EVERGREEN RESOURCES INC - 10-Q Quarterly Report

EVERGREEN RESOURCES, INC.
(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. ý Yes o No

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

As of October 28, 2003, 39,239,830 shares of the Registrant's Common Stock, no par value, were outstanding.


PART I. FINANCIAL INFORMATION
Item 1.		Financial Statements
		Consolidated Balance Sheets as of September 30, 2003 and December 31, 2002
		Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2003 and 2002
		Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2003 and 2002
		Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2003 and 2002
		Notes to Consolidated Financial Statements
Item 2.		Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3.		Quantitative and Qualitative Disclosure About Market Risk
Item 4.		Controls and Procedures
PART II. OTHER INFORMATION
Item 1.		Legal Proceedings
Item 2.		Changes in Securities and Use of Proceeds
Item 3.		Defaults Upon Senior Securities
Item 4.		Submission of Matters to a Vote of Security Holders
Item 5.		Other Information
Item 6.		Exhibits and Reports on Form 8-K

EVERGREEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)

EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of September 30, 2003
(Unaudited)

Evergreen Resources, Inc. ("Evergreen" or "the Company") is a Colorado corporation organized on January 14, 1981. Evergreen is an independent energy company engaged in the operation, development, production, exploration and acquisition of unconventional natural gas properties. Evergreen is one of the leading developers of coal bed methane reserves in the United States. Its current operations are principally focused on developing and expanding its coal bed methane project located in the Raton Basin in southern Colorado. Evergreen has initiated coal bed methane projects in Alaska's Cook Inlet-Susitna Basin and in the Forest City Basin of eastern Kansas. Effective October 29, 2003, Evergreen completed its acquisition of Carbon Energy Corporation ("Carbon"). Carbon's properties are located in the Piceance Basin of western Colorado, the Uintah Basin of eastern Utah, and the Western Sedimentary Basin of Canada (see Note 3).

All common stock and per-share amounts reported in the consolidated financial statements, and notes thereto, reflect the two-for-one split of Evergreen common stock effective September 16, 2003.

The financial statements include the accounts of Evergreen and its wholly-owned subsidiaries, Evergreen Operating Corporation, Evergreen Resources (UK) Ltd. ("ERUK"), Powerbridge, Inc., Evergreen Well Service Company, Primero Gas Marketing Company, Primero Gas Company, LLC, XYZ Minerals, Inc. (see Note 5), Evergreen Resources (Alaska) Corporation and Evergreen Supply and Distribution Company. The financial statements also include the accounts of Evergreen's majority owned subsidiaries consisting of an 85% ownership interest in Lorencito Gas Gathering, LLC and an approximate 75% ownership interest in Long Canyon Gas Company, LLC (see Note 5). All significant intercompany balances and transactions have been eliminated in consolidation.

ERUK also has a 40% ownership in Argos Evergreen Limited, a Falkland Islands company, which owns offshore drilling rights in the North Falklands Basin. This investment is accounted for by the equity method of accounting. The Company has no interests in any other unconsolidated entities, nor does it have any off-balance sheet financing arrangements (other than operating leases) or any unconsolidated special purpose entities.

The accompanying financial statements should be read in conjunction with the Company's audited consolidated financial statements for the year ended December 31, 2002. In the opinion of management, the accompanying unaudited financial statements include all adjustments, consisting only of normal recurring items, necessary to present fairly the Company's financial position as of September 30, 2003 and 2002 and the results of its operations and statements of comprehensive income for the three and nine months then ended and the cash flows for the nine months then ended. Certain reclassifications have been made to prior periods to conform to the classifications used in the current period. These reclassifications did not have an impact on previously reported results of operations. The results of operations for interim periods are not necessarily indicative of results to be expected for a full year.

The Company follows the full-cost method of accounting for oil and gas properties. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, and include salaries, benefits and other internal costs directly attributable to these activities. For the nine months ended September 30, 2003 and 2002, Evergreen capitalized $7.2 million and $4.6 million of internal costs. Of these amounts, approximately $4.6 million and $3.0 million were salary-related costs directly related to services provided by the Company's wholly-owned well service company and for gas gathering construction activities. The majority of the remaining capitalized costs were primarily attributable to certain engineering and land employees' salaries and benefits. Costs associated with production and general corporate activities are expensed in the period incurred. Interest costs related to unproved properties and properties under development are also capitalized to oil and gas properties. Approximately $0.8 million and $1.1 million of interest was capitalized during the nine months ended September 30, 2003 and 2002, respectively.

