operations prior to changes in working capital forthe year ended December 31, 2001 was $8.6 million compared to $7.5 million in2000.  The increase in operating cashflow in 2001 compared to 2000 was primarily due to increased oil, liquids andgas production in Canada, increased oil, liquids and natural gas prices in allareas and decreased working capital requirements, especially a decline inmargin deposit requirements for the Company’s derivative accounts.

 

Forthe year ended December 31, 2002, Carbon USA spent approximately $4.5 millionprimarily to fund development and exploration activities in Colorado, Montana,New Mexico and Utah.  Carbon USAreceived $3.1 million in proceeds related to the disposition of certainoverriding royalty interests in the Piceance and Permian Basin and the sale ofworking interests and related leasehold rights in New Mexico and Kansas.  For the year ended December 31, 2002, CarbonCanada spent approximately $6.1 million primarily to fund development andexploration activities in the Carbon area and for the acquisition of propertiesin the Rowley area of central Alberta.

 

Forthe year ended December 31, 2001, Carbon USA spent approximately $16.6 millionprimarily to fund development and exploration activities in Colorado, Utah andNew Mexico.  Carbon USA also received$6.8 million in proceeds related to the disposition of the Company’s entireworking interest and related leasehold rights in the San Juan Basin.  For the year ended December 31, 2001, CarbonCanada spent approximately $6.7 million primarily to fund developmentactivities in the Carbon area of central Alberta.

 

Forthe year ended December 31, 2000, Carbon USA spent approximately $4.8 millionprimarily to fund development and exploration activities in New Mexico.  For the year ended December 31, 2000, CarbonCanada spent approximately $3.1 million primarily to fund developmentactivities in the Carbon area of central Alberta.

 

Carbon’sprimary cash requirements for 2003, subject to completion of the proposedmerger described previously, will be to fund exploration and developmentexpenditures, finance acquisitions, repay debt, and for general working capitalneeds. At December 31, 2002, the Company had no cash balances as all availablecash flow generated from operations was used to pay down the Company’slong-term debt.  The Company hasbudgeted capital expenditures for 2003, exclusive of unplanned acquisitions ordivestitures, of approximately $21 million. At December 31, 2002, the Company is in compliance with all of its debtcovenants and has no reason to believe that either of its credit facilitieswill require principal payments during the next twelve months.  Under the facilities, funds available atDecember 31, 2002 were approximately $3.3 million.  In addition, the new U.S. facility secured on December 31, 2002with the Bank of Oklahoma National Association (Bank of Oklahoma) will providethe Company with an additional borrowing capability of $1.9 million compared toits current facility, for a total borrowing capacity of $5.2 million.

 

OnMarch 24, 2003, Carbon USA closed on the sale of its interests in 97 gross(23.3 net) wells and 25,400 gross (8,200 net) acres located primarily insoutheastern New Mexico.  The sale pricewas $15.7 million with an effective date of January 1, 2003.  The Company will initially use the proceedsfrom the sale to pay down debt and anticipates utilizing the resultingborrowing capacity to accelerate its 2003 exploration and development drillingprogram in the Piceance and Uintah Basins. The Company anticipates that there will be some downward modification toits bank borrowing capacity as a result of the sale of properties in March2003, nevertheless, Carbon believes that available borrowings under its creditagreements, projected operating cash flows and cash received from the March2003 asset sale will be sufficient to cover its working capital, plannedcapital expenditures, and debt service requirements for the next12 months.

 

TheCompany’s future cash flow is subject to a number of variables, including thelevel of production, commodity prices and capital expenditures.  Also, borrowings under Carbon’s creditfacilities are subject to a number of conditions, including compliance withvarious covenants and borrowing base calculations.  As a result, there can be no assurance that the operations andother capital resources will provide cash in sufficient amounts to maintainplanned levels of capital expenditures or to meet the other cash needs.

 

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Thetable below sets forth the Company’s contractual obligations atDecember 31, 2002 and the effect such obligations are expected to have onits liquidity and cash flow in future periods (in thousands):

 
|                        |   | **Payments Due By Period** |   |
|-----------------------------|--------|----------------------------|--------|
| **Contractual Obligations** |   | **Less than  1 Year**      |   | **1 - 3  Years** |   | **4 - 5  Years** |   |
|                        |   |                       |   |   |   |   |   |
| Revolving credit facility   |   | $                          | — |   | $ | 22,709 |   | $ | — |   |
| Operating leases            |   | 435                        |   | 303 |   | — |   |
| Transporation agreements    |   | 113                        |   | 107 |   | — |   |
|                        |   | $                          | 548    |   | $ | 23,119 |   | $ | — |   |

 

Contractual obligationsfor the Company's revolving credit facilities are presented prior to the March24, 2003 sale of Carbon USA's interests in southeastern New Mexico for $15.7million.

 

DISCLOSURESREGARDING FORWARD-LOOKING STATEMENTS

 

ThisAnnual Report on Form 10-K includes “forward-looking statements”.  All statements other than statements ofhistorical facts included in the Annual Report on Form 10-K are forward-lookingstatements.  Such statements addressactivities, events or developments that the Company expects, believes,projects, intends or anticipates will or may occur, including such matters asfuture capital, development and exploration expenditures, reserve estimates(including estimates of future net revenues associated with such reserves andthe present value of such future net revenues), future production of oil andnatural gas, business strategies, expansion and growth of the Company’soperations, cash flow and anticipated liquidity, prospect development andproperty acquisition, obtaining financial or industry partners for prospect orprogram development, or marketing of oil and natural gas.  Although the Company believes that theexpectations reflected in the forward-looking statements and the assumptionsupon which such forward-looking statements are based are reasonable, it can giveno assurance that such expectations and assumptions will prove to becorrect.  Factors that could causeactual results to differ materially (“Cautionary Statements”) are described, inamong other places in the Marketing, Competition, and Government Regulationsections in this Form 10-K and under “Management’s Discussion and Analysisof Financial Condition and Results of Operations.” These factors include, butare not limited to general economic conditions, the market price of oil andnatural gas, the risks associated with exploration, the Company’s ability tofind, acquire, market, develop and produce new properties, operating hazardsattendant to the oil and natural gas business, uncertainties in the estimationof proved reserves and in the projection of future rates of production andtiming of development expenditures, the strength and financial resources of theCompany’s competitors, the Company’s ability to find and retain skilledpersonnel, climatic conditions, labor relations, availability and cost ofmaterial and equipment, environmental risks, the results of financing efforts,and regulatory developments.  Allwritten and oral forward-looking statements attributable to the Company orpersons acting on its behalf are expressly qualified in their entirety by theCautionary Statements.  The Companyundertakes no obligation to update any forward-looking statements to reflectfuture events or developments.

 

## CRITICAL ACCOUNTING POLICES

 

Thefollowing summarizes several of our critical accounting policies.  See a complete list of significant accountingpolicies in Note 1 to the Consolidated Financial Statements.

 

Propertyand Equipment -  The Company follows the full cost method ofaccounting for its oil and gas properties, whereby all costs incurred in theacquisition, exploration and development of properties (including costs ofsurrendered and abandoned leaseholds, delay lease rentals, dry holes and directoverhead related to exploration and development activities) are capitalized.

 

Capitalizedcosts are accumulated  for the UnitedStates and Canada as separate cost centers and are depleted using the units ofproduction 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 sixthousand cubic feet of gas is equal to one barrel of oil.  The estimated future cost of siterestoration, dismantlement and abandonment activities is provided for as a

 

23

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componentof depletion.  Investments in unprovedproperties are recorded at the lower of cost or fair market value and are notdepleted pending the determination of the existence of proved reserves.

 

Pursuantto full cost accounting rules, capitalized costs less related accumulateddepletion and deferred income taxes may not exceed the sum of the present valueof future net revenue from estimated production of proved oil and gas reservesusing a 10% discount factor and unescalated oil and gas prices and costs as ofthe 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 includedin the costs being amortized, if any; less related income tax effects.

 

A non-cash ceiling test impairment of the Company’s full cost pool wasrecorded in the second quarter of 2002 because the capitalized cost of its oiland natural gas reserves in the United States and Canada exceeded the ceilinglimitation established for those reserves. The SEC requires that public companies utilizing the full cost method ofaccounting for oil and gas properties perform a ceiling test at the end of eachquarterly reporting period.  Under theSEC guidelines, the natural gas and oil prices used to determine the futurevalue of the Company’s oil and gas reserves is the price received forproduction on the last day of the reporting period (with consideration of pricechanges only to the extent provided by contractual arrangements).

 

Should natural gas and crude oil prices decline in the future, even ifonly for a brief period of time, it is possible that additional impairments ofoil and gas properties could occur.

 

Proceedsfrom disposal of interests in oil and gas properties are accounted for asadjustments of capitalized costs with no gain or loss recognized, unless suchadjustment would significantly alter the rate of depletion.

 

DerivativeInstrument and Hedging Activities - Pursuant to Company guidelines, the Company utilizes derivativeinstruments only as a hedging mechanism and does not enter into speculativetransactions. The Company has a Risk Management Committee to administer andapprove all hedging transactions. Gains or losses from financial instrumentsthat qualify for hedge accounting treatment are recognized as an adjustment tosales revenue in the period in which the financial instrument matures. Gains orlosses from financial instruments that do not qualify for hedge accountingtreatment are recognized currently as other income or expense. The cash flowsfrom such agreements are included in operating activities in the consolidatedstatements of cash flows.

 

The estimation of fair values for the Company’s hedging derivativesrequires substantial judgment. The fair values of the Company’s derivatives areestimated on a monthly basis using an option-pricing model. The option-pricingmodel uses various factors that include closing exchange prices, volatility andthe time value of options. The estimated future prices are compared to theprices fixed by the hedge agreements, and the resulting estimated future cashinflows (outflows) over the lives of the hedges are discounted. These pricingand discounting variables are sensitive to market volatility as well as tochanges in future price forecasts, regional price differentials and interestrates.

 

Valuation of Deferred Tax Assets –The Company uses the asset and liability method of accounting for income taxes.Under this method, future income tax assets and liabilities are determinedbased on differences between the financial statement carrying values and theirrespective income tax bases (temporary differences). Future income tax assetsand liabilities are measured using the tax rates expected to be in effect whenthe temporary differences are likely to reverse. The effect on future incometax assets and liabilities of a change in tax rates is included in operationsin the period in which the change is enacted. The amount of future income taxassets recognized is limited to the amount of the benefit that is more likelythan not to be realized.

 

In assessing the realizability of deferred tax assets, managementconsiders whether it is more likely than not that some portion or all of thedeferred tax assets will not be realized. The ultimate realization of deferredtax assets is dependent upon the generation of future taxable income during theperiods in which those temporary differences become deductible. Managementconsiders the scheduled reversal of deferred tax liabilities, projected futuretaxable income, and tax planning strategies in making this assessment.

 

24

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# **ITEM 7A.              QUANTITATIVE AND QUALITATIVEDISCLOSURES ABOUT MARKET RISK**

 

## INTEREST RATE RISK

 

Because of its debt position, the Company is exposed to interest raterisk on the unhedged portion of its debt. Interest rate risk is estimated asthe potential change in the fair value of interest sensitive investmentsresulting from an immediate hypothetical change in interest rates. Thesensitivity analysis presents the change in fair value of these instruments andchanges in the Company’s earnings and cash flows assuming an immediate onepercent change in floating interest rates. At December 31, 2002, the Companyhad $16.4 million of floating rate debt through its facility with Wells Fargoand $6.3 million through its facility with CIBC.  The Company currently has interest rate swap agreements thateffectively convert a portion of its variable rate borrowings to fixed ratedebt as described in Note 9 to the Consolidated Financial Statements in thisreport. Assuming constant debt levels, the impact on earnings and cash flow forthe twelve month period beginning January 1, 2003, from a one percent change ininterest rates would be approximately $157,000 before taxes.

 

## FOREIGN CURRENCY RISK

 

The Canadian dollar is the functional currency of Carbon Canada. TheCompany is subject to foreign currency exchange rate risk on cash flowsrelating to sales, expenses, financing and investing transactions. The Companyhas not entered into foreign currency forward contracts or other similarfinancial instruments to manage this risk.

 

## COMMODITY PRICE RISK

 

Oil and gas commodity markets are influenced by global and regionalsupply and demand factors.  Worldwidepolitical events can also impact commodity prices.  The prices received by Carbon for its natural gas production aredetermined mainly by factors affecting North American regional supply anddemand for natural gas.  Based uponrecent reportable events, it is possible that published indices used toestablish the price received for the Company’s natural gas production may notbe an accurate indication of the market price for natural gas.

 

At December 31, 2002, approximately 60% of the Company’s United Statesproduction is in Colorado and Utah. After March 2002, natural gas prices for production in these areas wereunusually low relative to the rest of the producing areas in the UnitedStates.  Lack of regional seasonaldemand and inadequate pipeline transportation capacity necessary to transportnatural gas to consuming regions are principal factors contributing to thelarge price differentials.  The prospectof additional pipeline capacity out of the region is expected to help alleviatethe high price differentials received by Carbon and other Rocky Mountain gasproducers.  However, continuedvolatility is expected to affect the price received for natural gas produced byCarbon in the United States and Canada.

 

The Company may use certain financial instruments including swaps,collars, futures and other contracts in an attempt to reduce exposure tofluctuations in the price of oil and natural gas by establishing fixed pricesor hedges for its natural gas production. Hedging the Company’s oil and natural gas production may limit the Company’sexposure to price declines or limit the benefit of price increases.  Risks associated with the practice ofhedging include counterparty credit risk, Carbon’s inability to deliverrequired physical volumes of gas which support the Company’s hedges,inefficient or non-correlatable hedges, basis risk, inability to liquidatehedge positions if desired and other unforeseen economic factors.

 

25

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Thetable below sets forth the Company’s derivative financial instrument positionsrelated to its natural gas and oil production at December 31, 2002:

 

Swaps:

 
| **Carbon USA Contracts** |   | **Carbon Canada Contracts** |   |
|--------------------------|--------|-----------------------------|--------|
| **Time Period**          |   | **Bbl/  MMBtu**             |   | **Weighted  Average  Fixed Price  Bbl/  MMBtu** |   | **Derivative  Asset/  (Liability)** |   | **Time Period** |   | **Bbl/  MMBtu** |   | **Weighted  Average  Fixed Price  Bbl/  MMBtu** |   | **Derivative  Asset/  (Liability)** |   |
|                     |   |                        |   |   |   | **(thousands)** |   |   |   |   |   |   |   | **(thousands)** |   |
| **Gas**                  |   |                        |   |   |   |   |   | **Gas** |   |   |   |   |   |   |   |
| 01/01/03-12/31/03        |   | 1,400,000                   |   | $ | 3.07 |   | $ | (541 | ) | 01/01/03-12/31/03 |   | 216,000 |   | $ | 2.83 |   | $ | (242 | ) |
|                     |   |                        |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Oil**                  |   |                        |   |   |   |   |   | **Oil** |   |   |   |   |   |   |   |
| 01/01/03-12/31/03        |   | 46,000                      |   | $ | 25.42 |   | $ | (76 | ) | 01/01/03-12/31/03 |   | 37,000 |   | $ | 25.47 |   | $ | (57 | ) |

 

TheCompany periodically enters into long-term physical contracts for a portion ofits natural gas and oil production.  Thetable below sets forth fixed price sales contracts at December 31, 2002:

 

Fixedprice contracts:

 
| **Carbon USA Contracts** |   | **Carbon Canada Contracts** |   |
|--------------------------|--------|-----------------------------|--------|
| **Time Period**          |   | **MMBtu**                   |   | **Weighted  Average  Fixed Price  MMBtu** |   | **Time Period** |   | **MMBtu** |   | **Weighted  Average  Fixed Price  MMBtu** |   |
|                     |   |                        |   |   |   |   |   |   |   |   |   |
| **Gas**                  |   |                        |   |   |   | **Gas** |   |   |   |   |   |
| 01/01/03-03/31/03        |   | 180,000                     |   | 2.57 |   | 01/01/03-12/31/03 |   | 778,000 |   | $ | 3.16 |   |
|                          |        |                             |        |  |  |  |  |  |  |  |  |  |  |

 

# **ITEM 8.                 FINANCIAL STATEMENTS ANDSUPPLEMENTARY DATA**

 

26

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**Carbon EnergyCorporation**

 

**ConsolidatedFinancial Statements**

** **

27

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**INDEX TO FINANCIAL STATEMENTS**

 
| **Independent Auditors’  Report**                                                                                |
|-----------------------------------------------------------------------------------------------------------------------|
|                                                                                                                  |
| **Report of  Independent Public Accountants**                                                                         |
|                                                                                                                  |
| **Consolidated Balance Sheets - December 31, 2002 and 2001**                                                     |
|                                                                                                                  |
| **Consolidated Statements of Operations - For the Years Ended December 31, 2002,  2001 and 2000**                |
|                                                                                                                  |
| **Consolidated Statements of Stockholders’ Equity - For the Years Ended December 31, 2002,  2001 and 2000** |
|                                                                                                                  |
| **Consolidated Statements of Cash Flows - For the Years Ended December 31, 2002,  2001 and 2000**                |
|                                                                                                                  |
| **Notes to Consolidated Financial Statements**                                                                        |

 

28

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### **INDEPENDENTAUDITORS’ REPORT**

### ** **

The Board of Directors and Stockholders

Carbon Energy Corporation

 

We have audited the 2002 consolidated financial statements of CarbonEnergy Corporation (a Colorado corporation) and subsidiaries as listed in theaccompanying index.  These consolidatedfinancial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinionon these consolidated financial statements based on our audit.  The 2001 and 2000 consolidated financialstatements of Carbon Energy Corporation and subsidiaries as listed in theaccompanying index were audited by other auditors who have ceased operations.  Those auditors’ report dated March 22, 2002,on those consolidated financial statements was unqualified and included anexplanatory paragraph that described the change in the Company’s method ofaccounting for derivative instruments and hedging activities discussed in Note1 to the consolidated financial statements.

