UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

CARBON ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

 

 

 

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

 

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

 

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

 

 

 

CARBON ENERGY CORPORATION

INDEX

 

PART I—FINANCIAL INFORMATION

Consolidated Balance Sheets as of March 31, 2003 and December 31, 2002

Consolidated Statements of Operations for the Three Months Ended March 31, 2003 and 2002

Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2003 and 2002

Notes to Consolidated Financial Statements

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Quantitative and Qualitative Disclosures about Market Risk

Controls and Procedures

PART II—OTHER INFORMATION

 

 

PART I - FINANCIAL INFORMATION

 

Item 1.           FINANCIAL STATEMENTS

 

CARBON ENERGY CORPORATION

 

CONSOLIDATED BALANCE SHEETS

(in thousands)

(unaudited)

 

		March 31, 2003			December 31, 2002
ASSETS
Current assets:
Cash		$	7,736		$	—
Accounts receivable, trade		4,513			3,240
Prepaid expenses and other		958			918
Total current assets		13,207			4,158
Property and equipment, at cost:
Oil and gas properties, using the full cost method of accounting:
Unproved properties		8,690			7,080
Proved properties		67,323			71,223
Furniture and equipment		931			894
		76,944			79,197
Less accumulated depreciation, depletion and amortization		(32,260		)	(31,503		)
Property and equipment, net		44,684			47,694
Deposits and other long-term assets		451			452
Total assets		$	58,342		$	52,304

 

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

 

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CONSOLIDATED BALANCE SHEETS

(in thousands)

(unaudited)

 

		March 31, 2003			December 31, 2002
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses		$	5,760		$	4,914
Accrued production taxes payable		293			337
Income taxes payable		276			—
Undistributed revenue and other		1,662			1,462
Current derivative liability		1,727			1,116
Total current liabilities		9,718			7,829
Long-term debt		21,242			22,709
Other long-term liabilities		2,987			37
Deferred income taxes		3,707			3,093
Minority interest		—			28
Stockholders' equity:
Preferred stock, no par value: 10,000,000 shares authorized, none outstanding		—			—
Common stock, no par value: 20,000,000 shares authorized, 6,122,447 and 6,116,295 shares issued and outstanding at March 31, 2003 and December 31, 2002, respectively		32,029			31,987
Accumulated deficit		(10,523		)	(12,017		)
Accumulated other comprehensive loss		(818		)	(1,362		)
Total stockholders' equity		20,688			18,608
Total liabilities and stockholders' equity		$	58,342		$	52,304

 

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

 

3

 

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(unaudited)

 

		Three Months Ended March 31,
		2003			2002
Revenues:
Oil and gas sales		$	6,466		$	3,548
Other, net		(192		)	78
		6,274			3,626
Expenses:
Oil and gas production costs		1,259			1,185
Depreciation, depletion and amortization		1,452			1,740
General and administrative, net		1,514			1,329
Interest and other, net		339			193
Total operating expenses		4,564			4,447
Income (loss) before income taxes		1,710			(821		)
Income tax provision (benefit):
Current		457			27
Deferred		96			(316		)
Total taxes		553			(289		)
Income (loss) before cumulative effect of change in accounting principle		1,157			(532		)
Cumulative effect of change in accounting principle, net of tax		336			—
Net income (loss)		$	1,493		$	(532	)
Average number of common shares outstanding:
Basic		6,120			6,086
Diluted		6,381			6,086
Earnings (loss) per share - basic:
Income (loss) before cumulative effect of change in accounting principle		$	0.19		$	(0.09	)
Cumulative effect of change in accounting principle, net of tax		0.05			—
		$	0.24		$	(0.09	)
Earnings (loss) per share - diluted:
Income (loss) before cumulative effect of change in accounting principle		$	0.18		$	(0.09	)
Cumulative effect of change in accounting principle, net of tax		0.05			—
		$	0.23		$	(0.09	)

 

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

 

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CARBON ENERGY CORPORATION

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

 