If the net investment in oil and gas properties exceeds an amount equal to the sum of (1) the standardized measure of discounted future net cash flows from proved reserves and (2) the lower of cost or fair market value of properties in process of development and unexplored acreage, the excess is charged to expense as additional depletion. Normal dispositions of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized.

Depletion of proved oil and gas properties is computed on the units-of-production method based upon estimates of proved reserves with oil and gas being converted to a common unit of measure based on the relative energy content. Unproved oil and gas properties, including any related capitalized interest expense, are not amortized, but are assessed for impairment either individually or on an aggregated basis.

Gas collection and support equipment are stated at cost. Depreciation and amortization for the Raton Basin gas collection system, with the exception of the gas compressor facilities, is computed on the units-of-production method based on total reserves of the field. Gas compressor facilities and support equipment are depreciated using the straight-line method over the estimated useful lives of the assets of three to 30 years.

On October 29, 2003, Evergreen completed its acquisition of 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. Carbon's areas of operations in the United States are the Piceance Basin in Colorado and the Uintah Basin in Utah. Carbon's areas of operations in Canada are south-central Alberta and southeast Saskatchewan.

Under the terms of the merger agreement, Carbon's shareholders received 0.55 shares of Evergreen common stock for each common share of Carbon. As a result, Evergreen issued approximately 3.5 million new shares of Evergreen common stock to Carbon's shareholders. The aggregate value of the transaction, including transaction costs and the fair value of Carbon employee stock options assumed by Evergreen is approximately $89 million. The net assets acquired include the assumption of Carbon's debt of approximately $20 million.

developed and the remaining amounts are classified as proved undeveloped. Independent petroleum engineering consultants Netherland Sewell & Associates, Inc. prepared the reserve estimates of Carbon. Average daily net production in the United States and Canada is 16.8 million cubic feet of gas equivalent. The gross acreage position is approximately 150,000 acres in the United States and 130,000 acres in Canada.

As reported in the Company's June 30, 2003 Form 10-Q, subsequent to the execution of the Carbon merger agreement and before the close of the transaction, Evergreen had received indications of interest from several oil and gas companies about the purchase from Evergreen of Carbon's U.S. assets (the Piceance Basin and Uintah Basin assets). Evergreen has decided not to pursue the sale of the U.S. assets and currently intends to develop these properties. The Company has allocated a portion of its 2004 capital budget for the development of Carbon's U.S. properties.

Through September 2003, the Company has acquired approximately 675,000 acres of prospective unconventional natural gas properties in the Forest City Basin of eastern Kansas. The Company has invested approximately $35.1 million in these properties since the beginning of 2003 (including 497,076 shares of Evergreen common stock issued in April 2003 valued at $12.4 million). Evergreen plans to drill a total of 40 wells in the Forest City Basin during the fourth quarter of 2003. This total consists of seven four-well CBM pilot projects (with an additional water injection well for each pilot), plus five stratigraphic core wells that will be drilled in various parts of the Company's acreage. As of October 29, 2003, Evergreen had drilled ten CBM wells on these properties. The wells were drilled to total depths ranging from 882 feet to 1,000 feet. Evergreen plans to begin fracture stimulation operations using its own well service crews and equipment in early November 2003.

On March 26, 2003, Evergreen entered into a settlement agreement with certain working interest owners, under which Evergreen agreed to sell certain mineral interests held by XYZ Minerals, Inc. and an approximate 25% membership interest in Long Canyon Gas Company, LLC for $3.75 million. On April 16, 2003, the transaction closed with an effective date of January 1, 2003. Net revenues of approximately $0.7 million from the effective date through the closing date were recorded as a sales price adjustment in the second quarter of 2003.

The following table sets forth the computation of basic and diluted weighted average shares outstanding for the three and nine months ended September 30, 2003 and 2002. Stock options and warrants were not included in the calculation of diluted loss per share for the three and nine months ending September 30, 2002 as their inclusion would have an antidilutive effect. The table gives effect to

the two-for-one split of Evergreen's common stock effective September 16, 2003 for all periods presented.

		Three Months Ended September 30,		Nine Months Ended September 30,
		2003	2002	2003	2002
		(in thousands)
Weighted average common shares outstanding:
	Basic	39,112	37,960	38,664	37,872
	Dilutive common stock options and unvested restricted stock grants	1,217	—	1,306	—

	Diluted	40,329	37,960	39,970	37,872

As discussed in Note 9, the Company issued $100 million in senior convertible notes in December 2001 that are convertible into shares of common stock under certain circumstances. At September 30, 2003 and 2002, no potential common shares were included in the computation of diluted earnings per share related to these senior convertible notes as no circumstances occurred that would allow conversion of the notes.