 

We conducted our audit in accordance with auditing standards generallyaccepted in the United States of America. Those standards require that we plan and perform the audit to obtainreasonable assurance about whether the financial statements are free ofmaterial misstatement.  An auditincludes examining, on a test basis, evidence supporting the amounts anddisclosures in the financial statements. An audit also includes assessing the accounting principles used andsignificant estimates made by management, as well as evaluating the overallfinancial statement presentation.  Webelieve that our audit provides a reasonable basis for our opinion.

 

In our opinion, the 2002 consolidated financial statements referred toabove present fairly, in all material respects, the financial position ofCarbon Energy Corporation and subsidiaries as of December 31, 2002, and theresults of their operations and their cash flows for the year then ended inconformity with accounting principles generally accepted in the United Statesof America.

 

As discussed in Note 1 to the consolidated financial statements, theCompany changed its method of accounting for derivative instruments and hedgingactivities in 2001.

 
|                              | KPMG  LLP |
|-----------------------------------|-----------|
|                              |      |
| Denver,  Colorado  March 21, 2003 |      |

 

29

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### **REPORT OFINDENDENT PUBLIC ACCOUNTANTS**

 

THE FOLLOWING REPORT IS A COPY OF THE PREVIOUSLY ISSUED REPORT FROMARTHUR ANDERSEN LLP (ANDERSEN). ANDERSEN DID NOT PERFORM ANY PROCEDURES IN CONNECTION WITH THIS ANNUALREPORT ON FORM 10-K.  ACCORDINGLY, THISREPORT HAS NOT BEEN REISSUED BY ANDERSEN.

 

ToCarbon Energy Corporation:

 

Wehave audited the accompanying consolidated balance sheets of Carbon EnergyCorporation (a Colorado corporation) and subsidiaries as of December 31,2001 and 2000, and the related consolidated statements of operations,stockholders’ equity and cash flows for the years ended December 31, 2001and 2000 and the period from inception (September 14, 1999) throughDecember 31, 1999.  These financialstatements are the responsibility of the Company’s management.  Our responsibility is to express an opinionon these financial statements based on our audits.

 

Weconducted our audits in accordance with auditing standards generally acceptedin the United States.  Those standardsrequire that we plan and perform the audit to obtain reasonable assurance aboutwhether the financial statements are free of material misstatement.  An audit includes examining, on a testbasis, evidence supporting the amounts and disclosures in the financialstatements.  An audit also includesassessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statementpresentation.  We believe that ouraudits provide a reasonable basis for our opinion.

 

Inour opinion, the consolidated financial statements referred to above presentfairly, in all material respects, the financial position of Carbon EnergyCorporation and subsidiaries as of December 31, 2001 and 2000, and theresults of their operations and their cash flows for the years endedDecember 31, 2001 and 2000 and the period from inception(September 14, 1999) through December 31, 1999, in conformity withaccounting principles generally accepted in the United States.

 

Asexplained in Note 1 to the consolidated financial statements, onJanuary 1, 2001, the Company changed its method of accounting forderivative instruments and hedging activity.

 
|                                   | ARTHUR  ANDERSEN LLP |
|----------------------------------------|----------------------|
|                                   |                 |
| Denver,  Colorado  March 22, 2002 |                 |

 

 

30

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**CARBON ENERGY CORPORATION**

 

### **CONSOLIDATED BALANCE SHEETS**

(in thousands)

 

|                                                               |   | **December 31,** |       |
|--------------------------------------------------------------------|--------|------------------|------------|
|                                                               |   | **2002**         |       | **2001** |   |
| **ASSETS**                                                         |   |             | ** ** |   | ** ** |
|                                                               |   |             | ** ** |   | ** ** |
| Current assets:                                                    |   |             |       |   |   |
| Cash                                                               |   | $                | —     |   | $ | — |   |
| Accounts receivable, trade                                         |   | 3,240            |       | 2,311 |   |
| Prepaid expenses and other                                         |   | 918              |       | 317 |   |
| Current derivative asset                                           |   | —           |       | 341 |   |
| Total current assets                                               |   | 4,158            |       | 2,969 |   |
|                                                               |   |             |       |   |   |
| Property and equipment, at  cost:                                  |   |             |       |   |   |
| Oil and gas properties, using  the full cost method of accounting: |   |             |       |   |   |
| Unproved properties                                                |   | 7,080            |       | 7,500 |   |
| Proved properties                                                  |   | 71,223           |       | 62,750 |   |
| Furniture and equipment                                            |   | 894              |       | 927 |   |
|                                                               |   | 79,197           |       | 71,177 |   |
| Less accumulated depreciation,  depletion and amortization         |   | (31,503          | )          | (12,226 | ) |
| Property and equipment, net                                        |   | 47,694           |       | 58,951 |   |
|                                                               |   |             |       |   |   |
| Deposits and other long-term  assets                               |   | 452              |       | 448 |   |
| Total assets                                                       |   | $                | 52,304     |   | $ | 62,368 |   |

 

|                                                                                                                                                                               |   | **December 31,** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|------------------|------------|
|                                                                                                                                                                               |   | **2002**         |       | **2001** | ** ** |
| **LIABILITIES AND STOCKHOLDERS’ EQUITY**                                                                                                                                      |   |             |       |   |   |
|                                                                                                                                                                               |   |             |       |   |   |
| Current liabilities:                                                                                                                                                               |   |             |       |   |   |
| Accounts payable and accrued expenses                                                                                                                                              |   | $                | 4,914      |   | $ | 5,113 |   |
| Accrued production taxes payable                                                                                                                                                   |   | 337              |       | 527 |   |
| Income taxes payable                                                                                                                                                               |   | —           |       | 1,168 |   |
| Undistributed revenue and other                                                                                                                                                    |   | 1,462            |       | 1,062 |   |
| Current derivative liability                                                                                                                                                       |   | 1,116            |       | 76 |   |
| Deferred income taxes                                                                                                                                                              |   | —           |       | 74 |   |
| Total current liabilities                                                                                                                                                          |   | 7,829            |       | 8,020 |   |
|                                                                                                                                                                               |   |             |       |   |   |
| Long-term debt                                                                                                                                                                     |   | 22,709           |       | 17,870 |   |
|                                                                                                                                                                               |   |             |       |   |   |
| Other long-term liabilities                                                                                                                                                        |   | 37               |       | 18 |   |
|                                                                                                                                                                               |   |             |       |   |   |
| Deferred income taxes                                                                                                                                                              |   | 3,093            |       | 2,577 |   |
|                                                                                                                                                                               |   |             |       |   |   |
| Minority interest                                                                                                                                                                  |   | 28               |       | 29 |   |
| Stockholders’ equity:                                                                                                                                                         |   |             |       |   |   |
| Preferred stock, no par value:  10,000,000 shares authorized, none outstanding                                                                                                     |   | —           |       | — |   |
| Common stock, no par value:  20,000,000 shares authorized, issued and outstanding  6,116,295 shares and 6,079,225 shares at December 31, 2002 and December 31,  2001, respectively |   | 31,987           |       | 31,799 |   |
| Retained earnings (accumulated deficit)                                                                                                                                            |   | (12,017          | )          | 2,538 |   |
| Accumulated other comprehensive loss                                                                                                                                               |   | (1,362           | )          | (483 | ) |
| Total stockholders’ equity                                                                                                                                                    |   | 18,608           |       | 33,854 |   |
| Total liabilities and stockholders’ equity                                                                                                                                    |   | $                | 52,304     |   | $ | 62,368 |   |

 

**The accompanyingnotes 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)

 
|                                                                      |   | **For the Year  Ended  December 31,** |    |
|---------------------------------------------------------------------------|--------|---------------------------------------|---------|
|                                                                      |   | **2002**                              |    | **2001** |   | **2000** |   |
|                                                                      |   |                                  |    |   |   |   |   |
| Revenues:                                                                 |   |                                  |    |   |   |   |   |
| Oil and gas sales                                                         |   | $                                     | 16,176  |   | $ | 21,421 |   | $ | 16,428 |   |
| Marketing and other, net                                                  |   | 344                                   |    | 534 |   | 175 |   |
|                                                                      |   | 16,520                                |    | 21,955 |   | 16,603 |   |
| Expenses:                                                                 |   |                                  |    |   |   |   |   |
| Oil and gas production costs                                              |   | 5,027                                 |    | 5,181 |   | 4,567 |   |
| Depreciation, depletion and amortization                                  |   | 6,142                                 |    | 6,234 |   | 5,536 |   |
| Full cost ceiling impairment                                              |   | 13,218                                |    | — |   | — |   |
| General and administrative, net                                           |   | 4,887                                 |    | 4,503 |   | 3,249 |   |
| Interest and other, net                                                   |   | 1,054                                 |    | 863 |   | 1,128 |   |
| Total operating expenses                                                  |   | 30,328                                |    | 16,781 |   | 14,480 |   |
|                                                                      |   |                                  |    |   |   |   |   |
| Income (loss) before income taxes                                         |   | (13,808                               | )       | 5,174 |   | 2,123 |   |
|                                                                      |   |                                  |    |   |   |   |   |
| Income tax provision:                                                     |   |                                  |    |   |   |   |   |
| Current                                                                   |   | 13                                    |    | 1,518 |   | 250 |   |
| Deferred                                                                  |   | 734                                   |    | 573 |   | 417 |   |
| Total taxes                                                               |   | 747                                   |    | 2,091 |   | 667 |   |
|                                                                      |   |                                  |    |   |   |   |   |
| Income (loss) before cumulative effect of change  in accounting principle |   | (14,555                               | )       | 3,083 |   | 1,456 |   |
|                                                                      |   |                                  |    |   |   |   |   |
| Cumulative effect of change in accounting principle, net  of tax          |   | —                                |    | (1,510 | ) | — |   |
|                                                                      |   |                                  |    |   |   |   |   |
| Net income (loss)                                                         |   | $                                     | (14,555 | ) | $ | 1,573 |   | $ | 1,456 |   |
|                                                                      |   |                                  |    |   |   |   |   |
| Average number of common shares outstanding:                              |   |                                  |    |   |   |   |   |
| Basic                                                                     |   | 6,101                                 |    | 6,055 |   | 5,822 |   |
| Diluted                                                                   |   | 6,101                                 |    | 6,294 |   | 5,874 |   |
|                                                                      |   |                                  |    |   |   |   |   |
| Earnings (loss) per share - basic:                                        |   |                                  |    |   |   |   |   |
| Income (loss) before cumulative effect of change in  accounting principle |   | $                                     | (2.39   | ) | $ | 0.51 |   | $ | 0.25 |   |
| Cumulative effect of change in accounting principle, net  of tax          |   | —                                |    | (0.25 | ) | — |   |
|                                                                      |   | $                                     | (2.39   | ) | $ | 0.26 |   | $ | 0.25 |   |
|                                                                      |   |                                  |    |   |   |   |   |
| Earnings (loss) per share - diluted:                                      |   |                                  |    |   |   |   |   |
| Income (loss) before cumulative effect of change in  accounting principle |   | $                                     | (2.39   | ) | $ | 0.49 |   | $ | 0.25 |   |
| Cumulative effect of change in accounting principle, net  of tax          |   | —                                |    | (0.24 | ) | — |   |
|                                                                      |   | $                                     | (2.39   | ) | $ | 0.25 |   | $ | 0.25 |   |

 

**The accompanyingnotes are an integral part of these consolidated financial statements.**

 

32

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**CARBON ENERGYCORPORATION**

 

**CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY**

**For the YearsEnded December 31, 2002, 2001 and 2000**

**(inthousands)**

** **
|                                                             |   | **Common Stock** |       | **Retained  Earnings  (Accumulated  Deficit)** |       | **Accumulated  Other  Comprehensive  Income (Loss)** |       | **Total** |       |
|------------------------------------------------------------------|--------|------------------|------------|------------------------------------------------|------------|------------------------------------------------------|------------|-----------|------------|
| **Shares**                                                       |   | **Amount**       |
|                                                             |   |             | ** ** |                                           | ** ** |                                                 | ** ** |      | ** ** |   | ** ** |
| Balances, December 31, 1999                                      |   | 4,510            |       | $                                              | 24,806     |                                                 | $          | (491      | )          | $ | — |   | $ | 24,315 |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Comprehensive income:                                            |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Net income                                                       |   | —           |       | —                                         |       | 1,456                                                |       | —    |       | 1,456 |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Currency translation adjustment                                  |   | —           |       | —                                         |       | —                                               |       | (225      | )          | (225 | ) |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Total comprehensive income                                       |   |             |       |                                           |       |                                                 |       |      |       | 1,231 |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Common stock issued                                              |   | 10               |       | 55                                             |       | —                                               |       | —    |       | 55 |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Common stock issued for acquisition of Carbon Energy  Canada     |   | 1,483            |       | 6,518                                          |       | —                                               |       | —    |       | 6,518 |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Issuance of restricted stock grants                              |   | 28               |       | 163                                            |       | —                                               |       | —    |       | 116 |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Amortization of restricted stock grants                          |   | (9               | )          | (47                                            | )          |                                                 |       |      |       |   |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Balances, December 31, 2000                                      |   | 6,022            |       | 31,495                                         |       | 965                                                  |       | (225      | )          | 32,235 |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Comprehensive income:                                            |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Net income                                                       |   | —           |       | —                                         |       | 1,573                                                |       | —    |       | 1,573 |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Cumulative effect of change in accounting principle, net  of tax |   | —           |       | —                                         |       | —                                               |       | (2,768    | )          | (2,768 | ) |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Currency translation adjustment                                  |   | —           |       | —                                         |       | —                                               |       | (526      | )          | (526 | ) |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Settled contracts reclassified to income                         |   | —           |       | —                                         |       | —                                               |       | 1,890     |       | 1,890 |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Changes in fair value of outstanding hedge positions             |   | —           |       | —                                         |       | —                                               |       | 1,146     |       | 1,146 |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Total comprehensive income                                       |   |             |       |                                           |       |                                                 |       |      |       | 1,315 |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Common stock issued                                              |   | 35               |       | 175                                            |       | —                                               |       | —    |       | 175 |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Amortization of restricted stock grants                          |   | 22               |       | 129                                            |       | —                                               |       | —    |       | 129 |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Balances, December 31, 2001                                      |   | 6,079            |       | 31,799                                         |       | 2,538                                                |       | (483      | )          | 33,854 |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Comprehensive income:                                            |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Net loss                                                         |   | —           |       | —                                         |       | (14,555                                              | )          | —    |       | (14,555 | ) |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Currency translation adjustment                                  |   | —           |       | —                                         |       | —                                               |       | 116       |       | 116 |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Settled contracts reclassified to income                         |   | —           |       | —                                         |       | —                                               |       | (278      | )          | (278 | ) |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Changes in fair value of outstanding hedge positions             |   | —           |       | —                                         |       | —                                               |       | (717      | )          | (717 | ) |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Total comprehensive loss                                         |   |             |       |                                           |       |                                                 |       |      |       | (15,434 | ) |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Common stock issued                                              |   | 13               |       | 39                                             |       | —                                               |       | —    |       | 39 |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Issuance of restricted stock grants                              |   | 18               |       | 140                                            |       | —                                               |       | —    |       | 149 |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Amortization of restricted stock grants                          |   | 6                |       | 9                                              |       |                                                 |       |      |       |   |   |
|                                                             |   |             |       |                                           |       |                                                 |       |      |       |   |   |
| Balances, December 31, 2002                                      |   | 6,116            |       | $                                              | 31,987     |                                                 | $          | (12,017   | )          | $ | (1,362 | ) | $ | 18,608 |   |