		For the Three Months Ended March 31,
		2003			2002
Cash flows from operating activities:
Net income (loss)		$	1,493		$	(532	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		1,452			1,740
Unrealized (gain)/loss on derivative contracts		216			(51		)
Deferred income tax		96			(316		)
Vesting of restricted stock grants and other		31			33
Cumulative effect of change in accounting principle		(336		)	—
Changes in operating assets and liabilities:
Decrease (increase) in:
Accounts receivable		(1,105		)	908
Prepaid expenses and other assets		(12		)	6
Increase (decrease) in:
Accounts payable and accrued expenses		626			(3,779		)
Undistributed revenue		131			(74		)
Net cash provided by (used in) operating activities		2,592			(2,065		)
Cash flows from investing activities:
Capital expenditures for oil and gas properties		(7,064		)	(2,440		)
Proceeds from property sales		14,377			1
Acquisition of minority interest in Carbon Energy Canada		(56		)	—
Capital expenditures for support equipment		(34		)	—
Net cash provided by (used in) investing activities		7,223			(2,439		)
Cash flows from financing activities:
Proceeds from notes payable		29,196			8,549
Principal payments on notes payable		(31,234		)	(4,069		)
Proceeds from issuance of common stock		11			24
Net cash provided by (used in) financing activities		(2,027		)	4,504
Effect of exchange rate changes on cash		(52		)	—
Net increase in cash		7,736			—
Cash, beginning of period		—			—
Cash, end of period		$	7,736		$	—
Supplemental cash flow information:
Cash paid for interest		$	228		$	197
Cash paid for taxes		2			1,236

 

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

 

5

 

CARBON ENERGY CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

 

1.                           Nature of Operations

 

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

 

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

 

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

 

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

 

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

 

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

 

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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, 2002, 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, 2003 and the results of its operations and its cash flows for the periods presented.

 

All amounts are presented in U.S. dollars.

 

2.             Significant Accounting Policies

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

		Three Months Ended March 31, 2003
		(in thousands)
Beginning of the period		$	—
Initial adoption entry		2,999
Liabilities incurred in the current period		257
Liabilities settled in the current period		(399		)
Accretion expense		52
Impact of foreign currency change		60
End of the period		$	2,969

 

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

 

		Three Months Ended March 31, 2002			Year Ended December 31,
					2002			2001			2000
		(in thousands, except per share data)
Net income (loss)
As reported		$	(532	)	$	(14,555	)	$	1,573		$	1,456
Pro forma		(499		)	(14,425		)	1,690			1,570
Basic earnings (loss) per common share:
As reported		$	(0.09	)	$	(2.39	)	$	0.26		$	0.25
Pro forma		(0.08		)	(2.35		)	0.28			0.27
Diluted earnings (loss) per common share:
As reported		$	(0.09	)	$	(2.39	)	$	0.25		$	0.25
Pro forma		(0.08		)	(2.35		)	0.27			0.27

 

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

 

8

 

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

 

Adoption Date		Pro Forma Asset Retirement Obligation
		(in thousands)
January 1, 2000		$	1,570
December 31, 2000		2,250
December 31, 2001		2,672
March 31, 2002		2,726
December 31, 2002		2,999

 

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

 

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

 

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

 

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

 

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

 

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

 

9

 

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

 

		Three Months Ended March 31,
		2003			2002
		(in thousands except per share data)
Net income (loss):
As reported		$	1,493		$	(532	)
Pro forma		1,441			(574		)
Basic earnings (loss) per common share:
As reported		$	0.24		$	(0.09	)
Pro forma		0.24			(0.09		)
Diluted earnings (loss) per common share:
As reported		$	0.23		$	(0.09	)
Pro forma		0.23			(0.09		)

 

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

 

		Three Months Ended March 31,
		2003		2002
Expected option life - years		5.00		5.00
Risk-free interest rate		2.78	%	2.79	%
Dividend yield		0.00	%	0.00	%
Volatility		47.16	%	44.84	%

 

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 all potentially dilutive securities would be anti-dilutive.

 

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

 

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

 

3.                           Acquisition and Disposition of Assets

 

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

 

10

 

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

 

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

 

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

 

4.                           Long-term Debt

 

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

 

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

 

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

 

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

 

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

 

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

 

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5.                           Derivative Instruments

 

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

 

Notional Amount			Contract Expiration Date		Fixed Rate		Derivative Asset/ (Liability)
(in thousands)
$	3,700		May 2003		3.46	%	$	(19	)
2,000			October 2003		3.77	%	(38		)
800			October 2003		3.82	%	(15		)
1,000			March 2004		4.15	%	(29		)
2,500			April 2004		4.24	%	(93		)
							$	(194)

 