The Company issued 1,121,252 shares of common stock during the nine months ended September 30, 2003 which included the issuance of 497,076 common shares for unconventional natural gas properties in the Forest City Basin of eastern Kansas (see Note 4) and 978 shares for other property interests, the issuance of 39,864 common shares as employee compensation and the issuance of 583,334 common shares in conjunction with the exercise of stock purchase options.

The Company has recently proposed to amend its articles of incorporation to increase the number of authorized shares of common stock from 50 million shares to 100 million shares. The proposal is subject to shareholder approval at a special meeting of shareholders to be held on November 20, 2003.

The Company sometimes enters into fixed-price physical delivery contracts and commodity derivative contracts to manage price risk with regard to a portion of its natural gas production. The Company's commodity derivative contracts are generally designated as cash flow hedges. To qualify as a cash flow hedge, the derivative contract must be designated as a cash flow hedge and the change in its fair value must correlate with the change in the price of anticipated future production such that the Company's exposure to the effect of commodity price change is reduced.

At September 30, 2003, the Company had the following open derivative contracts to manage price risk on a portion of its natural gas production. ("MMBtu" means million British thermal units and

converts on an approximate one-for-one basis into Mcf.) The contracts are based on the regional price indexes where the Company physically delivers its natural gas.

Remaining Contract Period	Type of Instrument(s)	Volume in MMBtu/day	Weighted Average $/ MMBtu		Unrealized Gain (Loss) at September 30, 2003
					(in thousands)
Oct 03 - Dec 03	Swaps	70,000	$	4.37	$	20
Oct 03 - Dec 03	Costless Collar	20,000	$	3.26/5.02		(238	)
Jan 04 - Dec 04	Swap	10,000	$	3.75		(2,889	)
Jan 04 - Dec 04	Costless Collar	20,000	$	3.21/4.91		(2,779	)

					$	(5,886	)

As of September 30, 2003, the Company had recorded net unrealized losses of approximately $5.9 million on the derivative instruments reflected in the above table, which represented the estimated aggregate fair values of the derivative contracts as of that date. These unrealized losses are presented on the Consolidated Balance Sheet as a current asset of $0.6 million (which is included in "Other current assets"), a liability of $5.0 million and a non-current liability of $1.5 million (which is included in "Production taxes payable and other"). The fair values of the costless collar contracts were calculated using the Black-Scholes option-pricing model, which factors in such variables as the term of the derivative contracts, the volatility of the gas market and the current risk-free rates of return on similar-termed investments. The values of the natural gas swaps were determined using expected discounted future cash flows. Based on the calculated fair values at September 30, 2003, the Company expects to reclassify net losses of $4.4 million into earnings related to these derivative contracts during the next 12 months. Actual gains or losses recognized may be materially different than what was estimated at September 30, 2003 and will depend solely on the regional price indexes of the commodities on the specified settlement dates provided by the derivative contracts.

During the three and nine months ended September 30, 2003, the Company recognized approximately $1.3 million and $16.2 million in hedging losses, respectively, related to natural gas derivative contracts designated as cash flow hedges. The losses are included in natural gas revenues in the Consolidated Statements of Operations for each period presented.

In addition to the derivative instruments reflected in the above table, the Company entered into several derivative instruments in the second quarter of 2003 in order to hedge several forecasted transactions associated with the anticipated acquisition of Carbon. The Company recognized a $0.3 million and $1.1 million loss on these derivative instruments during the three and nine months ended September 30, 2003, respectively, related to the change in the fair market value of these instruments. The losses are included in other expense in the Consolidated Statements of Operations for each period presented. The cash payments for these instruments are included in "Change in other assets" in Investing Activities in the Consolidated Statements of Cash Flows. At September 30, 2003 the estimated net fair value of these instruments was a $0.5 million net liability, which is presented on the Consolidated Balance Sheet as a current liability of $0.6 million and a current asset of $0.1 million (which is included in "Other current assets").

The Company also had an interest rate swap in place from April 2001 through April 2002 for a notional amount of $25 million at a LIBO rate of 4.4%. The Company recognized a $0.2 million loss on this contract during the nine months ended September 30, 2002, which is included in interest expense in the Consolidated Statements of Operations for the respective periods.

The Company is exposed to credit risk in the event of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate nonperformance by the counterparties.

Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based Compensation," as amended by SFAS No. 148, "Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment to SFAS No. 123" requires the Company to provide pro forma information regarding net income as if the compensation cost for the Company's stock option plans had been determined in accordance with the fair value based method prescribed in SFAS No. 123. To provide the required pro forma information, the Company estimates the fair value of each stock option at the grant date by using the Black-Scholes option-pricing model. The following table represents the pro forma effect on net income (loss) and income (loss) per share as if the Company had applied the fair value based method and recognition provisions of SFAS No. 123 to stock-based employee compensation:

		Three Months Ended September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
		(in thousands, except per share data)
Net income (loss), as reported		$	19,624		$	(14,996	)	$	54,980		$	(9,322	)
	Add: Stock-based employee compensation included in reported net income (loss), net of tax		249			8			423			44
	Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax		(655	)		(372	)		(1,641	)		(1,137	)

	Pro forma net income (loss)	$	19,218		$	(15,360	)	$	53,762		$	(10,415	)

Income (loss) per share:
Basic income (loss) per common share:
	As reported	$	0.50		$	(0.40	)	$	1.42		$	(0.25	)

	Pro forma	$	0.49		$	(0.40	)	$	1.39		$	(0.28	)

Diluted income (loss) per common share:
	As reported	$	0.49		$	(0.40	)	$	1.38		$	(0.25	)

	Pro forma	$	0.48		$	(0.40	)	$	1.35		$	(0.28	)

Under the Company's 2000 Stock Incentive Plan, shares of common stock may be granted to key employees and directors under terms and conditions determined by management. These stock grants vest over a period of three to six years and are distributed to the employees and directors as the shares vest. The Company determines employee and director compensation based on the market price of its common stock on the date of grant. Unearned compensation arising from the stock grants is shown as a reduction in stockholders' equity on the consolidated balance sheets and is amortized using the straight-line method as additional compensation over the vesting period. During the nine months ended September 30, 2003, the Company granted 296,300 shares of common stock to certain employees and directors that vest over three to six years. These shares were valued at approximately $6.8 million at the grant dates (representing a weighted average fair value of $22.92 per share) and recorded as deferred compensation in stockholders' equity. During the nine months ended September 30, 2003, the Company amortized deferred compensation of $1.2 million for all stock grants, including those granted during the year ended December 31, 2002.

The Company applies Accounting Principles Board Opinion 25, "Accounting for Stock Issued to Employees," and related interpretations in accounting for all stock option plans. No stock-based compensation cost has been recognized in operations for stock options granted because the option exercise price was equal to or more than the market price of the underlying common stock on the date of grant.

The Company currently has a $200 million revolving credit facility with a bank group (the "Banks"). The credit facility is available through July 1, 2005. Advances pursuant to this credit facility are limited to a borrowing base, which is presently $200 million. The Company may elect to use either the LIBO rate plus a margin of 1.125% to 1.50% or the prime rate plus a margin of 0% to 0.25%, with margins on both rates determined on the average outstanding borrowings under the credit facility. The borrowing base is redetermined semi-annually by the Banks based upon reserve evaluations of Evergreen's oil and gas properties. An average annual commitment fee of 0.375% is charged quarterly for any unused portion of the credit line. The agreement is collateralized by substantially all domestic oil and gas properties and guaranteed by substantially all of the Company's subsidiaries. The credit agreement also contains certain net worth, leverage and ratio requirements. At September 30, 2003, Evergreen had $131.5 million of outstanding borrowings under this credit facility, with a current average interest rate of approximately 2.6%. The Company was in compliance with all loan covenants at September 30, 2003.

The Company has $100 million outstanding in senior unsecured convertible notes which are due in 2021 and bear interest at a fixed annual rate of 4.75%, which is to be paid in cash on June 15 and December 15 of each year. In addition to the fixed interest, the Company will pay contingent interest to the holders of the notes if the average trading price of the notes for an established number of days equals 120% or more of the principal amount of the notes. The rate of contingent interest payable in respect to any six-month period will equal the greater of (1) a per annum rate equal to 5% of the Company's estimated per annum borrowing rate for senior non-convertible fixed-rate debt with a maturity date comparable to the notes or (2) 0.30% per annum. In no event may the contingent interest rate exceed 0.40% per annum. The Company will be required to pay contingent interest of approximately $0.2 million, at 0.30% per annum, on December 15, 2003.