 

**The accompanyingnotes are an integral part of these consolidated financial statements.**

 

33

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**CARBON ENERGYCORPORATION**

 

### **CONSOLIDATED STATEMENTS OF CASHFLOWS**

(in thousands)

 
|                                                                                      |   | **For the Year  Ended  December 31,** |    |
|-------------------------------------------------------------------------------------------|--------|---------------------------------------|---------|
|                                                                                      |   | **2002**                              |    | **2001** |   | **2000** |   |
|                                                                                      |   |                                  |    |   |   |   |   |
| Cash flows from operating activities:                                                     |   |                                  |    |   |   |   |   |
| Net income (loss)                                                                         |   | $                                     | (14,555 | ) | $ | 1,573 |   | $ | 1,456 |   |
| Adjustments to reconcile net income (loss) to net cash  provided by operating activities: |   |                                  |    |   |   |   |   |
| Depreciation, depletion and amortization                                                  |   | 6,142                                 |    | 6,234 |   | 5,536 |   |
| Full cost ceiling impairment                                                              |   | 13,218                                |    | — |   | — |   |
| Non-cash setttlement of derivative contracts                                              |   | (246                                  | )       | (1,437 | ) | — |   |
| Deferred income taxes                                                                     |   | 734                                   |    | 573 |   | 417 |   |
| Vesting of restricted stock grants and other                                              |   | 157                                   |    | 156 |   | 140 |   |
| Cumulative effect of change in accounting principle                                       |   | —                                |    | 1,510 |   | — |   |
| Changes in operating assets and liabilities:                                              |   |                                  |    |   |   |   |   |
| Decrease (increase) in:                                                                   |   |                                  |    |   |   |   |   |
| Accounts receivable                                                                       |   | (824                                  | )       | 4,695 |   | (3,063 | ) |
| Amounts due from broker                                                                   |   | —                                |    | 3,871 |   | (2,621 | ) |
| Prepaid expenses and other assets                                                         |   | (109                                  | )       | 1,018 |   | 315 |   |
| Increase (decrease) in:                                                                   |   |                                  |    |   |   |   |   |
| Accounts payable and accrued expenses                                                     |   | (2,263                                | )       | (2,150 | ) | 496 |   |
| Undistributed revenue                                                                     |   | 403                                   |    | (454 | ) | 1,079 |   |
| Derivative liabilities                                                                    |   | —                                |    | (1,357 | ) | — |   |
| Net cash provided by operating activities                                                 |   | 2,657                                 |    | 14,232 |   | 3,755 |   |
|                                                                                      |   |                                  |    |   |   |   |   |
| Cash flows from investing activities:                                                     |   |                                  |    |   |   |   |   |
| Capital expenditures for oil and gas properties                                           |   | (10,604                               | )       | (23,324 | ) | (7,941 | ) |
| Proceeds from property sales                                                              |   | 3,070                                 |    | 6,758 |   | — |   |
| Acquisition of Carbon Energy Canada                                                       |   | —                                |    | (203 | ) | (146 | ) |
| Capital expenditures for support equipment                                                |   | (38                                   | )       | (528 | ) | (179 | ) |
| Net cash used in investing activities                                                     |   | (7,572                                | )       | (17,297 | ) | (8,266 | ) |
|                                                                                      |   |                                  |    |   |   |   |   |
| Cash flows from financing activities:                                                     |   |                                  |    |   |   |   |   |
| Proceeds from note payable                                                                |   | 27,028                                |    | 47,833 |   | 30,852 |   |
| Principal payments on note payable                                                        |   | (22,192                               | )       | (44,919 | ) | (27,381 | ) |
| Proceeds from issuance of common stock                                                    |   | 39                                    |    | 175 |   | 55 |   |
| Net cash provided by financing activities                                                 |   | 4,875                                 |    | 3,089 |   | 3,526 |   |
|                                                                                      |   |                                  |    |   |   |   |   |
| Effect of exchange rate changes on cash                                                   |   | 40                                    |    | (45 | ) | 11 |   |
|                                                                                      |   |                                  |    |   |   |   |   |
| Net (decrease) in cash                                                                    |   | —                                |    | (21 | ) | (974 | ) |
| Cash, beginning of period                                                                 |   | —                                |    | 21 |   | 995 |   |
| Cash, end of period                                                                       |   | $                                     | —  |   | $ | — |   | $ | 21 |   |
|                                                                                      |   |                                  |    |   |   |   |   |
| Supplemental cash flow information:                                                       |   |                                  |    |   |   |   |   |
| Cash paid for interest                                                                    |   | $                                     | 1,009   |   | $ | 889 |   | $ | 1,147 |   |
| Cash paid for taxes                                                                       |   | 1,340                                 |    | 531 |   | 46 |   |

 

**The accompanyingnotes are an integral part of these consolidated financial statements.**

 

34

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**CARBONENERGY CORPORATION**

 

**NOTES****CONSOLIDATED FINANCIAL STATEMENTS**

 

**1.  Nature of Operations and SignificantAccounting Policies**

 

Natureof Operations - CarbonEnergy Corporation (Carbon) was incorporated in September 1999 under thelaws of the State of Colorado to facilitate the acquisition of Bonneville FuelsCorporation (Carbon USA) and subsidiaries. The acquisition of Carbon USA closed on October 29, 1999 and wasaccounted for as a purchase.  InFebruary 2000, Carbon completed an offer to exchange common shares ofCarbon for common shares of CEC Resources, Ltd. (Carbon Canada), anAlberta, Canada company.  Over 97% ofthe 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 purchaseshares of Carbon Canada stock that were not owned by Carbon.  The offer was completed inFebruary 2001 with the acquisition of approximately 34,000 of the 39,000shares of Carbon Canada stock that were not owned by Carbon.  In October 2002, Carbon Canada amended itsarticles to consolidate its issued and outstanding common shares on aone-for-2,500 basis.  In November 2002,Carbon Canada initiated the exchange of common shares for post-consolidationshares or a cash payment in lieu of fractional post-consolidated shares.  The exchange was completed in January 2003.  After the completion of the exchange, Carbonowns 100% of the stock of Carbon Canada. Collectively, Carbon, Carbon USA, Carbon Canada and its subsidiaries arereferred to as the Company.  TheCompany’s operations as of December 31, 2002, consist of the acquisition,exploration, development, and production of oil and natural gas propertieslocated primarily in Colorado, Kansas, New Mexico, Texas, Utah, and theCanadian provinces of Alberta and Saskatchewan.

 

Allamounts are presented in U.S. dollars unless otherwise noted.

 

Principlesof Consolidation - Theconsolidated financial statements include the accounts of Carbon and itssubsidiaries all of which are wholly owned, except Carbon Canada of which theCompany owned approximately 99.7% at December 31, 2002.  All significant intercompany transactions andbalances have been eliminated.

 

CashEquivalents - The Companyconsiders all highly liquid instruments with original maturities of threemonths or less when purchased to be cash equivalents.

 

Propertyand Equipment - TheCompany follows the full cost method of accounting for its oil and gasproperties, whereby all costs incurred in the acquisition, exploration anddevelopment of properties (including costs of surrendered and abandonedleaseholds, delay lease rentals, dry holes and direct overhead related toexploration and development activities) are capitalized.

 

Capitalizedcosts are accumulated for the United States and Canada as separate cost centersand are depleted using the units of production method based on proved reservesof oil and gas.  For purposes of thedepletion calculation, oil and gas reserves are converted to an equivalent unitof measure where six thousand cubic feet of gas is equal to one barrel ofoil.  The estimated future cost of siterestoration, dismantlement and abandonment activities is provided for as acomponent of depletion.  Investments inunproved properties are recorded at the lower of cost or fair market value andare not depleted pending the determination of the existence of proved reserves.

 

Pursuantto full cost accounting rules, capitalized costs less related accumulateddepletion and deferred income taxes may not exceed the sum of the present valueof future net revenue from estimated production of proved oil and gas reservesusing a 10% discount factor and unescalated oil and gas prices as of the end ofthe period; plus the cost of properties not being amortized, if any; plus thelower of cost or estimated fair market value of unproved properties included inthe costs being amortized, if any; less related income tax effects.

 

AtJune 30, 2002, the Company’s capitalized costs exceeded the ceiling limitationin the United States and Canada by $14.0 million and $2.4 million,respectively.  When pricing at June 30,2002 was adjusted for oil and natural gas hedges in place at June 30, 2002, theCompany’s capitalized costs exceeded the ceiling limitation in the UnitedStates and Canada by $12.0 million and $1.2 million, respectively.  At June 30, 2002, 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 were included as additional accumulated depreciation,depletion and amortization (DD&A) in the

 

35

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accompanyingbalance sheet.  At December 31, 2002,the costs reflected in the accompanying financial statements did not exceed theceiling limitation in either the United States or Canada.  Should natural  gas and oil prices decline in the future, it is possible thatadditional impairments of the Company’s oil and gas properties could occur.

 

Proceedsfrom disposal of interests in oil and gas properties are accounted for asadjustments of capitalized costs with no gain or loss recognized, unless suchadjustment would significantly alter the rate of depletion.

 

Buildings,transportation and other equipment are depreciated on the straight-line methodwith lives ranging from 3 to 7 years.

 

UndistributedRevenue - Representsamounts due to third parties of jointly owned oil and gas properties.

 

RevenueRecognition - The Companyfollows the sales method of accounting for natural gas revenues.  Under this method, revenues are recognizedbased on actual volumes of gas sold to purchasers.  To the extent the volumes of gas sold are more (over produced) orless (under produced) than the volumes to which the Company is entitled basedon its interests in its properties, a gas imbalance is created.  If the estimated remaining reserves of aproperty will not be sufficient to enable the underproduced owner to recoup itsshare of production, revenue is deferred and a liability is created.

 

IncomeTaxes - The Companyaccounts for income taxes under the liability method which requires recognitionof deferred tax assets and liabilities for the expected future tax consequencesof events that have been included in the financial statements or taxreturns.  Under this method, deferredtax assets and liabilities are determined based on the difference between the financialstatement and tax basis of assets and liabilities using enacted tax rates ineffect for the year in which the differences are expected to reverse.

 

Derivative Instrumentsand Hedging Activities - OnJanuary 1, 2001, the Company adopted the provisions of Statement of FinancialAccounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments andHedging Activities,” which provides accounting and reporting standardsrequiring that every derivative instrument (including certain derivativeinstruments embedded in other contracts) be recorded on the balance sheet atfair value as either an asset or liability. It also requires that changes in the derivative’s fair value berecognized currently in earnings unless specific hedge accounting criteria aremet.  Special accounting for qualifyinghedges allows a derivative’s gains and losses to offset related results on thehedged item in the income statement, and requires that a company must formallydocument, designate and assess the effectiveness of transactions that receivehedge accounting treatment.

 

ForeignCurrency Translation -Foreign currency transactions and financial statements are translated inaccordance with SFAS No. 52, “Foreign Currency Translation.”  The Company uses the U.S. dollar as thefunctional currency for its U.S. operations and the Canadian dollar as thefunctional currency for its Canadian operations.  Assets and liabilities related to the Company’s Canadianoperations are generally translated at the current exchange rate in effect asof the date of the balance sheet. Translation adjustments are reported as a component of stockholders’equity.  Income statement accounts aretranslated at the average exchange rates during the reporting period.  As a result of the change in the value ofthe Canadian dollar relative to the US dollar, the Company reported non-cashcurrency translation gains/(losses) of $116,000 and $(526,000) for the yearsended December 31, 2002 and 2001, respectively.

 

ComprehensiveIncome - The Companyfollows the provisions of SFAS No. 130, “Reporting Comprehensive Income.”Comprehensive income includes net income and certain items recorded directly tostockholders’ equity and classified as other comprehensive income.

 

Stock-BasedCompensation - The Companyapplies APB Opinion (APB) No. 25 “Accounting for Stock Issued to Employees” andrelated interpretations in accounting for its employee stock options.  Under APB No. 25, compensation expense isrecognized for the difference between the option price and market value on themeasurement date.  No compensationexpense was recognized for the years ended December 31, 2002, 2001 and 2000 asthe exercise price of the stock options granted under the plan equaled themarket price of the underlying stock on the date of grant.

 

36

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

 
|                                  |   | **Years Ended Decmber 31,**              |    |
|---------------------------------------|--------|------------------------------------------|---------|
|                                  |   | **2002**                                 |    | **2001** |   | **2000** |   |
|                                  |   | **(in thousands except per share data)** |    |
| Net income (loss):                    |   |                                     |    |   |   |   |   |
| As reported                           |   | $                                        | (14,555 | ) | $ | 1,573 |   | $ | 1,456 |   |
| Less compensation expense, net of tax |   | 167                                      |    | 211 |   | 180 |   |
| Pro forma                             |   | $                                        | (14,722 | ) | $ | 1,362 |   | $ | 1,276 |   |
|                                  |   |                                     |    |   |   |   |   |
| Basic Earnings per common share:      |   |                                     |    |   |   |   |   |
| As reported                           |   | $                                        | (2.39   | ) | $ | 0.26 |   | $ | 0.25 |   |
| Less compensation expense, net of tax |   | .03                                      |    | 0.04 |   | 0.03 |   |
| Pro forma                             |   | $                                        | (2.42   | ) | $ | 0.22 |   | $ | 0.22 |   |
|                                  |   |                                     |    |   |   |   |   |
| Diluted Earnings per common share:    |   |                                     |    |   |   |   |   |
| As reported                           |   | $                                        | (2.39   | ) | $ | 0.25 |   | $ | 0.25 |   |
| Less compensation expense, net of tax |   | .03                                      |    | 0.03 |   | 0.03 |   |
| Pro forma                             |   | $                                        | (2.42   | ) | $ | 0.22 |   | $ | 0.22 |   |

 

SeeNote 5 for additional information on the Company’s stock-based compensationplans.

 

Earnings (Loss) Per Share -  The Company uses the weightedaverage number of shares outstanding to calculate earnings per share data.  When dilutive, options are included as shareequivalents using the treasury stock method and are included in the calculationof diluted per share data.  Due to theCompany’s net loss for the year ended December 31, 2002, basic and diluted pershare earnings are the same, as all potentially dilutive securities would beanti-dilutive.

 

Accounting Estimates -  Thepreparation of financial statements in conformity with accounting principlesgenerally accepted in the United States requires management to make estimatesand assumptions that affect the amounts reported in these financial statementsand the accompanying notes.  The actualresults could differ from those estimates.

 

Recent Accounting Pronouncements - In July 2001, the FASB issued SFAS No. 143,“Accounting for Asset Retirement Obligations,” which requires that the fairvalue of a liability for an asset retirement obligation be recognized in theperiod in which it is incurred if a reasonable estimate of fair value can bemade.  The associated asset retirementcosts are capitalized as part of the carrying amount of the long-lived asset.  The asset retirement liability will beaccreted to operating expense by using a systematic and rational method.  The statement is effective for the Companyon January 1, 2003.  Upon adoption ofthe statement, the Company currently expects to record an asset retirementobligation of approximately $3.0 million, an addition to oil and gas propertiesof approximately $2.4 and a charge of approximately $327,000 (net of tax) forthe cumulative effect of a change in accounting principle.

