Use these links to rapidly review the document
CARBON ENERGY CORPORATION INDEX

---

---

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

---

FORM 10-Q

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15() OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2002

Or

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15() OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                              to                             

Commission File Number: 1-15639

---

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

Colorado		84-1515097
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
1700 Broadway, Suite 1150, Denver, CO		80290
(Address of principal executive offices)		(Zip Code)

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

Not Applicable
(Former name, former address and former fiscal year, if changed since last report)

---

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

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

---

---

CARBON ENERGY CORPORATION

INDEX

PART I—FINANCIAL INFORMATION
	Consolidated Balance Sheets as of March 31, 2002 and December 31, 2001
	Consolidated Statements of Operations for the Three Months Ended March 31, 2002 and 2001
	Consolidated Statement of Stockholders' Equity for the Three Months Ended March 31, 2002
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2002 and 2001
	Notes to Consolidated Financial Statements
	Management's Discussion and Analysis of Financial Condition and Results of Operations
	Quantitative and Qualitative Disclosure about Market Risk
PART II—OTHER INFORMATION

PART I—FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

CARBON ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS
(in thousands)

					March 31, 2002			December 31, 2001
					(unaudited)
ASSETS
Current assets:
	Cash				$	—		$	—
	Accounts receivable, trade					2,405			2,258
	Accounts receivable, other					29			53
	Prepaid expenses and other					577			317
	Current derivative asset					112			341
			Total current assets			3,123			2,969
Property and equipment, at cost:
	Oil and gas properties, using the full cost method of accounting:
		Unproved properties				7,885			7,500
		Proved properties				63,997			62,750
	Furniture and equipment					923			927
						72,805			71,177
		Less accumulated depreciation, depletion and amortization				(13,962	)		(12,226	)
			Property and equipment, net			58,843			58,951
Deposits and other long-term assets						502			448
Total assets					$	62,468		$	62,368

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

CARBON ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS
(in thousands)

					March 31, 2002			December 31, 2001
					(unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable and accrued expenses				$	2,913		$	5,113
	Accrued production taxes payable					396			527
	Income taxes payable					—			1,168
	Undistributed revenue and other					986			1,062
	Current derivative liability					806			76
	Deferred income taxes					—			74
			Total current liabilities			5,101			8,020
Long-term debt						22,348			17,870
Other long-term liabilities						11			18
Deferred income taxes						2,185			2,577
Minority interest						29			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 6,090,183 shares and 6,079,225 shares outstanding at March 31, 2002 and December 31, 2001, respectively					31,857			31,799
	Retained earnings					2,006			2,538
	Accumulated other comprehensive loss					(1,069	)		(483	)
			Total stockholders' equity			32,794			33,854
Total liabilities and stockholders' equity					$	62,468		$	62,368

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

CARBON ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
(unaudited)

						Three Months Ended March 31,
						2002			2001
Revenues:
	Oil and gas sales					$	3,548		$	7,616
	Marketing and other, net						78			687
							3,626			8,303
Expenses:
	Oil and gas production costs						1,185			1,368
	Depreciation, depletion and amortization						1,740			1,388
	General and administrative, net						1,329			1,096
	Interest, net						193			186
			Total operating expenses				4,447			4,038
	Minority interest						—			22
Income (loss) before income taxes							(821	)		4,243
	Income tax provision (benefit):
			Current				27			719
			Deferred				(316	)		998
				Total taxes			(289	)		1,717
	Net income (loss) before cumulative effect of change in accounting principle						(532	)		2,526
Cumulative effect of change in accounting principle, net of tax							—			(1,510	)
Net income (loss)						$	(532	)	$	1,016
Average number of common shares outstanding:
	Basic						6,086			6,026
	Diluted						6,086			6,246
Earnings (loss) per share—basic:
	Net income (loss) before cumulative effect of change in accounting principle					$	(0.09	)	$	0.42
	Cumulative effect of change in accounting principle, net of tax						—			(0.25	)
						$	(0.09	)	$	0.17
Earnings (loss) per share—diluted:
	Net income (loss) before cumulative effect of change in accounting principle					$	(0.09	)	$	0.40
	Cumulative effect of change in accounting principle, net of tax						—			(0.24	)
						$	(0.09	)	$	0.16

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

CARBON ENERGY CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
For the Three Months Ended March 31, 2002
(in thousands)
(unaudited)