The notes are general unsecured obligations, ranking on a parity in right of payment with all of Evergreen's existing and future senior indebtedness, and senior in right of payment with all of Evergreen's future subordinated indebtedness. The notes are due on December 15, 2021 but are redeemable at either the Company's option or the holder's option on other specified dates. The Company may redeem the notes at its option in whole or in part beginning on December 20, 2006, at 100% of their principal amount plus accrued and unpaid interest (including contingent interest). Holders of the notes may require the Company to repurchase the notes if a change in control of the Company occurs. Holders may also require the Company to repurchase all or part of the notes on December 20, 2006, December 15, 2011 and December 15, 2016 at a repurchase price of 100% of the principal amount of the notes plus accrued and unpaid interest (including contingent interest). On December 20, 2006, the Company may pay the repurchase price in cash, in shares of common stock, or in any combination of cash and common stock. On December 15, 2011 and December 15, 2016, the Company must pay the repurchase price in cash.

The notes are convertible into shares of common stock of Evergreen under certain circumstances as discussed below at a conversion price of $25 per share, subject to certain adjustments. The notes can be converted at the option of the holder if for a specified period of time, the closing price of the Company's common stock exceeds 110% of the conversion price or if the average trading price of the notes for a specified period of time is less than 105% of an average conversion value as defined by the indenture governing the notes. The notes may also be converted into shares of common stock of the Company at the election of the holder upon notice of redemption, or at any time the notes are rated by either Moody's Investors Service, Inc. or Standard & Poor's Rating Group and the credit rating initially assigned to the notes by either such rating agency is reduced by two or more ratings levels, or upon the occurrence of certain corporate transactions including a change in control or the distribution to current holders of the Company's common stock certain purchase rights or any other asset that has a value exceeding 10% of the sale price of the common stock on the day preceding the declaration date of the distribution of such assets. At September 30, 2003 and 2002, no potential common shares were included in the computation of diluted earnings per share related to these senior convertible notes as no circumstances occurred that would allow conversion of the notes.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
	(in thousands)
Gain on sale of investment in common stock of affiliated company	$	(1,989	)	$	—		$	(1,989	)	$	—
Gain on sale of investment in common stock of unaffiliated company		(371	)					(1,321	)
Foreign currency gain		—			—			(996	)		—
Loss on derivative instruments		256			—			1,096			—
Minority interest in subsidiaries' income (loss)		480			(6	)		962			(13	)
Other		431			292			688			521

Total other (income) expense	$	(1,193	)	$	286		$	(1,560	)	$	508

Cash paid during the nine months ended September 30, 2003 and 2002 for interest was approximately $5.6 million and $4.9 million.

Effective January 1, 2003, the Company adopted Financial Accounting Standards Board ("FASB") SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires the fair value of a liability for an asset retirement obligation to 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 adoption of this Statement required the Company to record a non-cash expense, net of tax, of approximately $0.7 million as a cumulative effect of change in accounting principle in the first quarter of 2003. In addition, the Company recorded a non-current liability of approximately $4.6 million and an addition to oil and gas properties and the gas collection system of approximately $3.9 million in connection with the adoption of this Statement effective January 1, 2003.

The schedule below is a reconciliation of the Company's liability for the nine months ended September 30, 2003:

	Asset Retirement Obligation
	(in thousands)
Upon adoption at January 1, 2003	$	4,631
Liabilities incurred		612
Liabilities settled		—
Accretion		251
Revisions to estimate		—

	$	5,494

The schedule below reflects, on a pro forma basis, the net loss and loss per share amounts as if SFAS No. 143 had been applied during each period presented. The asset retirement obligation as of September 30, 2002 would have equaled approximately $4.4 million had SFAS No. 143 been adopted during 2002.

	Three Months Ended September 30, 2002			Nine Months Ended September 30, 2002
	(in thousands, except per share data)
Net loss, as reported	$	(14,996	)	$	(9,322	)
Pro forma adjustments, net of tax		(63	)		(188	)

Net loss, pro forma	$	(15,059	)	$	(9,510	)

Basic loss per common share, as reported	$	(0.40	)	$	(0.25	)

Basic loss per common share, pro forma	$	(0.40	)	$	(0.25	)

Diluted loss per common share, as reported	$	(0.40	)	$	(0.25	)

Diluted loss per common share, pro forma	$	(0.40	)	$	(0.25	)

On February 9, 2001, Evergreen completed a transaction with KFx Inc. ("KFx"), a provider of technology and service solutions to the electric power generation industry, under which KFx sold to Evergreen a portion of its convertible preferred stock investment in its subsidiary, Pegasus Technologies, Inc. ("Pegasus"), representing an approximate 8.8% as converted interest in Pegasus, for $1.5 million. On May 1, 2002, KFx repurchased the convertible preferred stock from the Company for $2.0 million plus accrued interest. The Company recognized the $0.5 million difference between the $1.5 million purchase price of the convertible preferred stock and the sales price of $2.0 million redemption price ratably as interest income from February 2001 to February 2002.