 

InAugust 2001, the FASB issued SFAS No. 144, “Accounting for the Impairmentor Disposal of Long-Lived Assets,” which provides a single accounting model forlong-lived assets to be disposed of and changes the criteria that would have tobe met to classify an asset as held-for-sale. The statement also requires expected future operating losses from discontinuedoperations to be recognized in the periods in which the losses are incurred,which is a change from the current requirement of recognizing such operatinglosses as of the measurement date.  Thestatement is effective for fiscal years beginning after December 15,2001.  The adoption of SFAS No. 144 didnot have a material effect on the Company’s financial position or results ofoperations.

 

37

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InApril 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4,44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections.”  SFAS No. 145 is effective for fiscal yearsbeginning after May 15, 2002.  TheCompany adopted this standard early and it had no effect on the Company’sresults of operations or financial position.

 

InJuly 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated WithExit or Disposal Activities,” which provides guidance for financial accountingand reporting of costs associated with exit or disposal activities.  This statement requires the recognition of aliability for a cost associated with an exit or disposal activity when theliability is incurred, as opposed to when the entity commits to an exit planunder EITF No. 94-3.  The statement iseffective for the Company in 2003.  Theadoption of SFAS No. 146 is not expected to have an effect on the Company’sfinancial position or results of operations.

 

InDecember 2002, the FASB issued SFAS No. 148, “Accounting for Stock-BasedCompensation – Transition and Disclosure – an amendment of SFAS No. 123.”  SFAS No. 148 amends SFAS No. 123 to providealternative methods of transition for a voluntary change to the fair valuebased method of accounting for stock-based employee compensation.  In addition, this statement amends thedisclosure requirement of SFAS No. 123 to require disclosures in both annualand interim financial statements about the method of accounting for stock-basedemployee compensation and the effect of the method used on the reportedresults.  SFAS No. 148 is effective forthe Company’s year ended December 31, 2002 and for interim financial statementscommencing in 2003.  The Company’sadoption of this pronouncement had no impact on its financial condition orresults of operations.

 

**2.  Acquisition and Disposition of Assets**

 

Acquisitionof Carbon Canada - OnFebruary 17, 2000, Carbon completed the acquisition of approximately 97%of the stock of Carbon Canada.  An offerto exchange shares of Carbon stock for shares of Carbon Canada stock resultedin the issuance of 1,482,826 shares of Carbon stock to holders of Carbon Canadastock.  The acquisition was accountedfor as a purchase.  InFebruary 2001, Carbon Canada acquired approximately 34,000 of the 39,000remaining shares of Carbon Canada stock that were not owned by Carbon.  At December 31, 2002, Carbon owned 99.7% ofthe stock of Carbon Canada, and subsequent to year end acquired the remainderof the stock it did not previously own. The following unaudited pro forma information presents a summary of theconsolidated results of operations as if the acquisition had occurred atJanuary 1, 2000:

 
|                                  |   | **For the Year  Ended  December 31, 2000** |   |
|---------------------------------------|--------|--------------------------------------------|--------|
|                                  |   | **(in thousands, except  per share data)** |   |
|                                  |   |                                       |   |
| Total revenue                         |   | $                                          | 17,174 |   |
|                                  |   |                                       |   |
| Net income                            |   | $                                          | 1,549  |   |
|                                  |   |                                       |   |
| Earnings per share: Basic and diluted |   | $                                          | 0.26   |   |

 

Theseunaudited pro forma results have been prepared for comparative purposes onlyand do not purport to be indicative of results of operations that actuallywould have resulted had the combination occurred at January 1, 2000, orfuture results of operations of the consolidated entities.

 

38

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Dispositionof Oil and Gas Assets - InJanuary 2001, the Company closed the sale of its entire working interestsand related leasehold rights in the San Juan Basin, receiving net proceeds ofapproximately $6.8 million. Proceeds from the sale were credited directly to the full cost pool andno gain or loss was recognized.  Theproceeds were used to repay amounts outstanding under the Company’s creditfacilities and to finance the Company’s exploration and development program.

 

InJuly 2002, the Company sold certain overriding royalty interests in thePiceance and Permian Basins, receiving net proceeds of approximately$700,000.  Proceeds from the sale werecredited directly to the full cost pool and no gain or loss wasrecognized.  The proceeds were used torepay amounts outstanding under the Company’s credit facilities.

 

InSeptember 2002, the Company sold its working interests and related leaseholdrights in Kansas, receiving net proceeds of approximately $2.1 million.  Proceeds from the sale were crediteddirectly to the full cost pool and no gain or loss was recognized.  The proceeds were used to repay amounts outstandingunder the Company’s credit facilities.

 

**3.****              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). Outstanding borrowings under theCompany’s previous credit facility with Wells Fargo Bank West NationalAssociation (Wells Fargo) were repaid in January 2003 using borrowings underthe Bank of Oklahoma facility.  Thefacility has a borrowing base of $19.0 million and matures in October2005.  No principal payments arerequired until maturity.  The interestrates on amounts borrowed under the facility vary depending upon outstandingborrowings as a percentage of the borrowing base.  Based upon the amount of current borrowings with Wells Fargo at December31, 2002, the interest rate would equal LIBOR plus 2.5%.  The facility is secured by certain U.S. oiland gas properties of the Company and contains various covenants which prohibitor limit the Company’s ability to pay dividends, purchase treasury shares,incur indebtedness, sell properties or merge with another entity.  The Company will also be required tomaintain certain financial ratios.

 

The Company’s former credit facility was withWells Fargo.  At December 31, 2002, theborrowing base was $17.2 million with outstanding borrowings of$16.5 million. The Company’s average borrowing rate was approximately 3.7%at December 31, 2002.  The WellsFargo facility has been classified as long-term at December 31, 2002because the facility was repaid subsequent to year end with borrowings from thenew long-term credit facility with the Bank of Oklahoma. The Company was incompliance with all debt covenants at December 31, 2002.

 

InMarch 2003, Carbon USA closed on the sale of its working and leasehold interestsin the Permian Basin.  The sales pricewas $15.7 million with an effective date of January 1, 2003.  The Company will initially use the proceedsto pay down debt.  As a result of thesale, the Company and Bank of Oklahoma have initiated discussions to determinea revised borrowing base.  See Note 12to the Consolidated Financial Statements for additional information.

 

CanadianCredit Facility – CarbonCanada’s credit facility is an oil and gas reserve based line-of-credit withCanadian Imperial Bank of Commerce (CIBC). At December 31, 2002, the borrowingbase was $8.9 million with outstanding borrowings of $6.3 million.The Canadian facility is secured by the Canadian oil and gas properties of theCompany. The revolving phase of the Canadian facility expires on March 31,2003. If the revolving commitment is not renewed, the loan will be convertedinto a term loan and will be reduced by consecutive monthly payments over aperiod not to exceed 24 months. Subject to possible changes in the borrowingbase, CIBC has agreed that it will not require the Company to make principalpayments under the term loan section of the facility until April 2004 at theearliest. As such, no amounts under the CIBC facility have been classified ascurrent at December 31, 2002.  TheCanadian facility bears interest at a rate equal to banker’s acceptance ratesplus 1.5% or at the CIBC Prime rate plus .5%. The Company’s weighted averageinterest rate was 5.0% at December 31, 2002.

 

TheCanadian facility contains various covenants that limit the Company’s abilityto pay dividends, purchase treasury shares, incur indebtedness, sellproperties, or merge with another entity. The Company was in compliance with all debt covenants at December 31, 2002.

 

39

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Theagreement with CIBC also provides for $3.5 million of credit which can beutilized for  financial derivativeinstruments used to hedge a portion of the Company’s oil and gas production,currency exchange contracts and fixed price gas sales transactions withCIBC.  The Company currently utilizesthe swap facility to hedge a portion of its Canadian production as described inNote 9.

 

Scheduledmaturities of indebtedness under the Canadian facility for the next five yearsare as follows:

 
| **Year ending  December 31,** |   | **Maturities**     |   |
|-------------------------------|--------|--------------------|--------|
|                          |   | **(in thousands)** |   |
| 2003                          |   | $                  | — |   |
| 2004                          |   | 2,345              |   |
| 2005                          |   | 3,127              |   |
| 2006                          |   | 782                |   |
| 2007                          |   | —             |   |
|                          |   | $                  | 6,254  |   |

 

**4.  Commitments and Contingencies**

 

OperatingLeases - The Companyleases office space and certain equipment under non-cancelable operatingleases.  The annual minimum paymentsrelated to those commitments are as follows (in thousands):

 
|   |   | **United States** |   | **Canada** |   |
|--------|--------|-------------------|--------|------------|--------|
|   |   |              |   |       |   |
| 2003   |   | $                 | 257    |       | $      | 178 |   |
| 2004   |   | 229               |   | 14         |   |
| 2005   |   | 60                |   | —     |   |
| Total  |   | $                 | 546    |       | $      | 192 |   |

 

TransportationAgreements - The Companyhas entered into various natural gas transportation agreements in Canada.  The Company typically assigns thesetransportation agreements to a buyer of the Company’s production during theterm of the natural gas sales contract between the Company and the buyer.  The Company is typically paid on an indexbasis, net of transportation charges incurred by the buyer.  The rights and obligations under these transportationagreements will revert back to the Company upon expiration of the natural gassales contracts.

 

40

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**5.  Stock Options and Award Plans**

 

In1999, the Company adopted a stock option plan. All salaried employees of the Company and its subsidiaries are eligibleto receive both incentive stock options and nonqualified stock options.  Directors and consultants who are notemployees of the Company or its subsidiaries are eligible to receivenonqualified stock options, but not incentive stock options.  The option price for the incentive stockoptions granted under the plan is to be not less than 100% of the fair marketvalue of the shares subject to the options. The option price for the nonqualified stock options granted under theplan is to be not less than 85% of the fair market value of the shares subjectto the options.  The aggregate number ofshares of common stock which may be granted pursuant to the plan may not exceed700,000 shares.

 

Thespecific terms of grant and exercise are determined by the Company’s Board ofDirectors.  The options vest over athree-year period and expire ten years from the date of grant.  A summary of the status of the Company’sstock option plan as of December 31, 2002, 2001 and 2000 and changesduring these periods is presented below:

 
|                                                            |   | **For the Year Ended  December 31, 2002** |   | **For the Year Ended  December 31, 2001** |   | **For the Year Ended  December 31, 2000** |    |
|-----------------------------------------------------------------|--------|-------------------------------------------|--------|-------------------------------------------|--------|-------------------------------------------|---------|
|                                                            |   | **Number  of  Option  Shares**            |   | **Weighted-  Average  Exercise  Price**   |   | **Number  of  Option  Shares**            |    | **Weighted-  Average  Exercise  Price** |   | **Number  of  Option  Shares** |   | **Weighted-  Average  Exercise  Price** |   |
|                                                            |   |                                      |   |                                      |   |                                      |    |   |   |   |   |   |   |
| Outstanding at beginning of period                              |   | 551,834                                   |   | $                                         | 5.47   |                                      | 590,500 |   | $ | 5.30 |   | 115,000 |   | $ | 5.50 |   |
| Granted                                                         |   | 57,500                                    |   | 8.86                                      |   | 34,000                                    |    | 8.16 |   | 520,500 |   | 5.29 |   |
| Exercised                                                       |   | (18,165                                   | )      | 4.95                                      |   | (36,099                                   | )       | 5.14 |   | — |   | — |   |
| Forfeited                                                       |   | (21,001                                   | )      | 4.31                                      |   | (36,567                                   | )       | 5.56 |   | (45,000 | ) | 5.78 |   |
| Outstanding at end of year                                      |   | 570,168                                   |   | $                                         | 5.87   |                                      | 551,834 |   | $ | 5.47 |   | 590,500 |   | $ | 5.30 |   |
|                                                            |   |                                      |   |                                      |   |                                      |    |   |   |   |   |   |   |
| Options exercisable at year end                                 |   | 439,488                                   |   |                                      |   | 374,156                                   |    |   |   | 276,166 |   |   |   |
|                                                            |   |                                      |   |                                      |   |                                      |    |   |   |   |   |   |   |
| Shares available for grant at year end                          |   | 75,568                                    |   |                                      |   | 112,067                                   |    |   |   | 109,500 |   |   |   |
|                                                            |   |                                      |   |                                      |   |                                      |    |   |   |   |   |   |   |
| Weighted-average fair value of options granted during the  year |   |                                      |   | $                                         | 3.73   |                                      |    |   | $ | 2.93 |   |   |   | $ | 1.51 |   |

 

Thefollowing table summarizes information about the Company’s stock optionsoutstanding at December 31, 2002:

 
| **Options Outstanding**      |   | **Options Exercisable**              |   |
|------------------------------|--------|--------------------------------------|--------|
| **Range of  ExercisePrices** |   | **Options  Outstanding  atYear end** |   | **Weighted-  Average  Remaining  ContractualLife (Years)** |   | **Weighted-  Average  ExercisePrice** |   | **Options  Exercisable  atYear end** |   | **Weighted-  Average  ExercisePrice** | ** ** |
|                         |   |                                 |   |   |   |   |   |   |   |   |   |
| $4.18 - $5.87                |   | 478,668                              |   | 4.9 |   | $ | 5.34 |   | 428,158 |   | $ | 5.32 |   |
|                         |   |                                 |   |   |   |   |   |   |   |   |   |
| $6.00 - $9.88                |   | 91,500                               |   | 9.1 |   | $ | 8.60 |   | 11,330 |   | $ | 8.16 |   |
|                         |   |                                 |   |   |   |   |   |   |   |   |   |
| $4.18 - $9.88                |   | 570,168                              |   | 5.5 |   | $ | 5.87 |   | 439,488 |   | $ | 5.40 |   |

 

41

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Thefair value of each option grant is estimated on the date of the grant using theBlack-Scholes option pricing model with the following assumptions:

 
|                         |   | **2002** |   | **2001** |   | **2000** |   |
|------------------------------|--------|----------|--------|----------|--------|----------|--------|
|                         |   |     |   |     |   |     |   |
| Expected option life - years |   | 5.00     |   | 4.50     |   | 3.50     |   |
| Risk-free interest rate      |   | 2.79     | %      | 4.24     | %      | 6.36     | %      |
| Dividend yield               |   | 0.00     | %      | 0.00     | %      | 0.00     | %      |
| Volatility                   |   | 44.84    | %      | 33.70    | %      | 25.79    | %      |

 

In1999, the Company adopted a restricted stock plan for selected employees,directors and consultants of the Company and its subsidiaries.  The aggregate number of shares of commonstock which may be issued under the plan may not exceed 300,000 shares and atDecember 31, 2002 a total of 85,000 shares of common stock had been issuedunder the plan.  The number of sharesgranted under this plan were 17,500, 0 and 27,500 for the years ended December31, 2002, 2001 and 2000, respectively. The Company recognized compensation expense related to these grants of$149,000, $129,000, and $116,000 for the years ended December 31, 2002,2001, and 2000, respectively.  Theshares vest over a three year period.