				Common Stock					Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income (Loss)
				Shares		Amount									Total
Balances, December 31, 2001				6,079		$	31,799		$	2,538		$	(483	)	$	33,854
Comprehensive income:
	Net income									(532	)		—			(532	)
	Currency translation adjustment												(6	)		(6	)
	Reclassification adjustment for settled contracts												92			92
	Changes in fair value of outstanding hedge positions												(640	)		(640	)
	Impaired oil and gas hedging swaps												(32	)		(32	)
		Total comprehensive income														(1,118	)
Common stock issued				5			25			—			—			25
Vesting of restricted stock grants				6			33			—			—			33
Balances, March 31, 2002				6,090		$	31,857		$	2,006		$	(1,069	)	$	32,794

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

CARBON ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)

					For the Three Months Ended March 31,
					2002			2001
Cash flows from operating activities:
	Net income (loss)				$	(532	)	$	1,016
	Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
		Depreciation, depletion and amortization expense				1,740			1,388
		Non cash settlement of derivative contracts				(51	)		—
		Deferred income tax				(316	)		998
		Cumulative effect of change in accounting principle				—			1,510
		Minority interest				—			22
		Vesting of restricted stock grants				33			30
		Changes in operating assets and liabilities:
			Decrease (increase) in:
			Accounts receivable			908			(1,222	)
			Amounts due from broker			—			1,408
			Employee trust			—			51
			Prepaid expenses and other assets			6			330
		Increase (decrease) in:
			Accounts payable and accrued expenses			(2,811	)		(1,674	)
			Undistributed revenue			(74	)		465
		Net cash provided by (used in) operating activities				(1,097	)		4,322
Cash flows from investing activities:
	Capital expenditures for oil and gas properties					(2,440	)		(6,335	)
	Proceeds from property sale					1			6,758
	Acquisition of CEC Resources					—			(203	)
	Capital expenditures for support equipment					—			(24	)
		Net cash provided by (used in) investing activities				(2,439	)		196
Cash flows from financing activities:
	Proceeds from note payable					8,549			19,227
	Principal payments on note payable					(4,069	)		(23,745	)
	Proceeds from issuance of common stock					24			36
		Net cash provided by (used in) financing activities				4,504			(4,482	)
Effect of exchange rate changes on cash						—			(57	)
Net increase (decrease) in cash						968			(21	)
Cash, beginning of period						(968	)		21
Cash, end of period					$	—		$	—
Supplemental cash flow information:
	Cash paid for interest				$	197		$	255
	Cash paid for taxes					1,236			263

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

CARBON ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.    Nature of Operations

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

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

        All amounts are presented in U.S. dollars.

        The unaudited financial statements presented herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). The statements do not include certain information and note disclosures required by accounting principles generally accepted in the United States for complete financial statements. The accompanying consolidated financial statements of the Company should be read in conjunction with the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K, for the year ended December 31, 2001, as filed with the SEC. The statements reflect all adjustments that, in the opinion of management, are necessary to fairly present the Company's financial position at March 31, 2002 and the results of operations and cash flows for the periods presented.

2.    Significant Accounting Policies

        Principles of Consolidation—The consolidated financial statements include the accounts of Carbon and its subsidiaries all of which are wholly owned, except CEC, of which the Company owns approximately 99.7% of the equity. All significant intercompany transactions and balances have been eliminated.

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

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

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

        Pursuant to full cost accounting rules, total capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of the present value of future net revenues from the estimated production of proved oil and gas reserves discounted at 10%, using constant oil and gas prices in effect at the end of the reporting period; plus the cost of properties not being amortized, if any; plus the lower of cost or estimated fair market value of unproved properties included in the costs being amortized, if any; less related income tax effects. The capitalized costs reflected in the accompanying financial statements do not exceed this limitation.

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

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

        Undistributed Revenue—Represents revenue due to other owners of jointly owned oil and gas properties.

        Revenue Recognition—The Company follows the sales method of accounting for natural gas revenues. Under this method, revenues are recognized based on the actual volume of gas sold to purchasers. To the extent the volumes of gas sold is more (overproduced) or less (underproduced) than the volumes to which the Company is entitled based on its interests in its properties, a gas imbalance has been created. Where the estimated remaining reserves on a property will not be sufficient to enable the underproduced owner to recoup its share of production, revenue is deferred and a liability is created.