In connection with the purchase of the convertible preferred stock on February 9, 2001, Evergreen was provided with a five-year warrant to purchase one million shares of KFx common stock at $3.65 per share, subject to certain adjustments, which included a reduction in the warrant price to $2.25 per share upon KFx's retirement of certain outstanding debentures. These debentures were retired in full by KFx in July of 2002; accordingly, the warrant exercise price was reduced to $2.25 per share.

During the third quarter of 2003, Evergreen exercised warrants to purchase 750,000 shares of KFx common stock at $2.25 per share and subsequently sold the 750,000 shares at an average price of $4.90 per share. The resulting gain of approximately $2.0 million is included in other (income) expense in the

Consolidated Statements of Operations for the three and nine months ended September 30, 2003. During October 2003, the Company exercised the remaining 250,000 options and subsequently sold the 250,000 shares, resulting in a net gain of approximately $0.6 million.

In June 2001, the FASB issued SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 addresses accounting and reporting for business combinations and is effective for all business combinations initiated after June 30, 2001. SFAS No. 142 addresses the accounting and reporting for goodwill subsequent to acquisition and other intangible assets. The new standard eliminates the requirement to amortize acquired goodwill; instead, such goodwill is required to be reviewed at least annually for impairment. The new standard also requires that, at a minimum, all intangible assets be aggregated and presented as a separate line item in the balance sheet. The adoption of SFAS No. 141 and SFAS No. 142 had no impact on Evergreen's financial position or results of operations.

A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141 and SFAS No. 142 to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights held under lease or other contractual arrangement associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, Evergreen has included the costs of such mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights held under lease or other contractual arrangement associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, Evergreen would be required to reclassify approximately $41.2 million at September 30, 2003 and $6.5 million at December 31, 2002 out of oil and gas properties and into a separate intangible assets line item. Evergreen's cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full-cost accounting rules.

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires the fair value of a liability for an asset retirement obligation to 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. SFAS No. 143 was effective for the Company on January 1, 2003. The adoption of this statement required the Company to record a non-cash expense, net of tax, of approximately $0.7 million as a cumulative effect of change in accounting principle in the first quarter of 2003. In addition, the Company recorded a non-current liability of approximately $4.6 million and an addition to oil and gas properties and the gas collection system of approximately $3.9 million in connection with the adoption of this statement effective January 1, 2003.

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB No. 4, 44 and 64, Amendment of FASB No. 13, and Technical Corrections." SFAS No. 145 rescinds FASB No. 4 "Reporting Gains and Losses from Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." This statement also rescinds SFAS No. 44 "Accounting for Intangible Assets of Motor Carriers" and amends SFAS No. 13, "Accounting for Leases." This statement also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. The Company adopted this statement on January 1, 2003. The adoption of this statement did not have a material effect on the Company's financial statements.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 addresses accounting and reporting for costs associated with exit or

disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (Including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized and measured initially at fair value when the liability is incurred. SFAS No. 146 was effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of this statement did not have a material effect on the Company's financial statements.

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

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

This Quarterly Report on Form 10-Q may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), including statements regarding, among other items, (i) the Company's growth strategies, (ii) anticipated trends in the Company's business and its future results of operations, (iii) market conditions in the oil and gas industry, (iv) the ability of the Company to make and integrate acquisitions and (v) the impact of government regulation. These forward-looking statements are based largely on the Company's expectations and are subject to a number of risks and uncertainties, many of which are beyond the Company's control. Actual results could differ materially from those implied by these forward-looking statements as a result of, among other things, a decline in natural gas production, a decline in natural gas prices, incorrect estimations of required capital expenditures, increases in the cost of drilling and completion and gas collection, an increase in the cost of production and operations, an inability to meet growth projections, or changes in general economic conditions. These and other risks and uncertainties are described in more detail in the Company's most recent Annual Report on Form 10-K filed with the Securities and Exchange Commission. In light of these and other risks and uncertainties of which the Company may be unaware or which the Company currently deems immaterial, there can be no assurance that actual results will be as projected in the forward- looking statements.

The Company drilled 145 coal bed methane wells in the Raton Basin from the beginning of the year through October 28, 2003. The Company plans to drill a total of 160 wells in the Raton Basin in 2003. Average net daily sales from the Raton Basin for the month of October 2003 were approximately 130.1 million cubic feet per day.