During the first three months of 2003, net hedging losses of $59,000 ($37,000 after tax) relating to interest rate derivative contracts were transferred from accumulated other comprehensive income to earnings.  The fair value of outstanding interest rate derivative contracts designated as hedges decreased by $17,000 ($10,000 after tax).  In March 2003, Carbon USA closed on the sale of its interest in oil and gas properties located primarily in the Permian Basin of southeast New Mexico.  Proceeds from the sale were used to repay borrowings under the Company’s U.S. credit facility with Bank of Oklahoma.  As a result of this use of proceeds, the Company no longer had variable rate borrowings underlying certain of its interest rate swap agreements. As a result, the Company discontinued hedge accounting for these interest rate swaps and recorded a non-cash charge of $175,000 ($109,000 after tax) related to the change in the fair value of these interest rate swap agreements. As of March 31, 2003, the Company also had net unrealized derivative losses of $19,000 ($12,000 after tax) related to its interest rate swap agreements.  The Company expects to reclassify these unrealized losses to earnings during the next twelve month period.

 

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

 

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Pursuant to Company guidelines, the Company is to engage in these activities only as a hedging mechanism and may not enter into speculative transactions. Gains or losses from financial instruments that qualify for hedge accounting treatment are recognized as an adjustment to sales revenue in the period in which the financial instrument matures. Changes in the fair value of financial instruments that do not qualify for hedge accounting treatment are recognized during the current period as other revenue. 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, 2003 and 2002 (in thousands):

 

		Three Months Ended March 31, 2003						Three Months Ended March 31, 2002
		United States			Canada			United States			Canada
Oil		$	(157	)	$	(64	)	$	—		$	11
Natural gas		(216		)	(211		)	51			95

 

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

 

Swaps:

 

Carbon USA										Carbon Canada
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)
							(in thousands)										(in thousands)
Gas										Gas
04/01/03-12/31/03		1,085,000		$	3.07		$	(1,316	)	04/01/03-12/31/03		130,000		$	3.15		$	(183	)
Oil										Oil
04/01/03-12/31/03		27,500		$	25.63		$	(42	)	04/01/03-12/31/03		27,500		$	27.38		$	(10	)

 

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

 

Fixed price:							Costless collars:
Carbon Canada							Carbon Canada
Time Period		MMBtu		Weighted Average Fixed Price MMBtu			Time Period		MMBtu		Weighted Average Floor Price MMBtu			Weighted Average Ceiling Price MMBtu
Gas							Gas
04/01/03-12/31/03		753,000		$	3.75		04/01/03-12/31/03		289,000		$	3.95		$	5.12
							01/01/04-04/30/04		115,000		3.95			5.78

 

During the first three months of 2003, net hedging losses of $431,000 ($264,000 after tax) relating to commodity derivative contracts were transferred from accumulated other comprehensive income to earnings. The fair value of outstanding commodity derivative contracts designated as hedges decreased by $1.1 million ($663,000 after tax).  In March 2003, Carbon USA closed on the sale of its interest in oil and gas properties located primarily in the Permian

 

13

 

Basin of southeast New Mexico.  At the time of the sale, the Company had an oil commodity swap that was utilized to hedge the Company’s Permian Basin oil production which was sold.  As a result of the sale, the Company no longer has Permian Basin oil production underlying this commodity derivative contract and consequently discontinued hedge accounting for this contract and recorded a non-cash charge of $42,000 ($26,000 net of tax) related to the change in the fair value of this contract. Other than the above mentioned commodity derivative contract, oil and natural gas prices reflective of the Company’s hedge contracts were correlative with the published indices used to sell the Company’s production.  As a result, except for the above mentioned commodity derivative contract, no ineffectiveness was recognized related to the Company’s hedge contracts during the three months ended March 31, 2003.  As of March 31, 2003, the Company had net unrealized commodity derivative losses of $1.5 million ($926,000 after tax).  The Company expects to reclassify all of these net unrealized losses to earnings during the nest twelve months.

 

6.                           Business and Geographical Segments

 

Segment information has been prepared in accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.” Carbon has two reportable business and geographic segments: Carbon USA and Carbon Canada, 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 as of or for the three months ended March 31, 2003 and 2002 was prepared on the same basis as Carbon’s consolidated financial statements.