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

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

        Pursuant to Company guidelines, the Company is to engage in these activities only as a hedging mechanism. The Company has a Risk Management Committee to administer and approve all production hedging transactions. Gains or losses from financial instruments that qualify for hedge accounting treatment are recognized as an adjustment to sales revenue in the period in which the financial instrument matures. Gains or losses from financial instruments that do not qualify for hedge accounting treatment are recognized in the current period as other income or expense. The cash flows from such agreements are included in operating activities in the consolidated statements of cash flows. The following table sets forth the hedge gains/(losses) realized by the Company for the three months ended March 31, 2002 and 2001 (in thousands):

        The table below sets forth the Company's fixed price positions relating to its natural gas and oil production at March 31, 2002:

Fixed price:

        The Company utilizes financial instruments known as collars that establish a floor and ceiling price. The table below sets forth the Company's natural gas and oil collars in place at March 31, 2002:

Collars:

        On January 1, 2001, the Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," which provides accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. It also requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.

        The table below sets forth the financial statement impact to the Company of recording derivative instruments designated as hedges and derivative instruments not designated as hedges upon the adoption of SFAS No. 133 on January 1, 2001:

        During the first quarter of 2002, net hedging gains of $157,000 ($92,000 after tax) were transferred from other comprehensive income to earnings, and the change in the fair market value of outstanding derivative contracts designated as hedges decreased by $1.0 million ($600,000 after tax). As the underlying prices in the Company's hedge contracts were consistent with the indices used to sell their oil and gas, no ineffectiveness was recognized related to its hedge commitments in the first quarter of 2002. As of March 31, 2002, the Company had net unrealized derivative losses of $654,000 ($410,000 after tax). Based on futures prices as of March 31, 2002, the Company expects to reclassify $695,000 of these net unrealized losses to earnings during the next twelve month period.

        Interest Rate Swap Agreements—During the first quarter of 2002, the Company entered into interest rate swap agreements that effectively convert a portion its variable rate borrowings in the United States to fixed rate debt for periods of up to two years, thus reducing the impact of interest rate changes on future income. The table below sets forth the Company's interest rate derivative contracts in place at March 31, 2002:

        Foreign Currency Translation—Foreign currency transactions and financial statements are translated in accordance with SFAS No. 52, "Foreign Currency Translation." The Company uses the U.S. dollar as the functional currency for its U.S. operations and uses the Canadian dollar as the functional currency for its Canadian operations. Assets and liabilities related to the Company's Canadian operations are generally translated at the current exchange rate in effect as of the date of the balance sheet. Translation adjustments are reported as a component of stockholders' equity. Income statement accounts are translated at the average exchange rates during the reporting period. As a result of the change in the value of the Canadian dollar relative to the U.S. dollar, the Company reported non-cash currency translation losses of $6,000 and $378,000 for the three months ended March 31, 2002 and 2001, respectively.

        Comprehensive Income—The Company follows the provisions of SFAS No. 130, "Reporting Comprehensive Income." Comprehensive income includes net income and certain items recorded directly to stockholders' equity and classified as other comprehensive income. The following table sets forth the calculation of comprehensive income for the three months ended March 31, 2002 and 2001:

        The impairment of oil and gas hedging swaps related to a fourth quarter 2001 non-cash provision of $246,000 ($153,000 after tax) with Enron North America (Enron). In accordance with generally accepted accounting principles, the Company recorded non-cash revenues of $51,000 during the first quarter of 2002, with an additional $195,000 to be recorded during the course of 2002 as these hedges would have expired.

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

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

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

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

        In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The asset retirement liability will be allocated to operating expense by using a systematic and rational method. The statement is effective for fiscal years beginning after June 15, 2002. The Company has not yet determined the impact of adoption of this statement.

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

3.    Acquisition and Disposition of Assets

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

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

4.    Long-term Debt

        U.S. Credit Facility—The Company's credit facility is an oil and gas reserve based line-of-credit with Wells Fargo Bank West National Association (Wells Fargo) and had a borrowing base of $20.0 million with outstanding borrowings of $17.9 million at March 31, 2002. The facility is secured by certain U.S. oil and gas properties of the Company and is scheduled to convert to a term note on October 1, 2002. The Company is currently in negotiations with Wells Fargo to extend the revolving phase of the facility. However, there can be no guarantee that the Company will be able to successfully negotiate such an extension. The facility is scheduled to have a maturity date of either the economic half life of the Company's remaining U.S. reserves on the last day of the revolving period, or October 1, 2006, whichever is earlier. Subject to possible changes in the borrowing base, Wells Fargo has agreed that it will not require the Company to make any principal payments under the term loan section of the facility until April 2003 at the earliest. As such, no amounts under the Wells Fargo facility have been classified as current on the March 31, 2002 balance sheet. The facility bears interest at a rate equal to LIBOR plus 1.75% or Wells Fargo Prime, at the option of the Company. The Company's average borrowing rate was approximately 3.7% at March 31, 2002. The borrowing base is based upon the lender's evaluation of the Company's proved oil and gas reserves, generally determined semi-annually.