 

**6.  Income Taxes**

 

Thefollowing table sets forth the difference between the provision for incometaxes and the amounts computed by applying the statutory federal income taxrate in thousands:

 
|                                                           |   | **For the Year  Ended  December 31,** |   |
|----------------------------------------------------------------|--------|---------------------------------------|--------|
|                                                           |   | **2002**                              |   | **2001** |   | **2000** |   |
|                                                           |   |                                  |   |   |   |   |   |
| Tax expense at 35% of income before income taxes               |   | $                                     | (4,832 | ) | $ | 1,811 |   | $ | 743 |   |
| State income taxes                                             |   | (340                                  | )      | 9 |   | 17 |   |
| Change in the valuation allowance against deferred tax  assets |   | 5,643                                 |   | — |   | (192 | ) |
| Impact of higher statutory rates on Canadian income            |   | (17                                   | )      | 401 |   | 151 |   |
| Canadian resource allowance                                    |   | (447                                  | )      | (1,016 | ) | (375 | ) |
| Canadian Crown payments (net of Alberta Royalty Tax  Credit)   |   | 550                                   |   | 934 |   | 455 |   |
| Other                                                          |   | 190                                   |   | (48 | ) | (132 | ) |
|                                                           |   | $                                     | 747    |   | $ | 2,091 |   | $ | 667 |   |

 

42

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Deferredincome taxes generally result from recognizing income and expenses at differenttimes for financial and tax reporting. In the U.S., the largest differences are the tax effects of thecapitalization of certain development, exploration and other costs, recordingproceeds from the sale of properties in the full cost pool and the provisionfor impairment of oil and gas properties. In Canada, the largest difference results from accelerated recovery ofcapital expenditures for tax purposes. The following table sets forth the Company’s deferred tax assets andliabilities at December 31, 2002 and 2001:

 
|                               |   | **December 31, 2002** |   |
|------------------------------------|--------|-----------------------|--------|
|                               |   | **United States**     |   | **Canada** |   | **Total** |   |
|                               |   | **(in thousands)**    |   |
|                               |   |                  |   |   |   |   |   |
| Deferred tax assets:               |   |                  |   |   |   |   |   |
| Net operating loss carryforwards   |   | $                     | 4,230  |   | $ | — |   | $ | 4,230 |   |
| Unrealized hedging losses          |   | 325                   |   | 129 |   | 454 |   |
| Property and equipment             |   | 1,413                 |   | — |   | 1,413 |   |
| Gross deferred tax assets          |   | 5,968                 |   | 129 |   | 6,097 |   |
|                               |   |                  |   |   |   |   |   |
| Deferred tax liabilities:          |   |                  |   |   |   |   |   |
| Property and equipment             |   | —                |   | (3,222 | ) | (3,222 | ) |
| Gross deferred tax liabilities     |   | —                |   | (3,222 | ) | (3,222 | ) |
|                               |   |                  |   |   |   |   |   |
| Valuation allowance                |   | (5,643                | )      | — |   | (5,643 | ) |
|                               |   |                  |   |   |   |   |   |
| Net deferred tax asset (liability) |   | $                     | 325    |   | $ | (3,093 | ) | $ | (2,768 | ) |

 
|                               |   | **December 31, 2001** |   |
|------------------------------------|--------|-----------------------|--------|
|                               |   | **United States**     |   | **Canada** |   | **Total** |   |
|                               |   | **(in thousands)**    |   |
|                               |   |                  |   |   |   |   |   |
| Deferred tax assets:               |   |                  |   |   |   |   |   |
| Net operating loss carryforwards   |   | $                     | 2,352  |   | $ | — |   | $ | 2,352 |   |
| Gross deferred tax assets          |   | 2,352                 |   | — |   | 2,352 |   |
|                               |   |                  |   |   |   |   |   |
| Deferred tax liabilities:          |   |                  |   |   |   |   |   |
| Property and equipment             |   | (1,537                | )      | (3,195 | ) | (4,732 | ) |
| Unrealized hedging gains           |   | (74                   | )      | (128 | ) | (202 | ) |
| Other                              |   | (69                   | )      | — |   | (69 | ) |
| Gross deferred tax liabilities     |   | (1,680                | )      | (3,323 | ) | (5,003 | ) |
|                               |   |                  |   |   |   |   |   |
| Net deferred tax asset (liability) |   | $                     | 672    |   | $ | (3,323 | ) | $ | (2,651 | ) |
|                                    |        |                       |        |  |  |  |  |  |  |  |  |

 

Asof December 31, 2002, the Company had net operating loss carryforwards forfederal income tax purposes of $11.3 million which expire in the years 2019through 2022.  Due to the uncertaintyregarding the realization of the deferred tax assets relating to the netoperating loss carryforwards and other temporary differences in the UnitedStates, a valuation allowance has been recorded for the Company’s deferred taxassets in the United States as of December 31, 2002.  The Company makes periodic reviews of the realizability of itsnet deferred tax assets and will make adjustments to the valuation allowancewhen it is more likely than not that the net deferred tax assets will berealized.

 

43

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**7.  Business and Geographical Segments**

 

Segmentinformation has been prepared in accordance with SFAS No. 131, “Disclosuresabout Segments of an Enterprise and Related Information.”  For the years ended December 31, 2002,2001 and 2000, Carbon had two reportable and geographic segments: Carbon USAand Carbon Canada, representing oil and gas operations in the United States andCanada, respectively.  The segments arestrategic business units which operate in unique geographic locations.  The segment data presented below wasprepared on the same basis as Carbon’s consolidated financial statements (inthousands).

 
|                                                                      |   | **For the Year  Ended  December 31, 2002** |    | **For the Year  Ended  December 31, 2001** |   | **For  the  Year****Ended  December  31, 2000** |   | **For  the  Period  from  February  18,****through  December   31,  2000** |    |       |   |
|---------------------------------------------------------------------------|--------|--------------------------------------------|---------|--------------------------------------------|--------|-------------------------------------------------|--------|----------------------------------------------------------------------------|---------|------------|--------|
|                                                                      |   | **United States**                          |    | **Canada**                                 |   | **Total**                                       |   | **United States**                                                          |    | **Canada** |   | **Total** |   | **United States** |   | **Canada** |   | **Total** |   |
|                                                                      |   |                                       |    |                                       |   |                                            |   |                                                                       |    |       |   |   |   |   |   |   |   |   |   |
| Revenues:                                                                 |   |                                       |    |                                       |   |                                            |   |                                                                       |    |       |   |   |   |   |   |   |   |   |   |
| Oil and gas sales                                                         |   | $                                          | 8,603   |                                       | $      | 7,573                                           |   | $                                                                          | 16,176  |       | $      | 10,341 |   | $ | 11,080 |   | $ | 21,421 |   | $ | 11,054 |   | $ | 5,374 |   | $ | 16,428 |   |
| Marketing and other, net                                                  |   | 344                                        |    | —                                     |   | 344                                             |   | 532                                                                        |    | 2          |   | 534 |   | 245 |   | (70 | ) | 175 |   |
|                                                                      |   | 8,947                                      |    | 7,573                                      |   | 16,520                                          |   | 10,873                                                                     |    | 11,082     |   | 21,955 |   | 11,299 |   | 5,304 |   | 16,603 |   |
| Expenses:                                                                 |   |                                       |    |                                       |   |                                            |   |                                                                       |    |       |   |   |   |   |   |   |   |   |   |
| Oil and gas production costs                                              |   | 3,242                                      |    | 1,785                                      |   | 5,027                                           |   | 3,555                                                                      |    | 1,626      |   | 5,181 |   | 3,774 |   | 793 |   | 4,567 |   |
| Depreciation, depletion and  amortization                                 |   | 3,626                                      |    | 2,516                                      |   | 6,142                                           |   | 3,536                                                                      |    | 2,698      |   | 6,234 |   | 4,042 |   | 1,494 |   | 5,536 |   |
| Full cost ceiling impairment                                              |   | 12,003                                     |    | 1,215                                      |   | 13,218                                          |   | —                                                                     |    | —     |   | — |   | — |   | — |   | — |   |
| General and administrative,  net                                          |   | 2,868                                      |    | 2,019                                      |   | 4,887                                           |   | 2,767                                                                      |    | 1,736      |   | 4,503 |   | 1,989 |   | 1,260 |   | 3,249 |   |
| Interest and other, net                                                   |   | 804                                        |    | 250                                        |   | 1,054                                           |   | 653                                                                        |    | 210        |   | 863 |   | 917 |   | 211 |   | 1,128 |   |
| Total operating expenses                                                  |   | 22,543                                     |    | 7,785                                      |   | 30,328                                          |   | 10,511                                                                     |    | 6,270      |   | 16,781 |   | 10,722 |   | 3,758 |   | 14,480 |   |
| Income (loss) before income  taxes                                        |   | (13,596                                    | )       | (212                                       | )      | (13,808                                         | )      | 362                                                                        |    | 4,812      |   | 5,174 |   | 577 |   | 1,546 |   | 2,123 |   |
|                                                                      |   |                                       |    |                                       |   |                                            |   |                                                                       |    |       |   |   |   |   |   |   |   |   |   |
| Income tax provision                                                      |   | 746                                        |    | 1                                          |   | 747                                             |   | 135                                                                        |    | 1,956      |   | 2,091 |   | 44 |   | 623 |   | 667 |   |
|                                                                      |   |                                       |    |                                       |   |                                            |   |                                                                       |    |       |   |   |   |   |   |   |   |   |   |
| Income (loss) before  cumulative effect of change in accounting principle |   | $                                          | (14,342 | )                                          | $      | (213                                            | )      | $                                                                          | (14,555 | )          | $      | 227 |   | $ | 2,856 |   | $ | 3,083 |   | $ | 533 |   | $ | 923 |   | $ | 1,456 |   |
|                                                                      |   |                                       |    |                                       |   |                                            |   |                                                                       |    |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Total assets                                                              |   | $                                          | 29,298  |                                       | $      | 23,006                                          |   | $                                                                          | 52,304  |       | $      | 42,429 |   | $ | 19,939 |   | $ | 62,368 |   | $ | 44,279 |   | $ | 18,201 |   | $ | 62,480 |   |
|                                                                      |   |                                       |    |                                       |   |                                            |   |                                                                       |    |       |   |   |   |   |   |   |   |   |   |
| Capital expenditures                                                      |   | $                                          | 4,484   |                                       | $      | 6,120                                           |   | $                                                                          | 10,604  |       | $      | 16,615 |   | $ | 6,709 |   | $ | 23,324 |   | $ | 4,848 |   | $ | 3,093 |   | $ | 7,941 |   |

 

**8.  Major Customers**

 

For the year ended December 31, 2002, revenues from the sale of naturalgas to one customer of the Company’s U.S. operations and two customers of theCompany’s Canadian operations represented approximately 12%, 11% and 16%,respectively, of the Company’s consolidated revenues.

 

Forthe year ended December 31, 2001, revenues from the sale of natural gas to onecustomer of the Company’s Canadian operations represented approximately 34% ofthe Company’s consolidated revenues.

 

Forthe year ended December 31, 2000, revenues from the sale of natural gas toone customer of the Company’s U.S. operations and one customer of the Company’sCanadian operations represented approximately 16% and 20%, respectively, of theCompany’s consolidated revenues.

 

Managementbelieves that the loss of any individual purchaser would not have a long-termmaterial adverse impact on the financial position or results of operations ofthe Company.

 

44

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**9.  Derivative Instruments**

 

InterestRate Swap Agreements -During 2002, the Company entered into interest rate swap agreements thateffectively converted a portion of its variable rate borrowings in the UnitedStates to fixed rate debt for periods of up to two years, reducing the impactof interest rate increases or decreases on future income.  Quarterly settlements from interest rateswaps that qualify for hedge accounting treatment are recognized as anadjustment to interest expense.  Gainsor losses from interest rate swaps that do not qualify for hedge accountingtreatment are recognized in the current period as other income or expense. Thecash flows from such agreements are included in operating activities in theconsolidated statements of cash flow. The table below sets forth the Company’sinterest rate derivative contracts in place at December 31, 2002 that weretreated as cash flow hedges for accounting purposes:

 
| **Notional  Amount** |   | **Contract  Expiration  Date** |     | **LIBOR  Fixed  Rate** |   | **Derivative  Asset/  (Liability)** |   |
|----------------------|--------|--------------------------------|----------|------------------------|--------|-------------------------------------|--------|
| **(in thousands)**   |   |                           |     |                   |   |                                |   |
|                 |   |                           |     |                   |   |                                |   |
| $                    | 3,700  |                           | May 2003 |                   | 3.46   | %                                   | $      | (37 | ) |
| 2,000                |   | October 2003                   |     | 3.77                   | %      | (46                                 | )      |
| 800                  |   | October 2003                   |     | 3.82                   | %      | (19                                 | )      |
| 1,000                |   | March 2004                     |     | 4.15                   | %      | (34                                 | )      |
| 2,500                |   | April 2004                     |     | 4.24                   | %      | (101                                | )      |
|                 |   |                           |     |                   |   | $                                   | (237   | ) |
|                      |        |                                |          |                        |        |                                     |        |  |  |

 

Interestrates reflective of the Company’s interest rate swap agreements werecorrelative with the LIBOR rates used to determine the Company’s borrowingrate.  As a result, no ineffectiveness wasrecognized related to the Company’s interest rate swap agreements during theyear ended December 31, 2002.  During2002, settlements under these interest rate swap agreements of $142,000 wererecognized as additional interest expense. As of December 31, 2002, the Company had net unrealized derivativelosses of $237,000 ($147,000 after tax) related to its interest rate swapagreements.  The Company expects toreclassify $199,000 of these net unrealized losses to earnings during the nexttwelve month period.

 

CommodityDerivative Instruments and Hedging Activities - The Company may use certain financialinstruments including swaps, collars, futures and other contracts in an attemptto reduce exposure to market fluctuations in the price of oil and natural gas.

 

Pursuantto Company guidelines, the Company utilizes derivative instruments only as ahedging mechanism and does not enter into speculative transactions.  Gains or losses from financial instrumentsthat qualify for hedge accounting treatment are recognized as an adjustment tosales revenue during the period in which the financial instrument matures.  Gains or losses from financial instrumentsthat do not qualify for hedge accounting treatment are recognized during thecurrent period as other income or expense. The cash flows from such instruments are included in operatingactivities in the consolidated statements of cash flows.  The following table sets forth the hedge gains(losses) realized by the Company for 2002, 2001 and 2000 (in thousands):

 
|        |   | **For the Year Ended  December 31, 2002** |   | **For the Year Ended  December 31, 2001** |   | **For the Year Ended  December 31, 2000** |   |
|-------------|--------|-------------------------------------------|--------|-------------------------------------------|--------|-------------------------------------------|--------|
|        |   | **United States**                         |   | **Canada**                                |   | **United States**                         |   | **Canada** |   | **United States** |   | **Canada** |   |
|        |   |                                      |   |                                      |   |                                      |   |   |   |   |   |   |   |
| Oil         |   | $                                         | (83    | )                                         | $      | (8                                        | )      | $ | 25 |   | $ | 33 |   | $ | (414 | ) | $ | (186 | ) |
| Natural gas |   | 400                                       |   | 3                                         |   | (1,475                                    | )      | (571 | ) | (2,608 | ) | (987 | ) |
|             |        |                                           |        |                                           |        |                                           |        |  |  |  |  |  |  |  |  |  |  |  |  |

 

45

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The table below sets forth the Company’s derivative financial instrumentpositions related to its natural gas and oil production that qualify for hedgeaccounting treatment at December 31, 2002:

 

Swaps:

 
| **Carbon USA Contracts** |   | **Carbon Canada Contracts** |   |
|--------------------------|--------|-----------------------------|--------|
| **Time Period**          |   | **Bbl/  MMBtu**             |   | **Weighted  Average  Fixed Price  Bbl/  MMBtu** |   | **Derivative  Asset/  (Liability)** |   | **Time Period** |   | **Bbl/  MMBtu** |   | **Weighted  Average  Fixed Price  Bbl/  MMBtu** |   | **Derivative  Asset/  (Liability)** |   |
|                     |   |                        |   |   |   | **(thousands)** |   |   |   |   |   |   |   | **(thousands)** |   |
| **Gas**                  |   |                        |   |   |   |   |   | **Gas** |   |   |   |   |   |   |   |
| 01/01/03-12/31/03        |   | 1,400,000                   |   | $ | 3.07 |   | $ | (541 | ) | 01/01/03-12/31/03 |   | 216,000 |   | $ | 2.83 |   | $ | (242 | ) |
|                     |   |                        |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Oil**                  |   |                        |   |   |   |   |   | **Oil** |   |   |   |   |   |   |   |
| 01/01/03-12/31/03        |   | 46,000                      |   | $ | 25.42 |   | $ | (76 | ) | 01/01/03-12/31/03 |   | 37,000 |   | $ | 25.47 |   | $ | (57 | ) |

 

TheCompany periodically enters into long-term physical contracts for a portion ofits natural gas and oil production.  Thetable below sets forth fixed price sales contracts at December 31, 2002:

 

Fixed price contracts:

 
| **Carbon USA Contracts** |   | **Carbon Canada Contracts** |   |
|--------------------------|--------|-----------------------------|--------|
| **Time Period**          |   | **MMBtu**                   |   | **Weighted  Average  Fixed Price  MMBtu** |   | **Time Period** |   | **MMBtu** |   | **Weighted  Average  Fixed Price  MMBtu** |   |
|                     |   |                        |   |   |   |   |   |   |   |   |   |
| **Gas**                  |   |                        |   |   |   | **Gas** |   |   |   |   |   |
| 01/01/03-03/31/03        |   | 180,000                     |   | $ | 2.57 |   | 01/01/03-12/31/03 |   | 778,000 |   | $ | 3.16 |   |
|                          |        |                             |        |  |  |  |  |  |  |  |  |  |  |

 

During 2001, the Companyentered into certain commodity derivative contracts with Enron North AmericaCorporation (ENAC), a subsidiary of Enron Corporation (Enron).  On December 2, 2001, Enron and ENAC filedfor Chapter 11 bankruptcy, and the Company determined that the ENAC contractsno longer qualified for cash flow hedge accounting under SFAS No. 133.  Consequently, the Company recorded a loss of$328,000 for the year ended December 31, 2001, based on the estimated fairvalue of the derivative contracts as determined by the future commodity pricemarkets and deferred $328,000 ($205,000 after tax) in accumulated othercomprehensive income.  The amount deferred in accumulatedother comprehensive income at December 31, 2001 of $246,000 ($156,000 aftertax) was reclassified to earnings during 2002 based on the originally scheduledsettlement periods of the contracts.