 

		March 31, 2003									March 31, 2002
		United States			Canada			Total			United States			Canada			Total
Revenues:
Oil and gas sales		$	2,801		$	3,665		$	6,466		$	1,899		$	1,649		$	3,548
Other, net		(192		)	—			(192		)	78			—			78
		2,609			3,665			6,274			1,977			1,649			3,626
Expenses:
Oil and gas production costs		866			393			1,259			769			416			1,185
Depreciation, depletion and amortization		756			696			1,452			1,082			658			1,740
General and administrative, net		978			536			1,514			878			451			1,329
Interest and other, net		236			103			339			163			30			193
Total operating expenses		2,836			1,728			4,564			2,892			1,555			4,447
Income (loss) before income taxes and cumulative effect of accounting change		(227		)	1,937			1,710			(915		)	94			(821		)
Income tax provision (benefit)		(90		)	643			553			(343		)	54			(289		)
Net income (loss) before cumulative effect of accounting change		$	(137	)	$	1,294		$	1,157		$	(572	)	$	40		$	(532	)
Total assets		$	26,077		$	32,265		$	58,342		$	42,675		$	19,793		$	62,468
Capital expenditures		$	1,350		$	5,714		$	7,064		$	767		$	1,673		$	2,440

 

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

 

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

 

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

 

Statements contained in the following management discussion and analysis of financial conditions and results of operations that are not historical facts are forward-looking statements and are subject to completion of the proposed merger.

 

Critical Accounting Policies

 

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.

 

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. For periods prior to January 1, 2003, the estimated future cost of site restoration, dismantlement and abandonment activities was provided for as a component of depletion. Investments in unproved properties are recorded at the lower of cost or fair market value and are not depleted pending the determination of the existence of proved reserves.

 

Pursuant to full cost accounting rules, capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of the present value of future net revenues from estimated production of proved oil and gas reserves using a 10% discount factor and unescalated oil and gas prices and costs as of the end of the period; plus the cost of properties not being amortized, if any; plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less related income tax effects.

 

Reserves – There are many uncertainties inherent in estimating crude oil and natural gas reserve quantities, projecting future production rates and the timing of future development expenditures.  In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history.  Accordingly, these estimates are subject to change as additional information becomes available.  Proved reserves are the estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.  Proved developed reserves are those reserves expected to be recovered through existing equipment and operating methods.

 

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Derivative Instruments and Hedging Activities - Pursuant to Company guidelines, the Company utilizes derivative instruments only as a hedging mechanism and does not enter into speculative transactions. The Company has a Risk Management Committee to administer and approve all hedging transactions. Gains or losses from commodity derivative instruments that qualify for hedge accounting treatment are recognized as an adjustment to sales revenue in the period in which the derivative instrument matures. Gains or losses from financial instruments that do not qualify for hedge accounting treatment are recognized currently as other revenue. The cash flows from such agreements are included in operating activities in the consolidated statements of cash flows.

 

The estimation of fair values for the Company’s hedging derivatives requires substantial judgement.  The fair values of the Company’s derivatives are estimated on a monthly basis using an option pricing model.  The option pricing model uses various factors that include closing exchange prices, volatility and the time value of options.  The estimated future prices are compared to the prices fixed by the hedge agreements and the resulting estimated future cash inflows (outflows) over the lives of the hedges are discounted.  These pricing and discounting variables are sensitive to market volatility as well as to changes in future price forecasts, regional price differentials and interest rates.

 

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 determined based on differences between the financial statement carrying values and their respective income tax bases (temporary differences). Future income tax assets and liabilities are measured using the tax rates expected to be in effect when the temporary differences are likely to reverse. The effect on future income tax assets and liabilities of a change in tax rates is included in operations in the period in which the change is enacted. The amount of future income tax assets recognized is limited to the amount of the benefit that is more likely than not to be realized.

 

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

 

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Results of Operations

 

The following table and discussion present comparative revenue, production volumes, average sales prices, expenses and percentage change between periods for the three months ended March 31, 2003 and 2002 (first quarter) for the Company’s United States and Canadian operations.

 