        The credit agreement contains various covenants, which prohibit or limit the Company's ability to pay dividends, purchase treasury shares, incur indebtedness, sell properties or merge with another entity. The Company is also required to maintain certain financial ratios.

        Canadian Credit Facility—The Company's credit facility is an oil and gas reserve based line-of-credit with Canadian Imperial Bank of Commerce (CIBC) and had a borrowing base of $9.0 million with outstanding borrowings of $4.5 million at March 31, 2002. The Canadian facility is secured by the Canadian oil and gas properties of the Company. The revolving phase of the Canadian facility expired on March 31, 2002. The Company is currently in negotiations with CIBC to extend the revolving phase to April 1, 2003. However, there can be no guarantee that the Company will be able to successfully negotiate such an extension. If the revolving commitment is not renewed, the loan will be converted into a term loan and will be reduced by consecutive monthly payments over a period not to exceed 24 months. Subject to possible changes in the borrowing base, CIBC has agreed that it will not require the Company to make any principal payments under the term loan section of the facility until April 2003 at the earliest. As such, no amounts under the CIBC facility have been classified as current on the March 31, 2002 balance sheet. The Canadian facility bears interest at the CIBC Prime rate plus .5%. The Company's borrowing rate was 4.25% at March 31, 2002.

        The Canadian facility contains various covenants that limit the Company's ability to pay dividends, purchase treasury shares, incur indebtedness, sell properties, or merge with another entity.

        The agreement with CIBC also provides for $3.5 million of credit which can be utilized for financial derivative instruments used to hedge a portion of the Company's oil and gas production, currency exchange contracts and fixed price gas sales transactions. The Company currently utilizes the swap facility to hedge a portion of its Canadian production as described in Note 2 to the Consolidated Financial Statements.

5.    Business and Geographical Segments

        Segment information has been prepared in accordance with SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." Carbon has two reportable business and geographic segments: BFC and CEC, representing oil and gas operations in the United States and Canada, respectively. The segments are business units that operate in unique geographic locations. The segment data presented below for the three months ended March 31, 2002 and 2001 was prepared on the same basis as Carbon's consolidated financial statements.

				Three Months Ended March 31, 2002									Three Months Ended March 31, 2001
				United States			Canada			Total			United States			Canada			Total
Revenues:
	Oil and gas sales			$	1,899		$	1,649		$	3,548		$	3,801		$	3,815		$	7,616
	Marketing and other, net				78			—			78			687			—			687
					1,977			1,649			3,626			4,488			3,815			8,303
Expenses:
	Oil and gas production costs				769			416			1,185			843			525			1,368
	Depreciation, depletion and amortization				1,082			658			1,740			737			651			1,388
	General and administrative, net				878			451			1,329			620			476			1,096
	Interest, net				163			30			193			132			54			186
		Total operating expenses			2,892			1,555			4,447			2,332			1,706			4,038
	Minority interest				—			—			—			—			22			22
Income (loss) before income taxes					(915	)		94			(821	)		2,156			2,087			4,243
Income tax provision (benefit)					(343	)		54			(289	)		809			908			1,717
Net income (loss) before cumulative effect of change in accounting principle					(572	)		40			(532	)		1,347			1,179			2,526
Cumulative effect of change in accounting principle, net of tax					—			—			—			(1,510	)		—			(1,510	)
Net income (loss)				$	(572	)	$	40		$	(532	)	$	(163	)	$	1,179		$	1,016
Total assets				$	42,675		$	19,793		$	62,468		$	39,496		$	18,539		$	58,035

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

Results of Operations

        The following table and the discussion that follows present comparative revenue, production volumes, average sales prices, expenses and the percentage change between periods for the three months ended March 31, 2002 and 2001 (first quarter) for the Company's United States and Canadian operations.

        All amounts are presented in U.S. dollars.