 

Duringthe year ended December 31, 2002, net hedging gains of $196,000 ($122,000 aftertax) relating to commodity derivative contracts, excluding amounts related tothe ENAC contracts discussed above, were transferred from accumulated othercomprehensive income to earnings.  Thefair value of outstanding commodity derivative contracts designated as hedgesdecreased by $968,000 ($570,000 after tax). Oil and natural gas prices reflective of the Company’s hedge contractswere correlative with the published indices used to sell the Company’sproduction.  As a result, noineffectiveness was recognized related to the Company’s hedge contracts duringthe year ended December 31, 2002.  As ofDecember 31, 2002, the Company had net unrealized commodity derivative lossesof $916,000 million ($554,000 after tax). The Company expects to reclassify all of these net unrealized losses toearnings during the next twelve month period.

 

46

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**10.  Fair Value of Financial Instruments**

 

TheCompany’s financial instruments consist of cash, cash equivalents, accountsreceivable, accounts payable, derivative instruments and long-term debt.  Except for long-term debt, the carryingamounts of such financial instruments approximate fair value due to their shortmaturities.  As a result of the variableinterest rates on the Company’s debt facilities at December 31, 2002, thefair market value of long-term debt was not materially different from itscarrying amount.  The Company’sderivative instruments, which are intended to manage commodity price risks arerecorded at fair market value.

 

**11.  Marketing, Trading and Other Activities**

 

TheCompany formerly engaged in natural gas trading activities in the United Stateswhich involved purchasing natural gas from third parties and selling naturalgas to other parties.  In 2001, theCompany reduced its efforts concerning the marketing of third party natural gasand completely exited the business in 2002. Trading income associated with these activities is presented on a netbasis in the statements of operations as a component of marketing and otherrevenues.  The following table setsforth the gross trading activities and other significant components ofmarketing and other revenue (in thousands):

 
|                                                             |   | **For the Year  Ended  December 31,** |   |
|------------------------------------------------------------------|--------|---------------------------------------|--------|
|                                                             |   | **2002**                              |   | **2001** |   | **2000** |   |
|                                                             |   |                                  |   |   |   |   |   |
| Revenues, gross                                                  |   | $                                     | — |   | $ | 4,145 |   | $ | 5,445 |   |
| Operating expenses, gross                                        |   | —                                |   | 4,037 |   | 5,515 |   |
| Net trading income (loss)                                        |   | —                                |   | 108 |   | (70 | ) |
|                                                             |   |                                  |   |   |   |   |   |
| Non-hedge derivative contracts                                   |   | —                                |   | 1,290 |   | — |   |
| Impairment of accounts receivable                                |   | (5                                    | )      | (625 | ) | — |   |
| Non-cash income (charge) related to impaired oil and gas  hedges |   | 244                                   |   | (328 | ) | — |   |
| Gathering                                                        |   | 119                                   |   | 90 |   | 47 |   |
| Section 29 tax credits                                           |   | —                                |   | — |   | 176 |   |
| Other                                                            |   | (14                                   | )      | (1 | ) | 22 |   |
| Total marketing and other revenue                                |   | $                                     | 344    |   | $ | 534 |   | $ | 175 |   |

 

**12.  Subsequent Events**

 

On October 30, 2002, Carbon Canada passed a special resolution thatamended its articles of association in order to consolidate its issued andoutstanding common shares on a one-for-2,500 basis.  On November 15, 2002, Carbon Canada initiated the exchange ofcommon shares for post-consolidation shares or a cash payment in lieu offractional post-consolidation shares. The exchange was completed on January 13, 2003.  After the completion of the exchange, Carbonowns 100% of the stock of Carbon Canada.

 

On March 24, 2003, Carbon USA closed on the sale ofits interests in 97 gross (23.3 net) wells and 25,400 gross (8,200 net) acreslocated primarily in southeast New Mexico. The purchase price was $15.7 million in cash, with an effective

 

47

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date of January 1,2003.  Proceeds from the sale were usedto repay borrowings under the Company’s U.S. credit facility with Bank ofOklahoma.

 

OnMarch 31, 2003, Carbon announced that it had entered into an Agreement and Planof Reorganization (the Merger Agreement) with Evergreen Resources, Inc.(Evergreen).  Under the MergerAgreement, Carbon will merge with a subsidiary of Evergreen, and Carbonshareholders will receive .275 shares of Evergreen common stock for eachoutstanding share of Carbon common stock (and cash in lieu of any fractionalshares).  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.

 

TheBoards of Directors of Carbon and Evergreen each unanimously approved theMerger Agreement.  At the time ofexecution of the agreement, each of Yorktown Energy Partners III, L.P., andPatrick R. McDonald, President and Chief Executive Officer of Carbon, whobeneficially own approximately 73.2% and 6.0%, respectively, of Carbon'soutstanding common stock, has executed an agreement with Evergreen obligatingeach of them to vote all shares over which it has voting control in favor ofthe merger.

 

RBCCapital Markets has acted as the financial advisor to Carbon and rendered afairness opinion to the Board of Directors of Carbon.

 

Completionof the merger, which is subject to customary conditions, including approval bythe shareholders of Carbon, is expected to occur late in the second quarter orin the third quarter of 2003.  TheMerger Agreement contains a $2.5 million termination fee payable by Carbon ifthe Merger Agreement is terminated under certain circumstances.

 

48

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**13.  Disclosures about Oil and Gas Activities**

 

(A)          Costs Incurred in Oil and GasProducing Activities

 

Thefollowing table sets forth costs incurred in oil and gas property acquisition,exploration and development activities for the years ended December 31,2002, 2001 and 2000:

 
|                       |   | **United  States** |   | **Canada** |   | **Total** |   |
|----------------------------|--------|--------------------|--------|------------|--------|-----------|--------|
|                       |   | **(in thousands)** |   |
| 2002                       |   |               |   |       |   |      |   |
| Acquisition of properties: |   |               |   |       |   |      |   |
| Proved properties          |   | $                  | — |       | $      | 1,046     |   | $ | 1,046 |   |
| Unproved properties        |   | 785                |   | 502        |   | 1,287     |   |
| Exploration                |   | 1,827              |   | 296        |   | 2,123     |   |
| Development                |   | 2,120              |   | 4,430      |   | 6,550     |   |
| Total                      |   | $                  | 4,732  |       | $      | 6,274     |   | $ | 11,006 |   |
|                       |   |               |   |       |   |      |   |
| 2001                       |   |               |   |       |   |      |   |
| Acquisition of properties: |   |               |   |       |   |      |   |
| Proved properties          |   | $                  | — |       | $      | —    |   | $ | — |   |
| Unproved properties        |   | 1,540              |   | 525        |   | 2,065     |   |
| Exploration                |   | 9,513              |   | 214        |   | 9,727     |   |
| Development                |   | 5,300              |   | 5,440      |   | 10,740    |   |
| Total                      |   | $                  | 16,353 |       | $      | 6,179     |   | $ | 22,532 |   |
|                       |   |               |   |       |   |      |   |
| 2000(1)                    |   |               |   |       |   |      |   |
| Acquisition of properties: |   |               |   |       |   |      |   |
| Proved properties          |   | $                  | — |       | $      | 14,176    |   | $ | 14,176 |   |
| Unproved properties        |   | 1,217              |   | 161        |   | 1,378     |   |
| Exploration                |   | 2,895              |   | 19         |   | 2,914     |   |
| Development                |   | 1,495              |   | 3,627      |   | 5,122     |   |
| Total                      |   | $                  | 5,607  |       | $      | 17,983    |   | $ | 23,590 |   |

 

----

(1)          Canadian results for2000 are the results of Carbon Canada subsequent to its acquisition by Carbonin February 2000.

 

49

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(B)                                Aggregate Capitalized Costs

 

The following table sets forth the aggregate capitalized costs relatingto oil and gas activities at the end of each of the years indicated:

 
|                                       |   | **December 31, 2002** |   |
|--------------------------------------------|--------|-----------------------|--------|
|                                       |   | **United  States**    |   | **Canada** |   | **Total** |   |
|                                       |   | **(in thousands)**    |   |
| Oil and gas properties, full cost method:  |   |                  |   |   |   |   |   |
| Unevaluated properties not being amortized |   | $                     | 6,218  |   | $ | 862 |   | $ | 7,080 |   |
| Evaluated costs                            |   | 43,591                |   | 27,632 |   | 71,223 |   |
| Total capitalized costs                    |   | 49,809                |   | 28,494 |   | 78,303 |   |
| Less - Accumulated DD&A                |   | (23,419               | )      | (7,705 | ) | (31,124 | ) |
| Net capitalized costs                      |   | $                     | 26,390 |   | $ | 20,789 |   | $ | 47,179 |   |

 
|                                       |   | **December 31, 2001** |   |
|--------------------------------------------|--------|-----------------------|--------|
|                                       |   | **United  States**    |   | **Canada** |   | **Total** |   |
|                                       |   | **(in thousands)**    |   |
| Oil and gas properties, full cost method:  |   |                  |   |   |   |   |   |
| Unevaluated properties not being amortized |   | $                     | 6,892  |   | $ | 608 |   | $ | 7,500 |   |
| Evaluated costs                            |   | 41,247                |   | 21,503 |   | 62,750 |   |
| Total capitalized costs                    |   | 48,139                |   | 22,111 |   | 70,250 |   |
| Less - Accumulated DD&A                |   | (7,941                | )      | (4,013 | ) | (11,954 | ) |
| Net capitalized costs                      |   | $                     | 40,198 |   | $ | 18,098 |   | $ | 58,296 |   |

 

The followingtable sets forth the oil and gas property costs not being amortized atDecember 31, 2002, by the year in which the costs were incurred (inthousands):

 
|   |   | **United  States** |   | **Canada** |   | **Total** |   |
|--------|--------|--------------------|--------|------------|--------|-----------|--------|
| 2002   |   | $                  | 1,134  |       | $      | 449       |   | $ | 1,583 |   |
| 2001   |   | 1,059              |   | 413        |   | 1,472     |   |
| 2000   |   | 246                |   | —     |   | 246       |   |
| 1999   |   | 3,779              |   | —     |   | 3,779     |   |
|   |   | $                  | 6,218  |       | $      | 862       |   | $ | 7,080 |   |

 

TheCompany anticipates that substantially all unevaluated costs will be classifiedas evaluated costs within five years.

 

50

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(C)                                Estimated Proved Oil and Gas Reserves (Unaudited)

 

Thetable below sets forth the estimated quantities of year end proved reservesafter royalty burdens at December 31, 2002, 2001 and 2000.  The reserve estimates for properties locatedin the United States were prepared by Ryder Scott Company, an independentreservoir engineering firm, and the Canadian reserve estimates were prepared bySproule Associates Limited, independent geological petroleum engineeringconsultants.

 
|                                  |   | **Oil and Liquids** |   | **Natural Gas** |   |
|---------------------------------------|--------|---------------------|--------|-----------------|--------|
|                                  |   | **(MBbl)**          |   | **(MMcf)**      |   |
|                                  |   | **United  States**  |   | **Canada**      |   | **Total** |   | **United  States** |   | **Canada** |   | **Total** |   |
|                                  |   |                |   |            |   |   |   |   |   |   |   |   |   |
| Balance, December 31, 1999            |   | 228                 |   | —          |   | 228 |   | 31,012 |   | — |   | 31,012 |   |
| Revisions of previous estimates       |   | 278                 |   | —          |   | 278 |   | 4,179 |   | — |   | 4,179 |   |
| Extensions, discoveries and additions |   | 70                  |   | 146             |   | 216 |   | 283 |   | 7,727 |   | 8,010 |   |
| Purchases of reserves in place        |   | —              |   | 355             |   | 355 |   | — |   | 12,452 |   | 12,452 |   |
| Production                            |   | (69                 | )      | (40             | )      | (109 | ) | (3,374 | ) | (1,312 | ) | (4,686 | ) |
|                                  |   |                |   |            |   |   |   |   |   |   |   |   |   |
| Balance, December 31, 2000            |   | 507                 |   | 461             |   | 968 |   | 32,100 |   | 18,867 |   | 50,967 |   |
| Revisions of previous estimates       |   | (10                 | )      | (51             | )      | (61 | ) | (679 | ) | (2,560 | ) | (3,239 | ) |
| Extensions, discoveries and additions |   | 34                  |   | 79              |   | 113 |   | 10,968 |   | 5,575 |   | 16,543 |   |
| Purchases of reserves in place        |   | —              |   | 9               |   | 9 |   | — |   | 405 |   | 405 |   |
| Production                            |   | (81                 | )      | (59             | )      | (140 | ) | (2,810 | ) | (2,419 | ) | (5,229 | ) |
| Sales of reserves in place            |   | (38                 | )      | —          |   | (38 | ) | (5,587 | ) | — |   | (5,587 | ) |
|                                  |   |                |   |            |   |   |   |   |   |   |   |   |   |
| Balance, December 31, 2001            |   | 412                 |   | 439             |   | 851 |   | 33,992 |   | 19,868 |   | 53,860 |   |
| Revisions of previous estimates       |   | 32                  |   | 41              |   | 73 |   | 1,396 |   | (1,365 | ) | 31 |   |
| Extensions, discoveries and additions |   | 22                  |   | 120             |   | 142 |   | 5,310 |   | 7,305 |   | 12,615 |   |
| Purchases of reserves in place        |   | —              |   | 7               |   | 7 |   | — |   | 2,229 |   | 2,229 |   |
| Production                            |   | (91                 | )      | (50             | )      | (141 | ) | (3,049 | ) | (2,232 | ) | (5,281 | ) |
| Sales of reserves in place            |   | (110                | )      | —          |   | (110 | ) | (972 | ) | — |   | (972 | ) |
|                                  |   |                |   |            |   |   |   |   |   |   |   |   |   |
| Balance, December 31, 2002            |   | 265                 |   | 557             |   | 822 |   | 36,677 |   | 25,805 |   | 62,482 |   |
|                                  |   |                |   |            |   |   |   |   |   |   |   |   |   |
| Proved developed reserves(1):         |   |                |   |            |   |   |   |   |   |   |   |   |   |
|                                  |   |                |   |            |   |   |   |   |   |   |   |   |   |
| December 31, 2000                     |   | 382                 |   | 411             |   | 793 |   | 26,422 |   | 16,193 |   | 42,615 |   |
| December 31, 2001                     |   | 401                 |   | 352             |   | 753 |   | 28,949 |   | 14,710 |   | 43,659 |   |
| December 31, 2002                     |   | 237                 |   | 426             |   | 663 |   | 28,569 |   | 17,403 |   | 45,972 |   |

 

----

(1)          Proved developed oil and gas reserves are reserves that can be expectedto be recovered through existing wells with existing equipment and operatingmethods.