		United States Three Months Ended March  31,								Canada Three Months Ended March  31,
		2003			2002			Change		2003			2002			Change
		(U.S. dollars in thousands, except prices and per Mcfe information)								(U.S. dollars in thousands, except prices and per Mcfe information)
Revenues:
Oil and gas revenues		$	2,801		$	1,899		47	%	$	3,665		$	1,649		122	%
Other, net		(192		)	78			-346	%	—			—			—
Total revenues		$	2,609		$	1,977		32	%	$	3,665		$	1,649		122	%
Daily production volumes:
Natural gas (MMcf)		7.7			9.1			-15	%	7.5			6.2			21	%
Oil and liquids (Bbl)		225			247			-9	%	157			155			1	%
Equivalent production (MMcfe 6:1)		9.1			10.6			-14	%	8.4			7.1			18	%
Average price realized:
Natural gas (Mcf)		$	3.38		$	1.84		84	%	$	4.93		$	2.56		93	%
Oil and liquids (Bbl)		23.05			17.91			29	%	24.47			15.58			57	%
Direct lifting costs		$	386		$	386		0	%	$	361		$	349		3	%
Average direct lifting costs/Mcfe		0.47			0.41			15	%	0.48			0.54			-11	%
Other production costs		480			383			25	%	32			67			-52	%
General and administrative, net		978			878			11	%	536			451			19	%
Depreciation, depletion and amortization		756			1,082			-30	%	696			658			6	%
Interest and other expense, net		236			163			45	%	103			30			243	%
Income tax provision (benefit)		(90		)	(343		)	-74	%	643			54			1091	%

 

Revenues from oil, liquids and gas sales of Carbon USA for the first quarter of 2003 were $2.8 million, a 47% increase from 2002. The increase was due primarily to increased oil, liquids and natural gas prices in the first quarter of 2003, partially offset by decreased oil, liquids and natural gas production.

 

Revenues from oil, liquids and gas sales of Carbon Canada for the first quarter of 2003 were $3.7 million, a 122% increase from 2002. The increase was due primarily to increased oil, liquids and natural gas prices and increased oil, liquids and natural gas production.

 

Average production in the United States for the first quarter of 2003 was 225 barrels of oil and liquids per day and 7.7 million cubic feet (MMcf) of gas per day, a decrease of 14% from the same period in 2002 on a Mcf equivalent (Mcfe) basis where one barrel of oil or liquids is equal to six Mcf of gas.  The decrease in production was due in part to the disposition of the Company’s Kansas properties in September 2002 and natural production declines in all operating areas. During the first quarter of 2003, Carbon USA participated in the drilling of three gross (.6 net) wells of which one gross (.1 net) was completed as an oil well and two gross (.5 net) were completed as gas wells compared to two gross (.1 net) oil wells during the first quarter of 2002.

 

Average production in Canada for the first quarter of 2003 was 157 barrels of oil and liquids per day and 7.5 MMcf of gas per day, an increase of 18% on a Mcfe basis from the same period in 2002. The increase was primarily due to successful drilling activities in the third and fourth quarters of 2002 and first quarter of 2003 in the Carbon and Rowley areas of central Alberta.  During the first quarter of 2003, Carbon Canada participated in the drilling of four gross (3.8 net) gas wells.  During the first quarter of 2002, Carbon Canada participated in the drilling of three gross (2.0 net) wells of which two gross (1.5 net) were completed as gas wells and one gross (.5 net) well was abandoned as a dry hole.

 

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Average oil and liquids prices realized by Carbon USA increased 29% from $17.91 per barrel for the first quarter of 2002 to $23.05 for 2003.  The average oil and liquids price includes hedge losses of $157,000 or $7.73 per barrel for the first quarter of 2003.  There was no oil hedge activity for the first quarter of 2002.  Average natural gas prices realized by Carbon USA increased 84% from $1.84 per Mcf for the first quarter of 2002 to $3.38 for 2003. The average natural gas price includes hedge losses of $216,000 or $.31 per Mcf for the first quarter of 2003 compared to hedge gains of $51,000 or $.06 per Mcf for 2002.

 

Average oil and liquids prices realized by Carbon Canada increased 57% from $15.58 per barrel for the first quarter of 2002 to $24.47 for 2003.  The average oil and liquids price includes hedge losses of $64,000 or $4.54 per barrel for the first quarter of 2003 compared to hedge gains of $11,000 or $.76 per barrel for 2002.  Average natural gas prices realized by Carbon Canada increased 93% from $2.56 per Mcf for the first quarter of 2002 to $4.93 for 2002. The average natural gas price includes hedge losses of $211,000 or $.32 per Mcf for the first quarter of 2003 compared to hedge gains of $95,000 or $.17 Mcf for 2002.