				United States Three Months Ended March 31,								Canada Three Months Ended March 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			$	1,899		$	3,801		-50	%	$	1,649		$	3,815		-57	%
	Marketing and other, net				78			687		-89	%		—			—		n/a
		Total revenues		$	1,977		$	4,488		-56	%	$	1,649		$	3,815		-57	%
Daily production volumes:
	Natural gas (MMcf)				9.1			6.7		36	%		6.2			6.9		-10	%
	Oil and liquids (Bbl)				247			239		3	%		155			171		-9	%
	Equivalents production (MMcfe 6:1)				10.6			8.1		31	%		7.1			7.9		-10	%
Average price realized:
	Natural gas (Mcf)			$	1.84		$	5.23		-65	%	$	2.56		$	5.44		-53	%
	Oil and liquids (Bbl)				17.91			28.97		-38	%		15.58			28.15		-45	%
Direct lifting costs				$	386		$	290		33	%	$	349		$	511		-32	%
Average direct lifting costs/Mcfe					0.41			0.39		5	%		0.54			0.72		-25	%
Other production costs					383			553		-31	%		67			14		n/a
General and administrative, net					878			620		42	%		451			476		-5	%
Depreciation, depletion and amortization					1,082			737		47	%		658			651		1	%
Interest expense, net					163			132		23	%		30			54		-44	%
Income tax provision					(343	)		809		-142	%		54			908		-94	%

        Revenues from oil and gas sales of BFC for the first quarter of 2002 were $1.9 million, a 50% decrease from 2001. The decrease was due primarily to decreased oil and natural gas prices, partially offset by increased oil, liquids and natural gas production.

        Revenues from oil, liquids and gas sales of CEC for the first quarter of 2002 were $1.6 million, a 57% decrease from 2001. The decrease was due primarily to decreased oil, liquids and natural gas prices and a decrease in oil, liquids and natural gas production.

        Average production in the United States for the first quarter of 2002 was 247 barrels of oil and liquids per day and 9.1 million cubic feet (MMcf) of gas per day, an increase of 31% from the same period in 2001 on a Mcf equivalent (Mcfe) basis where one barrel of oil or liquids is equal to six Mcf of gas. The increase in oil, liquids and gas production was due to successful drilling activities conducted during 2001 in the Piceance and Permian Basins, partially offset by natural production declines. During the first quarter of 2002, BFC participated in the drilling of two gross (.1 net) oil wells compared to two gross (.5 net) oil wells, five gross (3.4 net) gas wells and two gross (1.4 net) unsuccessful wells during the first quarter of 2001.

        Average production in Canada for the first quarter of 2002 was 155 barrels of oil and liquids per day and 6.2 MMcf of gas per day, a decrease of 10% on a Mcfe basis from the same period in 2001. The decrease was primarily due to comparatively large first quarter 2001 production volumes related to the initial production from the Company's fourth quarter 2000 drilling program and natural production declines in all operating areas, partially offset by successful drilling activities in the Carbon and Rowley areas of Central Alberta. During the first quarter of 2002, CEC participated in the drilling of two gross (1.5 net) gas wells and one gross (.5 net) unsuccessful well compared to three gross (3.0 net) gas wells during the first quarter of 2001.

        Average oil and liquids prices realized by BFC decreased 38% from $28.97 per barrel for the first quarter of 2001 to $17.91 for 2002. Average natural gas prices realized by BFC decreased 65% from $5.23 per Mcf for the first quarter of 2001 to $1.84 for 2002. The average natural gas price includes hedge losses of $529,000 for the first quarter of 2001 compared to hedge gains of $51,000 for 2002. The Company's estimated average price on March 31, 2002 for natural gas and oil and liquids was $2.54 per Mcf and $23.82 per barrel, respectively.

        Average oil and liquids prices realized by CEC decreased 45% from $28.15 per barrel for the first quarter of 2001 to $15.58 for 2002. The average oil price includes hedge gains of $11,000 for the first quarter of 2002. There was no oil hedge activity for the first quarter of 2001. Average natural gas prices realized by CEC decreased 53% from $5.44 per Mcf for the first quarter of 2001 to $2.56 for 2002. The average natural gas price includes hedge losses of $720,000 for the first quarter of 2001 compared to hedge gains of $95,000 for 2002. The Company's estimated average price on March 31, 2002 for natural gas and oil and liquids was $2.73 per Mcf and $23.20 per barrel, respectively.