 

Inaccordance with applicable requirements of the Securities and ExchangeCommission (SEC), estimates of the Company’s proved reserves and future netrevenues are made using sale prices estimated to be in effect as of the date ofthe reserve estimates and are held constant throughout the life of theproperties (except to the extent contractual arrangements in existence at yearend specifically provide for escalation). Price declines decrease reserve values by lowering the future netrevenues attributable to the reserves and may reduce the quantities of reservesthat are recoverable on an economic basis. Price increases may have the opposite effect.  Future prices received for production and future production costsmay vary, perhaps significantly, from the prices and costs assumed for purposesof these estimates.

 

There are numerous uncertainties inherent inestimating quantities of proved reserves and in projecting future rates ofproduction and timing of development expenditures.  Oil and gas reserve engineering is a subjective process ofestimating underground accumulations of natural gas and oil that cannot bemeasured in an exact way, and estimates of

 

51

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other engineers might differ materially from thoseshown above.  The accuracy of anyreserve estimate is a function of the quality of available data and engineeringand geological interpretations and judgment. Results of drilling, testing and production may justify revisions.  Accordingly, reserve estimates are oftenmaterially different from the quantities of oil and natural gas that areultimately recovered.  Themeaningfulness of such estimates depends primarily on the accuracy of theassumptions upon which they were based. In general, the volume of production from oil and gas properties theCompany owns declines as reserves are depleted.  Except to the extent the Company acquires additional propertiescontaining proved reserves or conducts successful exploration activities orboth, the proved reserves of the Company will decline as reserves areproduced.  Reserves generated fromfuture activities of the Company are therefore highly dependent upon the levelof success in acquiring or discovering additional reserves and the costsincurred in doing so.

 

(D)                               Standardized Measure (Unaudited)

 

Thestandardized measure schedule is presented pursuant to the disclosurerequirements of the SEC and SFAS No. 69, “Disclosures About Oil and GasProducing Activities”.

 

Thestandardized measure is intended to provide a standard of comparablemeasurement of the Company’s estimated proved oil and gas reserves based onpricing and costs existing as of December 31, 2002, 2001 and 2000.  Pursuant to SFAS No. 69, future oil and gasrevenues are calculated by multiplying the oil and gas production volumesexpected to be produced in each year throughout the life of the properties bythe oil and gas prices in effect at the end of the reporting period.  Future price changes are considered only tothe extent provided by contractual arrangement in existence at year end.  Production and development costs are basedupon costs at each year end and are held constant for the life of theproperties.  Future income tax expensesare estimated by applying a combined federal and state statutory tax rate of38% in the United States and a combined federal and provincial rate rangingfrom 37 - 41% in Canada with recognition of tax basis, net operatingloss carryforwards and other statutory deductions.  For standardized measure purposes, the Company estimates futureincome taxes using the “year-by-year” method. For ceiling test purposes, the Company estimates future income taxesusing the “short-cut” method. Discounted amounts are based on a 10% annual discount rate.

 

Thefollowing table sets forth the Company’s standardized measure of discountedfuture net cash flows at December 31, 2002, 2001 and 2000:

 
|                                                         |   | **December 31, 2002** |    |
|--------------------------------------------------------------|--------|-----------------------|---------|
|                                                         |   | **United  States**    |    | **Canada** |   | **Total** |   |
|                                                         |   | **(in thousands)**    |    |
|                                                         |   |                  |    |   |   |   |   |
| Future oil and gas revenue                                   |   | $                     | 123,119 |   | $ | 118,943 |   | $ | 242,062 |   |
| Future production costs                                      |   | (34,859               | )       | (21,801 | ) | (56,660 | ) |
| Future development costs                                     |   | (13,593               | )       | (4,612 | ) | (18,205 | ) |
| Future income tax expense                                    |   | (13,192               | )       | (29,870 | ) | (43,062 | ) |
| Future net cash flows                                        |   | 61,475                |    | 62,660 |   | 124,135 |   |
| 10% annual discount for estimated timing  of cash flows |   | (25,470               | )       | (16,897 | ) | (42,367 | ) |
| Standardized measure of discounted future net cash flows     |   | $                     | 36,005  |   | $ | 45,763 |   | $ | 81,768 |   |

 

52

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Thecomputation of the standardized measure of discounted future net cash flowsrelating to proved oil and gas reserves at December 31, 2002 was based onaverage oil and liquids prices of $29.84 per barrel in the United States and$24.68 per barrel in Canada, and average natural gas prices of $3.14 per Mcf inthe United States and $3.84 per Mcf in Canada.

 
|                                                         |   | **December 31, 2001** |   |
|--------------------------------------------------------------|--------|-----------------------|--------|
|                                                         |   | **United  States**    |   | **Canada** |   | **Total** |   |
|                                                         |   | **(in thousands)**    |   |
|                                                         |   |                  |   |   |   |   |   |
| Future oil and gas revenue                                   |   | $                     | 84,038 |   | $ | 55,219 |   | $ | 139,257 |   |
| Future production costs                                      |   | (24,141               | )      | (18,698 | ) | (42,839 | ) |
| Future development costs                                     |   | (6,734                | )      | (3,497 | ) | (10,231 | ) |
| Future income tax expense                                    |   | (6,224                | )      | (8,537 | ) | (14,761 | ) |
| Future net cash flows                                        |   | 46,939                |   | 24,487 |   | 71,426 |   |
| 10% annual discount for estimated timing  of cash flows |   | (18,235               | )      | (5,379 | ) | (23,614 | ) |
| Standardized measure of discounted future net cash flows     |   | $                     | 28,704 |   | $ | 19,108 |   | $ | 47,812 |   |

 

Thecomputation of the standardized measure of discounted future net cash flowsrelating to proved oil and gas reserves at December 31, 2001 was based onaverage oil and liquids prices of $18.45 per barrel in the United States and$13.02 per barrel in Canada, and average natural gas prices of $2.25 per Mcf inthe United States and $2.30 per Mcf in Canada.

 
|                                                         |   | **December 31, 2000** |    |
|--------------------------------------------------------------|--------|-----------------------|---------|
|                                                         |   | **United  States**    |    | **Canada** |   | **Total** |   |
|                                                         |   | **(in thousands)**    |    |
|                                                         |   |                  |    |   |   |   |   |
| Future oil and gas revenue                                   |   | $                     | 326,156 |   | $ | 186,815 |   | $ | 512,971 |   |
| Future production costs                                      |   | (51,331               | )       | (14,828 | ) | (66,159 | ) |
| Future development costs                                     |   | (7,923                | )       | (2,719 | ) | (10,642 | ) |
| Future income tax expense                                    |   | (75,844               | )       | (65,986 | ) | (141,830 | ) |
| Future net cash flows                                        |   | 191,058               |    | 103,282 |   | 294,340 |   |
| 10% annual discount for estimated timing  of cash flows |   | (79,804               | )       | (27,872 | ) | (107,676 | ) |
| Standardized measure of discounted future net cash flows     |   | $                     | 111,254 |   | $ | 75,410 |   | $ | 186,664 |   |

 

Thecomputation of the standardized measure of discounted future net cash flowsrelating to proved oil and gas reserves at December 31, 2000 was based onaverage oil prices of $25.50 per barrel in the United States and $21.73 perbarrel in Canada, and average natural gas prices of $9.76 per Mcf in the UnitedStates and $9.00 per Mcf in Canada.

 

53

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The standardized measure of discounted future net cashflows should not be construed to be an estimate of the fair value of theCompany’s proved reserves.  Changes inthe demand for oil and gas, price changes, reserve recovery variances and otherfactors make such estimates inherently imprecise and subject to revision.

 

Thetables below set forth the principle sources of changes in the standardizedmeasure of discounted future net cash flows for the years endedDecember 31, 2002 , 2001 and 2001:

 
|                                                                                                                    |   | **December 31, 2002** |   |
|-------------------------------------------------------------------------------------------------------------------------|--------|-----------------------|--------|
|                                                                                                                    |   | **United  States**    |   | **Canada** |   | **Total** |   |
|                                                                                                                    |   | **(in thousands)**    |   |
|                                                                                                                    |   |                  |   |   |   |   |   |
| Standardized measure of discounted future net cash flows  relating to proved oil and gas reserves, at beginning of year |   | $                     | 28,704 |   | $ | 19,108 |   | $ | 47,812 |   |
|                                                                                                                    |   |                  |   |   |   |   |   |
| Changes resulting from:                                                                                                 |   |                  |   |   |   |   |   |
| Sales and transfers of oil and gas produced, net of  production costs                                                   |   | (5,044                | )      | (5,793 | ) | (10,837 | ) |
| Net change in sales price and future production costs                                                                   |   | 12,353                |   | 25,724 |   | 38,077 |   |
| Net changes in future development costs                                                                                 |   | (195                  | )      | 735 |   | 540 |   |
| Net changes due to extensions, discoveries and improved  recovery                                                       |   | 2,034                 |   | 16,218 |   | 18,252 |   |
| Revision of previous quantity estimates                                                                                 |   | 1,964                 |   | (2,568 | ) | (604 | ) |
| Purchase of reserves in place                                                                                           |   | —                |   | 4,746 |   | 4,746 |   |
| Sales of reserves in place                                                                                              |   | (2,198                | )      | — |   | (2,198 | ) |
| Accretion of discount                                                                                                   |   | 3,111                 |   | 2,468 |   | 5,579 |   |
| Net change in income tax                                                                                                |   | (3,857                | )      | (12,575 | ) | (16,432 | ) |
| Other                                                                                                                   |   | (867                  | )      | (2,300 | ) | (3,167 | ) |
| Net changes                                                                                                             |   | 7,301                 |   | 26,655 |   | 33,956 |   |
|                                                                                                                    |   |                  |   |   |   |   |   |
| Standardized measure of discounted future net cash flows  relating to proved oil and gas reserves, at end of year       |   | $                     | 36,005 |   | $ | 45,763 |   | $ | 81,768 |   |

 

54

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|                                                                                                                    |   | **December 31, 2001** |    |
|-------------------------------------------------------------------------------------------------------------------------|--------|-----------------------|---------|
|                                                                                                                    |   | **United  States**    |    | **Canada** |   | **Total** |   |
|                                                                                                                    |   | **(in thousands)**    |    |
|                                                                                                                    |   |                  |    |   |   |   |   |
| Standardized measure of discounted future net cash flows  relating to proved oil and gas reserves, at beginning of year |   | $                     | 111,254 |   | $ | 75,410 |   | $ | 186,664 |   |
|                                                                                                                    |   |                  |    |   |   |   |   |
| Changes resulting from:                                                                                                 |   |                  |    |   |   |   |   |
| Sales and transfers of oil and gas produced, net of  production costs                                                   |   | (8,236                | )       | (9,993 | ) | (18,229 | ) |
| Net change in sales price and future production costs                                                                   |   | (105,421              | )       | (83,846 | ) | (189,267 | ) |
| Net changes in future development costs                                                                                 |   | 4,678                 |    | 1,074 |   | 5,752 |   |
| Net changes due to extensions, discoveries and improved  recovery                                                       |   | 8,964                 |    | 4,924 |   | 13,888 |   |
| Revision of previous quantity estimates                                                                                 |   | (634                  | )       | (3,103 | ) | (3,737 | ) |
| Purchase of reserves in place                                                                                           |   | —                |    | 320 |   | 320 |   |
| Sales of reserves in place                                                                                              |   | (23,957               | )       | — |   | (23,957 | ) |
| Accretion of discount                                                                                                   |   | 15,353                |    | 11,146 |   | 26,499 |   |
| Net change in income tax                                                                                                |   | 39,872                |    | 33,520 |   | 73,392 |   |
| Other                                                                                                                   |   | (13,169               | )       | (10,344 | ) | (23,513 | ) |
| Net changes                                                                                                             |   | (82,550               | )       | (56,302 | ) | (138,852 | ) |
|                                                                                                                    |   |                  |    |   |   |   |   |
| Standardized measure of discounted future net cash flows  relating to proved oil and gas reserves, at end of year       |   | $                     | 28,704  |   | $ | 19,108 |   | $ | 47,812 |   |

 
|                                                                                                                    |   | **December 31, 2000** |    |
|-------------------------------------------------------------------------------------------------------------------------|--------|-----------------------|---------|
|                                                                                                                    |   | **United  States**    |    | **Canada (1)** |   | **Total** |   |
|                                                                                                                    |   | **(in thousands)**    |    |
|                                                                                                                    |   |                  |    |   |   |   |   |
| Standardized measure of discounted future net cash flows  relating to proved oil and gas reserves, at beginning of year |   | $                     | 25,429  |   | $ | — |   | $ | 25,429 |   |
|                                                                                                                    |   |                  |    |   |   |   |   |
| Changes resulting from:                                                                                                 |   |                  |    |   |   |   |   |
| Sales and transfers of oil and gas produced, net of  production costs                                                   |   | (10,302               | )       | (6,961 | ) | (17,263 | ) |
| Net change in sales price and future production costs                                                                   |   | 113,753               |    | — |   | 113,753 |   |
| Net changes in future development costs                                                                                 |   | (1,269                | )       | — |   | (1,269 | ) |
| Net changes due to extensions, discoveries and improved  recovery                                                       |   | 2,243                 |    | 35,084 |   | 37,327 |   |
| Revision of previous quantity estimates                                                                                 |   | 27,019                |    | — |   | 27,019 |   |
| Purchase of reserves in place                                                                                           |   | —                |    | 76,377 |   | 76,377 |   |
| Accretion of discount                                                                                                   |   | 2,619                 |    | — |   | 2,619 |   |
| Net change in income tax                                                                                                |   | (41,502               | )       | (39,094 | ) | (80,596 | ) |
| Other                                                                                                                   |   | (6,736                | )       | 10,004 |   | 3,268 |   |
| Net changes                                                                                                             |   | 85,825                |    | 75,410 |   | 161,235 |   |
|                                                                                                                    |   |                  |    |   |   |   |   |
| Standardized measure of discounted future net cash flows  relating to proved oil and gas reserves, at end of year       |   | $                     | 111,254 |   | $ | 75,410 |   | $ | 186,664 |   |

 

----

(1)          Changes in Canadian reserves for 2000 represent changes since theCompany’s acquisition of Carbon Canada in February 2000.

 

55

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**14.  Quarterly FinancialData (Unaudited)**

 

Thefollowing table sets forth the Company’s quarterly results of operations for2002 and 2001:

 
|                       |   | **2002**                                 |   |
|----------------------------|--------|------------------------------------------|--------|
|                       |   | **March 31,**                            |   | **June 30,** |   | **September 30,** |   | **December 31,** |   |
|                       |   | **(in thousands except per share data)** |   |
|                       |   |                                     |   |   |   |   |   |   |   |
| Operating revenues         |   | $                                        | 3,626  |   | $ | 4,137 |   | $ | 3,745 |   | $ | 5,012 |   |
| Operating expenses         |   | 1,185                                    |   | 1,226 |   | 1,347 |   | 1,269 |   |
| Operating margin           |   | 2,441                                    |   | 2,911 |   | 2,398 |   | 3,743 |   |
| Net income (loss)          |   | (532                                     | )      | (14,089 | ) | (253 | ) | 319 |   |
|                       |   |                                     |   |   |   |   |   |   |   |
| Basic earnings per share   |   | $                                        | (0.09  | ) | $ | (2.31 | ) | $ | (0.04 | ) | $ | 0.05 |   |
| Diluted earnings per share |   | (0.09                                    | )      | (2.31 | ) | (0.04 | ) | 0.05 |   |

 
|                       |   | **2001**                                 |   |
|----------------------------|--------|------------------------------------------|--------|
|                       |   | **March 31,**                            |   | **June 30,** |   | **September 30,** |   | **December 31,** |   |
|                       |   | **(in thousands except per share data)** |   |
|                       |   |                                     |   |   |   |   |   |   |   |
| Operating revenues         |   | $                                        | 8,303  |   | $ | 6,315 |   | $ | 3,710 |   | $ | 3,627 |   |
| Operating expenses         |   | 1,368                                    |   | 1,260 |   | 1,268 |   | 1,285 |   |
| Operating margin           |   | 6,935                                    |   | 5,055 |   | 2,442 |   | 2,342 |   |
| Net income (loss)          |   | 1,016                                    |   | 1,304 |   | (304 | ) | (443 | ) |
|                       |   |                                     |   |   |   |   |   |   |   |
| Basic earnings per share   |   | $                                        | 0.17   |   | $ | 0.22 |   | $ | (0.05 | ) | $ | (0.07 | ) |
| Diluted earnings per share |   | 0.16                                     |   | 0.21 |   | (0.05 | ) | (0.07 | ) |

 

56

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**ITEM 9.****                                                     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ONACCOUNTING AND                                 FINANCIALDISCLOSURE**

 

Not applicable.