 

Other losses in the United States were $192,000 for the first quarter of 2003 compared to revenues of $78,000 for 2002.  In March 2003, Carbon USA closed on the sale of its interest in oil and gas properties located primarily in the Permian Basin of southeast New Mexico.  Proceeds from the sale were used to repay borrowings under the Company’s U.S. credit facility with Bank of Oklahoma.  As a result of this use of proceeds, the Company no longer had variable rate borrowings underlying certain of its interest rate swap agreements.  As a result, the Company discontinued hedge accounting for these interest rate swaps and recorded a non-cash charge of $175,000 related to the change in the fair value of these agreements.  In addition, at the time of the asset sale, the Company had an oil commodity swap that was utilized to hedge the Company’s Permian Basin oil production which was sold.  As a result of the sale, the Company no longer has Permian Basin oil production underlying this commodity derivative contract.  Consequently the Company discontinued hedge accounting for this derivative contract and recorded a non-cash charge of $42,000 related to the change in the fair value of this contract.

 

Direct lifting costs incurred by Carbon USA were $386,000 or $.47 per Mcfe for the first quarter of 2003 compared to $386,000 or $.41 per Mcfe for 2002.  The higher per Mcfe expense in the first quarter of 2003 compared to 2002 was due to operating approximately the same number of wells with lower production per well.

 

Other production costs incurred by Carbon USA, consisting primarily of severance taxes and production overhead, were $480,000 for the first quarter of 2003 compared to $383,000 for 2002.   The increase is due primarily to increased severance taxes as a result of higher natural gas and oil prices.

 

Direct lifting costs incurred by Carbon Canada were $361,000 or $.48 per Mcfe for the first quarter of 2003 compared to $349,000 or $.54 per Mcfe for 2002. The lower per Mcfe expense in the first quarter of 2003 was primarily due to a reconfiguration of the Company’s compressor facilities that reduced compressor expenses in the Carbon area and a reduction in contract operating and overhead charges due to Carbon Canada employees assuming these duties.

 

General and administrative (G&A) expenses (net of overhead reimbursements on operated wells) incurred by Carbon USA increased 11% from $878,000 for the first quarter of 2002 to $978,000 for 2003.  The increase was primarily due to one time fees of $317,000 paid to RBC Capital Markets incurred during the first quarter of 2003 for financial advisory services and rendering a fairness opinion to the Board of Directors of Carbon regarding the exchange ratio of common shares in the announced merger with Evergreen.  The comparative increase was partially offset by one time legal expenses of $146,000 incurred during the first quarter of 2002 related to litigation that was concluded in 2002. For the first quarter of 2002 and 2003, Carbon USA capitalized $41,000 of G&A related to geological and geophysical activities.

 

General and administrative expenses (net of overhead reimbursements on operated wells) incurred by Carbon Canada increased 19% from $451,000 for the first quarter of 2002 to $536,000 for 2003. The increase was primarily due to an increase in Carbon management service fees billed to Carbon Canada in the first quarter of 2003 compared to 2002. For the first quarter of 2002 and 2003, Carbon Canada did not capitalize any G&A related to geological and geophysical activities.

 

18

 

Interest and other expense incurred by Carbon USA increased 45% from $163,000 for the first quarter of 2002 to $236,000 for 2003. The increase was due primarily to increased interest rates in the first quarter of 2003 relative to 2002.

 

Interest and other expense incurred by Carbon Canada increased 243% from $30,000 for the first quarter of 2002 to $103,000 for 2003. The increase was due primarily to increased average debt balances in the first quarter of 2003 relative to 2002 and increased interest rates in 2003.

 

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 affected by the purchase price of the properties acquired in the Company's acquisitions of Carbon USA and Carbon Canada, the volume of proved reserves the Company acquired in the acquisitions and a ceiling test impairment recorded by the Company in the second quarter of 2002.

 

DD&A expense incurred by Carbon USA was $756,000 or $.93 per Mcfe for the first quarter of 2003 compared to $1.1 million or $1.14 per Mcfe for 2002. The decreased rate is primarily due to the ceiling test impairment recorded by the Company in the second quarter of 2002.

 

DD&A expense incurred by Carbon Canada was $696,000 or $.92 per Mcfe compared to $658,000 or $1.02 per Mcfe for 2002. The decreased rate is primarily due to the ceiling test impairment recorded by the Company in the second quarter of 2002.

 

Income tax benefit recorded by Carbon USA was $90,000 for the first quarter of 2003, an effective tax rate of 40%. This compared to an income tax benefit of $343,000 and an effective tax rate of 37% for the first quarter of 2002.