        Marketing and other revenues in the United States were $78,000 for the first quarter of 2002 compared to $687,000 for 2001. First quarter 2001 results were primarily due to mark to market gains of $621,000 related to a derivative contract that no longer qualified for hedge accounting treatment upon the January 1, 2001 adoption of Statement of Financial Accounting Standard (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." In conjunction with the adoption of SFAS No. 133, the Company recorded a derivative loss (net of tax) of $1.5 million as the cumulative effect of a change in accounting principle related to the derivative contract. The Company has reduced its efforts concerning the marketing of third party natural gas and anticipates that natural gas trading activities will continue to decline significantly in 2002 compared to 2001 and prior years.

        Direct lifting costs incurred by BFC were $386,000 or $.41 per Mcfe for the first quarter of 2002 compared to $290,000 or $.39 per Mcfe for 2001.

        Other production costs incurred by BFC, consisting primarily of severance taxes and production overhead, were $383,000 for the first quarter of 2002 compared to $553,000 for 2001. The decrease was primarily due to lower severance taxes as a result of lower oil, liquids and gas prices and a credit for prior period ad valorem taxes, partially offset by increased oil, liquids and gas production.

        Direct lifting costs incurred by CEC were $349,000 or $.54 per Mcfe for the first quarter of 2002 compared to $511,000 or $.72 per Mcfe for 2001. The higher per Mcfe expense in the first quarter of 2001 was primarily due to higher chemical costs related to the Company's initial production and a prior period charge for gas processing fees.

        Other production costs incurred by CEC, consisting primarily of severance taxes, were $67,000 for the first quarter of 2002 compared to $14,000 for 2001. The increase was primarily due to increased production during the first quarter of 2002 from wells subject to these taxes.

        General and administrative expenses (net of overhead reimbursements on operated wells) incurred by BFC increased 42% from $620,000 for the first quarter of 2001 to $878,000 for 2002. The increase was primarily due to legal expenses incurred of $146,000 related to the case of Bonneville Fuels Corporation vs. Williams Production RMT Company, which proved unsuccessful. For more information regarding this case, see Part II, Item 1, to the Form 10-Q.

        General and administrative expenses (net of overhead reimbursements on operated wells) incurred by CEC decreased 5% from $476,000 for the first quarter of 2001 to $451,000 for 2002.

        Interest expense incurred by BFC increased 23% from $132,000 for the first quarter of 2001 to $163,000 for 2002. The increase was due primarily to increased average debt balances in the first quarter of 2002 relative to 2001, partially offset by a decline in interest rates.

        Interest expense incurred by CEC decreased 44% from $54,000 for the first quarter of 2001 to $30,000 for 2002. The decrease was due primarily to a decline in interest rates, partially offset by increased average debt balances in the first quarter of 2002 relative to 2001.

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

        DD&A expense incurred by BFC was $1.1 million or $1.14 per Mcfe for the first quarter of 2002 compared to $737,000 or $1.00 per Mcfe for 2001. The increased rate is due to the capitalized cost per Mcfe of reserves added to the Company's proved reserves during 2001 compared to the rate established at the time of the acquisition of BFC.

        DD&A expense incurred by CEC was $658,000 or $1.02 per Mcfe compared to $651,000 or $.91 per Mcfe for 2001. The increased rate is due to the capitalized cost per Mcfe of reserves added to the Company's proved reserves during 2001 compared to the rate established at the time of the acquisition of CEC.

        Income tax benefit recorded by BFC was $343,000 for the first quarter of 2002, an effective tax rate of 38% compared to an expense of $809,000 and an effective tax rate of 38% for 2001.

        Income tax expense incurred by CEC was $54,000 for the first quarter of 2002, an effective tax rate of 57% compared to $908,000 and an effective tax rate of 44% for 2001.

Liquidity and Capital Resources

        At March 31, 2002, the Company had $62.5 million of assets. Total capitalization was $55.1 million, consisting of 59% of stockholders' equity and 41% of debt.

        For a discussion of the Company's credit facilities, see Note 4 to the Consolidated Financial Statements in this report.

        For the three months ended March 31, 2002, net cash used in operations was $1.1 million compared to $4.3 million provided by operations in 2001. Net cash provided by operations prior to changes in working capital for the three months ended March 31, 2002 was $874,000 compared to $5.0 million in 2001. The decrease in operating cash flow was primarily due to sharp declines in oil, liquids, and natural gas prices, partially offset by increased oil, liquids and natural gas production.