 

**PART III**

 

**ITEM 10.               DIRECTORS AND EXECUTIVE OFFICERSOF THE REGISTRANT**

 

**ITEM 11.               EXECUTIVE COMPENSATION**

 

**ITEM 12.               SECURITY OWNERSHIP OF CERTAINBENEFICIAL OWNERS AND MANAGEMENT**

 

**ITEM 13.               CERTAIN RELATIONSHIPS AND RELATEDTRANSACTIONS**

 

ForPart III, the information set forth in the Company’s definitive ProxyStatement for the Company’s 2003 Annual Meeting of Shareholders, to be filed,is incorporated by reference into this Report.

 

# **ITEM 14                CONTROLS ANDPROCEDURES**

 

Within the 90 days prior to the date of this report, the Companycarried out an evaluation, under the supervision and with the participation ofthe Company’s management, including Carbon’s principal executive officer andprincipal financial officer, of the effectiveness of the design and operationof the Company’s disclosure controls and procedures pursuant to Rule 13a-14under the Securities Exchange Act of 1934. Based upon that evaluation, the principal executive officer andprincipal financial officer concluded that the Company’s disclosure controlsand procedures are effective for purposes of recording, summarizing and timelyreporting material information required to be disclosed in reports that theCompany files under the Securities Exchange Act of 1934.  There were no significant changes in theCompany’s internal controls or in other factors that could significantly affectthese controls since the date the controls were evaluated.

 

57

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**PART IV**

 

**ITEM 15.               EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTSON FORM 8-K**

 
| (a)    | (1)    | Financial Statements:                                    |
|--------|--------|----------------------------------------------------------|
|   |   |                                                     |
|   |   | See indexes to Financial Statements of Carbon in Item 8. |

 

**Schedulesare omitted because of the absence of the conditions under which they arerequired or because the information is included in the Consolidated FinancialStatements or notes to the Consolidated Financial Statements.**

 

(b)           Reports on Form 8-K:

 

**Thefollowing report was filed by the Company on Form 8-K during the quarter endedDecember 31, 2002:  None.**

 

(c)           Exhibits:

 
| **Exhibit  Number** |   | **Description of Exhibit**                                                                                                                                                                                                                                                                                       |
|---------------------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.1                 |   | Articles of Incorporation  of Carbon Energy Corporation, incorporated by reference to Exhibit 2 of the  Company’s registration statement on Form S-4, No. 333-89783, effective  January 18, 2000.                                                                                                 |
|                |   |                                                                                                                                                                                                                                                                                                             |
| 3.2                 |   | Bylaws of Carbon Energy  Corporation, incorporated by reference to Exhibit 3 of the Company’s  registration statement on Form S-4, No. 333-89783, effective January 18,  2000.                                                                                                                              |
|                |   |                                                                                                                                                                                                                                                                                                             |
| 10.1                |   | 1999 Stock Option Plan,  incorporated by reference to Exhibit 10.1 of the Company’s registration  statement on Form S-4, No. 333-89783, effective January 18, 2000.                                                                                                                                         |
|                |   |                                                                                                                                                                                                                                                                                                             |
| 10.2                |   | 1999 Restricted Stock  Plan, incorporated by reference to Exhibit 10.2 of the Company’s registration  statement on Form S-4, No. 333-89783, effective January 18, 2000.                                                                                                                                     |
|                |   |                                                                                                                                                                                                                                                                                                             |
| 10.3                |   | Exchange and Financing  Agreement dated October 14, 1999 among Carbon Energy Corporation, Carbon  Canada Resources Ltd. and Yorktown Energy Partners III, L.P., incorporated by  reference to Exhibit 10.3 of the Company’s registration statement on Form  S-4, No. 333-89783, effective January 18, 2000. |
|                |   |                                                                                                                                                                                                                                                                                                             |
| 10.4                |   | Stock Purchase  Agreement dated August 11, 1999 between Bonneville Pacific Corporation and  Carbon Canada Resources Ltd., incorporated by reference to Exhibit 10.4 of  the Company’s registration statement on Form S-4, No. 333-89783, effective  January 18, 2000.                                       |
|                |   |                                                                                                                                                                                                                                                                                                             |
| 10.5                |   | Form of Indemnification  Agreement between Carbon Energy Corporation and its officers and directors,  incorporated by reference to Exhibit 10.5 of the Company’s registration  statement on Form S-4, No. 333-89783, effective January 18, 2000.                                                            |
|                |   |                                                                                                                                                                                                                                                                                                             |
| 10.6                |   | Employment Agreement,  dated as of October 29, 1999, between Carbon Energy Corporation and Patrick  R. McDonald, incorporated by reference to Exhibit 10.6 of the Company’s  registration statement on Form S-4, No. 333-89783, effective January 18, 2000.                                                 |

 

58

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| 10.7   |   | Employment Agreement,  dated as of October 29, 1999, between Carbon Energy Corporation and  Kevin D. Struzeski, incorporated by reference to Exhibit 10.7 of the  Company’s registration statement on Form S-4, No. 333-89783, effective  January 18, 2000. |
|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                  |
| 10.8   |   | Credit agreement dated  as of May 9, 2002 between CEC Resources Ltd. and Canadian Imperial Bank of  Commerce, incorporated by reference to Exhibit 10.1 of the Company’s  Quarterly Report on Form 10-Q No. 1-15639, filed August 19, 2002.                      |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.9   |   | Amended and restated  credit agreement dated December 31, 2002 between Carbon Energy Corporation  (USA) and Bank of Oklahoma, National Association. *                                                                                                                 |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.10  |   | Asset purchase and sale  agreement dated January 15, 2003 by and between Carbon Energy Corporation  (USA), formerly known as Bonneville Fuels Corporation as Seller and Fasken  Acquisition 02, Ltd. as Buyer.*                                                       |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.11  |   | First amendment to  asset purchase and sale agreement, dated March 19, 2003 by and between Carbon  Energy Corporation (USA), formerly known as Bonneville Fuels Corporation as  Seller and Fasken Acquisition 02, Ltd. as Buyer.*                                     |
|   |   |                                                                                                                                                                                                                                                                  |
| 21     |   | List of subsidiaries*                                                                                                                                                                                                                                                 |
|   |   |                                                                                                                                                                                                                                                                  |
| 23.1   |   | Consent of KPMG LLP*                                                                                                                                                                                                                                                  |
|   |   |                                                                                                                                                                                                                                                                  |
| 23.2   |   | Consent of Ryder Scott  Company, L.P.*                                                                                                                                                                                                                                |
|   |   |                                                                                                                                                                                                                                                                  |
| 23.3   |   | Consent of Sproule  Associates Limited*                                                                                                                                                                                                                               |
|   |   |                                                                                                                                                                                                                                                                  |
| 24     |   | Power of Attorney*                                                                                                                                                                                                                                                    |
|   |   |                                                                                                                                                                                                                                                                  |
| 99.1   |   | Certificate of 10-K  Report, dated March 31, 2003, pursuant to 18 U.S.C. Section 1350, as adopted  pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*                                                                                                        |

 

----

 
|   |   | * Filed herewith |
|--------|--------|------------------|

 

59

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**SIGNATURES**

 

**Pursuantto the requirements of Section 13 of the Securities Exchange Act of 1934, theRegistrant has duly caused this report to be signed on its behalf by theundersigned, thereunto duly authorized.**

**Date:  March 31, 2003**

 
|   |   |   |   |   |   | CARBON ENERGY  CORPORATION |
|--------|--------|--------|--------|--------|--------|----------------------------|
|   |   |   |   |   |   |                       |   |
|   |   |   |   |   |   | By:                        | /s/  Patrick R. McDonald |   |
|   |   |   |   |   |   |                       | Patrick R. McDonald,  President and |
|   |   |   |   |   |   |                       | Chief Executive Officer |
|   |   |   |   |   |   |                       |   |
|   |   |   |   |   |   | By:                        | /s/  Kevin D. Struzeski |   |
|   |   |   |   |   |   |                       | Kevin D. Struzeski,  Treasurer and |
|   |   |   |   |   |   |                       | Chief Financial Officer |

 

**Pursuantto the requirements of the Securities Exchange Act of 1934, this report hasbeen signed below by the following persons of the Registrant and in thecapacities and on the dates indicated:**

** **
| **Date**        |                      | **Name and  Title** |                                                                                                                                                                  | **Signature** |
|-----------------|---------------------------|---------------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------|
|            |                      |                |                                                                                                                                                                  |
| March  31, 2003 | Cortlandt  S. Dietler,    | )                   |                                                                                                                                                                  |
|            | Director                  | )                   |                                                                                                                                                                  |
|            |                      | )                   | /s/ Patrick R. McDonald                                                                                                                                               |          |
| March  31, 2003 | David  H. Kennedy,        | )                   | Patrick  R. McDonald, for himself and as Attorney-in-Fact for the named directors who  together constitute all of the members of Registrant’s Board of Directors |
|            | Director                  | )                   |
|            |                      | )                   |
| March  31, 2003 | Bryan  H. Lawrence,       | )                   |
|            | Director                  | )                   |
|            |                      | )                   |
| March  31, 2003 | Peter  A. Leidel,         | )                   |
|            | Director                  | )                   |
|            |                      | )                   |
| March  31, 2003 | Patrick  R. McDonald,     | )                   |
|            | Director                  | )                   |
|            |                      | )                   |
| March  31, 2003 | Harry  A. Trueblood, Jr., | )                   |
|            | Director                  | )                   |

 

60

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**CERTIFICATIONS**

 

I, Patrick R. McDonald, certify that:

 

1.                                       Ihave reviewed this annual report on Form 10-K of Carbon Energy Corporation;

 

2.                                       Basedon my knowledge, this annual report does not contain any untrue statement of amaterial fact or omit to state a material fact necessary to make the statementsmade, in light of the circumstances under which such statements were made, notmisleading with respect to the period covered by this annual report;

 

3.                                       Basedon my knowledge, the financial statements, and other financial informationincluded in this annual report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant asof, and for, the periods presented in this annual report;

 

4.                                       Theregistrant’s other certifying officer and I are responsible for establishingand maintaining disclosure controls and procedures (as defined in Exchange ActRules 13a-14 and 15d-14) for the registrant and have:

a.                                       designedsuch disclosure controls and procedures to ensure that material informationrelating to the registrant, including its consolidated subsidiaries, is madeknown to us by others within those entities, particularly during the period inwhich this annual report is being prepared;

 

b.                                      evaluatedthe effectiveness of the registrant’s disclosure controls and procedures as ofa date within 90 days prior to the filing date of this annual report (the“Evaluation Date”); and

 

c.                                       presentedin this annual report our conclusions about the effectiveness of the disclosurecontrols and procedures based on our evaluation as of the Evaluation Date;

 

5.                                       Theregistrant’s other certifying officer and I have disclosed, based on our mostrecent evaluation, to the registrant’s auditors and the audit committee ofregistrant’s board of directors (or persons performing the equivalentfunctions):

 

a.                                       allsignificant deficiencies in the design or operation of internal controls whichcould adversely affect the registrant’s ability to record, process, summarizeand report financial data and have identified for the registrant’s auditors anymaterial weaknesses in internal controls; and

 

b.                                      anyfraud, whether or not material, that involves management or other employees whohave a significant role in the registrant’s internal controls; and

 

6.                                       Theregistrant’s other certifying officer and I have indicated in this annualreport whether there were significant changes in internal controls or in otherfactors that could significantly affect internal controls subsequent to thedate of our most recent evaluation, including any corrective actions withregard to significant deficiencies and material weaknesses.

 

 
| Date:  | March  31, 2003 |                                   | /s/  Patrick R. McDonald |   |
|--------|-----------------|----------------------------------------|--------------------------|--------|
|   |            | Patrick  R. McDonald                   |
|   |            | President  and Chief Executive Officer |

 

61

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**CERTIFICATIONS**

 

I, Kevin D. Struzeski, certify that:

 

1.                                       Ihave reviewed this annual report on Form 10-K of Carbon Energy Corporation;

 

2.                                       Basedon my knowledge, this annual report does not contain any untrue statement of amaterial fact or omit to state a material fact necessary to make the statementsmade, in light of the circumstances under which such statements were made, notmisleading with respect to the period covered by this annual report;

 

3.                                       Basedon my knowledge, the financial statements, and other financial informationincluded in this annual report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant asof, and for, the periods presented in this annual report;

 

4.                                       Theregistrant’s other certifying officer and I are responsible for establishingand maintaining disclosure controls and procedures (as defined in Exchange ActRules 13a-14 and 15d-14) for the registrant and have:

 

a.                                       designedsuch disclosure controls and procedures to ensure that material informationrelating to the registrant, including its consolidated subsidiaries, is made knownto us by others within those entities, particularly during the period in whichthis annual report is being prepared;

 

b.                                      evaluatedthe effectiveness of the registrant’s disclosure controls and procedures as ofa date within 90 days prior to the filing date of this annual report (the“Evaluation Date”); and

 

c.                                       presentedin this annual report our conclusions about the effectiveness of the disclosurecontrols and procedures based on our evaluation as of the Evaluation Date;

 

5.                                       Theregistrant’s other certifying officer and I have disclosed, based on our mostrecent evaluation, to the registrant’s auditors and the audit committee ofregistrant’s board of directors (or persons performing the equivalentfunctions):

 

a.                                       allsignificant deficiencies in the design or operation of internal controls whichcould adversely affect the registrant’s ability to record, process, summarizeand report financial data and have identified for the registrant’s auditors anymaterial weaknesses in internal controls; and

 

b.                                      anyfraud, whether or not material, that involves management or other employees whohave a significant role in the registrant’s internal controls; and

 

6.                                       Theregistrant’s other certifying officer and I have indicated in this annualreport whether there were significant changes in internal controls or in otherfactors that could significantly affect internal controls subsequent to thedate of our most recent evaluation, including any corrective actions withregard to significant deficiencies and material weaknesses.

 

 
| Date:  | March  31, 2003 |                                   | /s/  Kevin D. Struzeski |   |
|--------|-----------------|----------------------------------------|-------------------------|--------|
|   |            | Kevin  D. Struzeski                    |
|   |            | Treasurer  and Chief Financial Officer |

 

62

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### **EXHIBIT INDEX**

 

 
| **Exhibit  Number** |   | **Description  of Exhibit**                           |
|---------------------|--------|-------------------------------------------------------|
|                |   |                                                  |
| 10.9                |   | Amended and restated  credit agreement                |
|                |   |                                                  |
| 10.10               |   | Asset purchase and sale  agreement                    |
|                |   |                                                  |
| 10.11               |   | First amendment to  asset purchase and sale agreement |
|                |   |                                                  |
| 10.12               |   | Agreement and Plan of  Reorganization                 |
|                |   |                                                  |
| 21                  |   | List of subsidiaries                                  |
|                |   |                                                  |
| 23.1                |   | Consent of KPMG LLP                                   |
|                |   |                                                  |
| 23.2                |   | Consent of Ryder Scott  Company, L.P.                 |
|                |   |                                                  |
| 23.3                |   | Consent of Sproule  Associates Limited                |
|                |   |                                                  |
| 24                  |   | Power of Attorney                                     |
|                |   |                                                  |
| 99.1                |   | Certification of 10-K  Report                         |

 

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