 

Income tax expense incurred by Carbon Canada was $643,000 for the first quarter of 2003, an effective tax rate of 33%, compared to $54,000 and an effective tax rate of 57% for 2002.  The decrease in the effective rate for the first quarter of 2003 compared to 2002 was primarily due to permanent differences in the non-deductibility of certain Canadian royalties for oil, liquids and natural gas compared to an allowable special deduction for Canadian resource properties.

 

Liquidity and Capital Resources

 

At March 31, 2003, the Company had $58.3 million of assets. Total capitalization was $41.9 million, consisting of 49% stockholders’ equity and 51% debt.

 

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

 

Net cash provided by operations for the three months ended March 31, 2003 was $2.6 million compared to $2.1 million used in operations in 2002.  The increase in operating cash flow was primarily due to increased oil, liquids, and natural gas prices in all regions and increased oil, liquids and natural gas production in Canada, partially offset by decreased oil, liquids and natural gas production in the United States.

 

For the three months ended March 31, 2003, Carbon USA spent approximately $1.3 million primarily to fund development and exploration activities in Colorado and Utah and received $14.4 million in proceeds related to the disposition of its interest in oil and gas properties located primarily in the Permian Basin of southeast New Mexico.  For the three months ended March 31, 2003, Carbon Canada spent approximately $5.8 million primarily to fund development and exploration activities in central and northwest Alberta.

 

For the three months ended March 31, 2002, Carbon USA spent approximately $767,000 primarily to fund development and exploration activities in Colorado, Montana and Utah.  For the three months ended March 31, 2002, Carbon Canada spent approximately $1.6 million primarily to fund development activities in the Carbon area of central Alberta.

 

19

 

Carbon’s primary cash requirements for the remainder of 2003, subject to completion of the proposed merger described previously, will be to fund exploration and development expenditures, finance acquisitions, repay debt, and for general working capital needs.  The Company has budgeted capital expenditures for the remainder of 2003, exclusive of unplanned acquisitions or divestitures, of approximately $13.9 million.  At March 31, 2003, the Company is in compliance with all its debt covenants and has no reason to believe that either of its credit facilities will require principal payments during the next twelve months.  Under the facilities, funds available at March 31, 2003 were approximately $7.8 million.  In addition, at March 31, 2003, the Company had $7.7 million in cash which was subsequently used to repay borrowings under the Company’s U.S. credit facility in April 2003.  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.

 

On March 24, 2003, Carbon USA closed on the sale of its interest in oil and gas properties located primarily in the Permian Basin of southeast New Mexico.  Net proceeds from the sale, after normal closing adjustments, were $14.4 million.  The Company initially utilized the proceeds to pay down a portion of the debt and anticipates utilizing the resulting additional borrowing capacity to accelerate its remaining 2003 exploration and development drilling program in the Piceance and Uintah Basins.

 

The Company’s future cash flow is subject to a number of variables, including the level of production, commodity prices and 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, 2003 and the effect such obligations are expected to have on its 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 facilities		$	—		$	21,242		$	—
Operating leases		397			236			—
Transporation agreements		121			86			—
		$	518		$	21,564		$	—

 

Disclosures Regarding Forward-Looking Statements

 

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 expectations 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 2002 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

 

20

 

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.

 

Item 3.                                QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Interest Rate Risk

 

Because of its debt position, 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, 2003, the Company had $10.7 million of floating rate debt through its facility with Bank of Oklahoma and $10.5 million through its facility with CIBC. The Company also had $7.7 million in cash equivalent instruments that were used to repay borrowings under the Company’s U.S. credit facility in April 2003. In addition, the Company currently has interest rate swap agreements that effectively convert a portion of its variable rate borrowings to fixed rate debt as described in Note 5 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, 2003, from a one percent change in interest rates would be approximately $131,000 before taxes.

 

Foreign Currency Risk

 

The Canadian dollar is the functional currency of Carbon Canada. 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 instruments to manage this risk.

 

Commodity Price Risk

 

Oil and gas commodity markets are influenced by global and regional supply and demand factors.  Worldwide political events can also impact commodity prices.  The prices received by Carbon for its natural gas production are determined mainly by factors affecting North American regional supply and demand for natural gas.  Based upon recent reportable events, it is possible that published indices used to establish the price received by producers for their natural gas production may not be an accurate indication of the market price for natural gas.