        For the three months ended March 31, 2002, net cash used in investing activities was $2.4 million compared to $196,000 provided by investing activities in 2001. For the three months ended March 31, 2002, net cash provided by financing activities was $4.5 million compared to $4.5 million used in financing activities in 2001. For the three months ended March 31, 2002, the Company spent approximately $700,000 in the United States primarily to fund development and exploration activities in the Piceance Basin and approximately $1.7 million in Canada primarily to fund development and exploration activities in the Carbon area of Central Alberta. For the three months ended March 31, 2001, the Company spent approximately $3.8 million in the United States primarily to fund development and exploration activities in the Permian and Piceance Basins. The Company also received $6.8 million in proceeds related to the disposition of the Company's working interest and related leasehold rights in the San Juan Basin. For the three months ended March 31, 2001, the Company spent $2.8 million primarily to fund development activities in the Carbon area of Central Alberta.

        Carbon's primary cash requirements will be to fund exploration and development expenditures, finance acquisitions, repay debt, and for general working capital needs. At March 31, 2002, the Company had no cash balances as all available cash is used to pay down the Company's long-term debt and working capital deficit. The Company anticipates that capital expenditures, exclusive of acquisitions (if any) or divestitures in 2002 will be approximately $6.7 million. Carbon believes that available borrowings under its credit agreements and projected operating cash flows will be sufficient to cover its working capital, planned capital expenditures, and debt service requirements for the next 12 months. Nevertheless, Carbon may explore outside funding opportunities including equity or additional debt financings for use in expanding Carbon's operations or in consummating any significant acquisitions. Carbon does not know, however, whether any financing can be accomplished on terms that are acceptable to the Company.

        The Company's future cash flow is subject to a number of variables, including the level of production and commodity prices and unplanned capital expenditures. Also, borrowings under Carbon's credit facilities are subject to a number of conditions, including compliance with various covenants and borrowing base calculations. As a result, there can be no assurance that operating cash flows and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures or to meet other cash needs.

        The table below sets forth the Company's contractual obligations at March 31, 2002 and the effect such obligations are expected to have on its liquidity and cash flow in future periods (in thousands):

Certain Factors That May Affect Future Results

        All statements contained in this filing that are not historical facts are forward-looking statements. Such statements address activities, events or developments that the Company expects, believes, projects, intends or anticipates will or may occur, including such matters as future capital, development and exploration expenditures, reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues), future production of oil and natural gas, business strategies, expansion and growth of the Company's operations, cash flow and anticipated liquidity, prospect development and property acquisition, obtaining financial or industry partners for prospect or program development, or marketing of oil and natural gas. Although the Company believes that the expectation reflected in the forward-looking statements and the assumptions upon which such forward-looking statements are based are reasonable, it can give no assurance that such expectations and assumptions will prove to be correct. Factors that could cause actual results to differ materially are described, among other places, in the Marketing, Competition, Government Regulation, Environmental Regulation and Operating Hazards sections of the Company's 2001 Form 10-K and under "Management's Discussion and Analysis of Financial Condition and Results of Operations." These factors include, but are not limited to, general economic conditions, the market price of oil and natural gas, the risks associated with exploration, the Company's ability to find, acquire, market, develop and produce new properties, operating hazards attendant to the oil and natural gas business, uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures, the strength and financial resources of the Company's competitors, the Company's ability to find and retain skilled personnel, climatic conditions, labor relations, availability and cost of material and equipment, environmental risks, the results of financing efforts, and regulatory developments. All written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements. The Company undertakes no obligation to update any forward-looking statements to reflect future events or developments.

Critical Accounting Polices

        The following summarizes several of our critical accounting policies. See a complete list of significant accounting policies in Note 2 to the Consolidated Financial Statements in this report.

        Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates.

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

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

        Pursuant to full cost accounting rules, total capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of the present value of future net revenues from the estimated production of proved oil and gas reserves discounted at 10% using constant oil and gas prices in effect at the end of the period; plus the cost of properties not being amortized, if any; plus the lower of cost or estimated fair market value of unproved properties included in the cost being amortized, if any; less related income tax effects. The capitalized costs reflected in the accompanying financial statements do not exceed this limitation.

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

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

        Derivative Instrument and Hedging Activities—Pursuant to Company guidelines, the Company is to engage in these activities only as a hedging mechanism. The Company has a Risk Management Committee to administer and approve all hedging transactions. Gains or losses from financial instruments that qualify for hedge accounting treatment are recognized as an adjustment to sales revenue in the period in which the financial instrument matures. Gain or losses from financial instruments that do not qualify for hedge accounting treatment are recognized currently as other income or expense. The cash flows from such agreements are included in operating activities in the consolidated statements of cash flows.