Evergreen completed the acquisition of Carbon Energy Corporation effective October 29, 2003. 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. Carbon's areas of operations in the United States are the Piceance Basin in Colorado and the Uintah Basin in Utah. Carbon's areas of operations in Canada are south-central Alberta and southeast Saskatchewan.

aggregate value of the transaction, including transaction costs and the fair value of Carbon employee stock options assumed by Evergreen is approximately $89 million. The net assets acquired include the assumption of Carbon's debt of approximately $20 million.

The acquired Carbon properties are estimated to contain at least 97 billion cubic feet equivalent ("Bcfe") of proved reserves, substantially all of which are natural gas. Carbon operates substantially all of its properties in the United States and Canada. Net gas reserves in the United States and Canada are approximately 59 Bcfe and 38 Bcfe, respectively, of which 45% and 73% are classified as proved developed and the remaining amounts are classified as proved undeveloped. Independent petroleum engineering consultants Netherland Sewell & Associates, Inc. prepared the reserve estimates of Carbon. Average daily net production in the United States and Canada is 16.8 million cubic feet of gas equivalent. The gross acreage position is approximately 150,000 acres in the United States and 130,000 acres in Canada.

In mid-September, Evergreen acquired a 100% working interest in an additional 113,000 acres of prospective coal bed methane (CBM) acreage in the Forest City Basin of eastern Kansas. With the acquisition, along with several smaller property transactions, Evergreen holds a 100% working interest in approximately 675,000 acres in eastern Kansas. The acquired properties, located primarily in Atchison County, Kansas, include a 12-well pilot project with a gas gathering system and associated production equipment.

Evergreen plans to drill a total of 40 wells in the Forest City Basin during the fourth quarter. This total consists of seven four-well CBM pilot projects (with an additional water injection well for each pilot), plus five stratigraphic core wells that will be drilled in various parts of the Company's acreage. As of October 29, 2003, Evergreen had drilled ten CBM wells on these properties. The wells were drilled to total depths ranging from 882 feet to 1,000 feet. Evergreen plans to begin fracture stimulation operations using its own well service crews and equipment in early November 2003.

Early in the second quarter of 2003, Evergreen completed five of its eight coal bed methane wells on the Pioneer Unit in Alaska's Cook Inlet Basin. The initial production results indicate that the wells in the first two pilot projects are probably not capable of commercial production. In September, the Company acquired the rights to an additional 230,000 acres of prospective CBM acreage in south-central Alaska. With the new properties, Evergreen's total leased acreage in south-central Alaska is more than 300,000 acres. The licenses for this new acreage were applied for more than three years ago. The majority of the new acreage is located immediately to the northwest of the Pioneer Unit, extending about 25 miles up the Susitna River Valley.

All common stock and per-share amounts reported in the consolidated financial statements, and notes thereto, reflect the two-for-one split of Evergreen common stock effective September 16, 2003.

Results of Operations—Three and Nine Months Ended September 30, 2003 Compared to the Three and Nine Months Ended September 30, 2002

The following table sets forth certain operating data of the Company for the periods presented ("Mcf" means thousand cubic feet, "MMcf" means million cubic feet and "Bcf" means billion cubic feet):

		Three Months Ended September 30,				Nine Months Ended September 30,
		2003		2002		2003		2002
Natural gas production (Bcf)			11.750		10.192		33.440		28.518
Average realized sales price per Mcf *		$	4.55	$	2.89	$	4.65	$	2.56
Cost per Mcf:
	Lease operating expenses	$	0.40	$	0.42	$	0.44	$	0.42
	Transportation costs	$	0.31	$	0.31	$	0.32	$	0.32
	Production and property taxes	$	0.20	$	0.13	$	0.25	$	0.14
	Depreciation, depletion and amortization	$	0.55	$	0.54	$	0.54	$	0.54
	General and administrative	$	0.32	$	0.21	$	0.29	$	0.24
	Interest expense	$	0.17	$	0.21	$	0.19	$	0.21

The Company recorded net income of $19.6 million or $0.49 per diluted share for the three months ended September 30, 2003, compared to a net loss of $15.0 million or $0.40 per diluted share for the same period in 2002. For the nine months ended September 30, 2003, the Company recorded net income of $55.0 million or $1.38 per diluted share compared to a net loss of $9.3 million or $0.25 per diluted share in 2002. The increase in net income during the three and nine months ended September 30, 2003, as compared to the prior year periods, was due primarily to increases in the average realized natural gas price and production as discussed below and the $22.0 million asset impairment charge, net of tax, taken in the third quarter of 2002.