 

At March 31, 2003, all of the Company’s United States gas production is in Colorado and Utah.  Since March 2002, natural gas prices for production in these areas have been unusually low relative to the rest of the producing areas in the United States.  Reduced regional seasonal demand and inadequate pipeline transportation capacity linking Carbon’s production in the Piceance and Uintah Basins to consuming regions are principal factors contributing to the large price differentials.  While there is the prospect of additional pipeline capacity out of the region which is expected to help alleviate the high price differentials received by Rocky Mountain gas producers, continued volatility is expected to affect the price received for natural gas produced by Carbon 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 to fluctuations in the price of oil and natural gas by establishing fixed prices or hedges for its oil and natural gas production.  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.  Risks associated with the practice of hedging include counterparty credit risk, Carbon’s inability to deliver required physical volumes of oil and gas which support the Company’s hedges, inefficient or non-correlatable hedges, basis risk, inability to liquidate hedge positions if desired and other unforeseen economic factors.

 

21

 

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

 

Swaps:

 

Carbon USA										Carbon Canada
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)
							(in thousands)										(in thousands)
Gas										Gas
04/01/03-12/31/03		1,085,000		$	3.07		$	(1,316	)	04/01/03-12/31/03		130,000		$	3.15		$	(183	)
Oil										Oil
04/01/03-12/31/03		27,500		$	25.63		$	(42	)	04/01/03-12/31/03		27,500		$	27.38		$	(10	)

 

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

 

Fixed price:							Costless collars:
Carbon Canada							Carbon Canada
Time Period		MMBtu		Weighted Average Fixed Price MMBtu			Time Period		MMBtu		Weighted Average Floor Price MMBtu			Weighted Average Ceiling Price MMBtu
Gas							Gas
04/01/03-12/31/03		753,000		$	3.75		04/01/03-12/31/03		289,000		$	3.95		$	5.12
							01/01/04-04/30/04		115,000		3.95			5.78

 

Item 4.                                CONTROLS AND PROCEDURES

 

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

 

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PART II—OTHER INFORMATION

 

Item 1-5		Not applicable.
Item 6		(a)	Exhibits
		10.1	First Amendment of Amended and Restated Credit Agreement dated as of March 24, 2003 between Carbon Energy Corporation (USA) and Bank of Oklahoma, National Association *
		10.2	Credit Agreement dated as of May 14, 2003 between Carbon Energy Canada Corporation and Canadian Imperial Bank of Commerce. *
		99.1	Certification of 10-Q Report, dated May 15, 2003, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*
		(b)	Reports on Form 8-K
			(i)                     A report on Form 8-K, filed with the Securities and Exchange commission on April 1, 2003, regarding the March 31, 2003 announcement of an Agreement and Plan of Reorganization between Carbon Energy Corporation, Evergreen Resources, Inc. and Evergreen Merger Corporation.
			(ii)                  A report on Form 8-K, filed with the Securities and Exchange Commission on April 8, 2003, regarding the March 24, 2003 sale of the Company’s interests in oil and gas properties located primarily in the Permian Basin of southeast New Mexico.

 

* Filed herewith

 

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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, 2003	By:	/s/ Patrick R. McDonald
		President and Chief Executive Officer
Date:  May 15, 2003	By:	/s/ Kevin D. Struzeski
		Treasurer and Chief Financial Officer

 

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CERTIFICATION

 

I, Patrick R. McDonald certify that:

 

1.                                       I have reviewed this quarterly report on Form 10-Q of Carbon Energy Corporation;

 

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

 

3.                                       Based on my knowledge, the financial statements and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

 

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

 

(a)                                    designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

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

(c)                                  presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

 

5.                                       The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

 

(a)                                  all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

(b)                                 any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

 

6.                                       The registrant’s other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

Date:	May 15, 2003
	By:	/s/  Patrick R. McDonald
		Patrick R. McDonald
		President and Chief Executive Officer

 

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CERTIFICATION

 

I, Kevin D. Struzeski certify that:

 

1.                                       I have reviewed this quarterly report on Form 10-Q of Carbon Energy Corporation;

 

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

 

3.                                       Based on my knowledge, the financial statements and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

 

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

 

(a)                                  designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

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

(c)                                    presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

 

5.                                       The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

 

(a)                                    all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

(b)                                   any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

 

6.                                       The registrant’s other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

Date:	May 15, 2003
	By:	/s/  Kevin D. Struzeski
		Kevin D. Struzeski
		Chief Financial Officer

 

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EXHIBIT INDEX

 

Exhibit Number		Description of Exhibit
10.1		First Amendment of Amended and Restated Credit Agreement
10.2		Credit Agreement
99.1		Certification of 10-Q Report

 

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