        The Company follows SFAS No. 133, which provides accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair market value which is determined by using market pricing. It also requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

        The Company is exposed to interest rate risk. Interest rate risk is estimated as the potential change in the fair value of interest sensitive investments resulting from an immediate hypothetical change in interest rates. The sensitivity analysis presents the change in fair value of these instruments and changes in the Company's earnings and cash flows assuming an immediate one percent change in floating interest rates. At March 31, 2002, the Company had $17.9 million of floating rate debt through its facility with Wells Fargo and $4.5 million through its facility with CIBC. In addition, the Company currently has interest rate swap agreements that effectively converts a portion of its variable rate borrowings to fixed rate debt as described in Note 2 to the Consolidated Financial Statements in this report. Assuming constant debt levels, the impact on earnings and cash flow for the twelve month period beginning April 1, 2002, from a one percent change in interest rates would be approximately $124,000 before taxes.

Foreign Currency Risk

        The Canadian dollar is the functional currency of CEC. The Company is subject to foreign currency exchange rate risk on cash flows relating to sales, expenses, financing and investing transactions. The Company has not entered into foreign currency forward contracts or other similar financial investments to manage this risk.

Commodity Price Risk

        Oil and gas commodity markets are influenced by global as well as regional supply and demand. Worldwide political events can also impact commodity prices. The Company may use certain financial instruments including swaps, collars, futures and other contracts in an attempt to reduce exposure to the market fluctuations in the price of oil and natural gas. Hedging the Company's oil and natural gas production may limit the Company's exposure to price declines or limit the benefit of price increases. Hedging is subject to a number of risks, including credit risk of the counterparty to the hedge. For additional information, see Note 2 to the Consolidated Financial Statements in this report. In addition, quantitative and qualitative disclosures about market risk were included in the Company's Form 10-K (Item 7A) and the financial statements included therein for the fiscal year ended December 31, 2001.

Inflation and Changes in Prices

        Changing prices, or a change in the dollar's purchasing power, distorts the traditional measures of financial performance which are generally expressed in terms of the actual number of dollars exchanged and do not take into account changes in the purchasing power of the monetary units. This results in the reporting of many transactions over an extended period as though the dollars received or expended were of common value, which does not accurately portray financial performance.

        Inflation, as well as a recessionary period, can cause significant swings in the interest rates that companies pay on bank borrowings. These factors are anticipated to continue to affect the Company's operations both positively and negatively for the foreseeable future.

        Expenses and costs in the oil and gas industry are affected by the overall level of inflation in the economy and price and economic conditions specific to the oil and gas industry, including the effects caused by higher or lower oil and gas prices. Although it is difficult to determine the future prices of oil and natural gas, price fluctuations may have a material effect on the Company.

PART II—OTHER INFORMATION

Item 1		The Company was the plaintiff in Bonneville Fuels Corporation vs. Williams Production RMT Company, brought in District Court of Garfield County, Colorado. Bonneville claimed oil and gas leasehold interests reserved pursuant to an assignment between Bonneville and a third party, subsequently acquired by Williams Production RMT Company. Bonneville also sought damages for breach of the operating agreement governing the lands in question. On March 7, 2002, the Court denied Bonneville's claims. Total expenses incurred in this litigation from inception through March 31, 2002 is approximately $390,000, of which $244,000 was incurred during 2001 ($6,000 in the first quarter of 2001) with the balance of $146,000 recorded in the first quarter of 2002.
Item 2		During the quarter ended March 31, 2003, the Company granted 17,500 shares of its stock under its restricted stock plan to its executive officers and to senior officers of its subsidiaries. The Company believes that these grants did not constitute sales under the Securities Act of 1933. These grants would also be exempt under Section 4(2) of the Securities Act of 1933 in Rule 506 of Regulation D if considered a sale.
Item 3 - 5		Not applicable
Item 6		(a)		Exhibits
		(b)		No reports on Form 8-K were filed by the registrant during the quarter ended March 31, 2002.

SIGNATURES

        Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		CARBON ENERGY CORPORATION Registrant
Date: May 15, 2002		By:	/s/  PATRICK R. MCDONALD       President and Chief Executive Officer
Date: May 15, 2002		By:	/s/  KEVIN D. STRUZESKI       Treasurer and Chief Financial Officer