Natural gas revenues increased to $53.5 million during the three months ended September 30, 2003, from $29.5 million for the same period in the prior year. During the nine months ended September 30, 2003, natural gas revenues increased to $155.5 million from $73.0 million for the same period in the prior year. The increases in natural gas revenues for the three and nine month periods ended September 30, 2003 compared to the same periods in 2002 were due to a 57% and 82% increase in the average realized natural gas price to $4.55 and $4.65 per Mcf in 2003 from $2.89 and $2.56 per Mcf in 2002. Approximately 72% of Evergreen's net production during the third quarter of 2003 was hedged using financial instruments. The Company realized $1.3 million and $16.2 million in net losses related to its financial hedges during the three and nine months ended September 30, 2003. The Company recorded a non-cash unrealized loss of $0.6 million in the third quarter of 2002 and a $6.6 million net loss related to its natural gas hedging activities during the nine months ended September 30, 2002.

Net gas production for the three and nine months ended September 30, 2003 increased to 11.8 Bcf and 33.4 Bcf or an average of 127.7 and 122.5 MMcf per day, from 10.2 Bcf and 28.5 Bcf or an average of 110.8 MMcf and 104.5 MMcf per day for the comparable periods in 2002.

Evergreen had 953 net producing gas wells at September 30, 2003 compared to 802 at September 30, 2002. Evergreen drilled 136 coal bed methane wells in the Raton Basin during the first nine months of this year compared to 143 coal bed methane wells in the first nine months of 2002.

Lease operating expenses for the three months ended September 30, 2003 were $4.7 million compared to $4.3 million in last year's third quarter. On a per-Mcf basis, lease operating expenses

declined 5% from the prior-year period to $0.40 per Mcf from $0.42 per Mcf. During the nine months ended September 30, 2003, lease operating expenses were $14.7 million or $0.44 per Mcf as compared to $12.0 million or $0.42 per Mcf for the same period in the prior year. At June 30, 2003, the company had projected higher operating costs through 2003, including third quarter estimated costs of $0.50 to $0.52 per Mcf. The anticipated increase was primarily due to an expected increase in well repairs, field supplies and compressor maintenance as a result of an increasing number of older wells and surface systems. The lower than expected lease operating costs in the third quarter of 2003 were partially due to improved operating efficiencies during the third quarter and to the rescheduling of certain maintenance projects from the third quarter to the fourth quarter. Lease operating costs for the fourth quarter are currently estimated to be between $0.46 and $0.48 per Mcf in the Raton Basin. With the addition of the Carbon properties, consolidated lease operating expenses are estimated to be $0.49 to $0.51 per Mcf in the fourth quarter.

Transportation costs remained unchanged at $0.31 per Mcf for three months ended September 30, 2003 and 2002 and at $0.32 per Mcf for the nine months ended September 30, 2003 and 2002.

Production and property taxes for the three and nine months ended September 30, 2003 were $2.3 million and $8.3 million compared to $1.3 million and $3.9 million during the three and nine months ended September 30, 2002. The increases in production and property taxes were primarily due to higher natural gas revenues.

Depreciation, depletion and amortization expense for the three months ended September 30, 2003 was $6.5 million compared to $5.5 million for the same period in 2002. On an equivalent Mcf basis, depreciation, depletion and amortization expense was $0.55 per Mcf for the three months ended September 30, 2003 as compared to $0.54 per Mcf for the same period in the prior year. During the nine months ended September 30, 2003, depreciation, depletion and amortization expense was $18.2 million or $0.54 per Mcf as compared to $15.5 million or $0.54 per Mcf for the same period in the prior year. With the addition of the Carbon properties, depreciation, depletion and amortization is expected to increase to $0.68 to $0.69 per Mcf in the fourth quarter of 2003.

In September 2002, the Company recorded an impairment of approximately $34.2 million of certain international oil and gas properties. Of this amount, approximately $15.9 was related to the coal bed methane project in the United Kingdom, $13.6 million was related to wells drilled in Northern Ireland and the Republic of Ireland and $4.7 million was related to undeveloped acreage held in the Falkland Islands and Chile. The impairment charges of $2.5 million for the nine months ended September 30, 2003 relate to plugging and abandonment operations done for the United Kingdom and Ireland properties, which have been substantially completed as of September 30, 2003.

General and administrative expenses were $3.8 million during the three months ended September 30, 2003, as compared to $2.1 million during the same period in 2002. The $1.7 million increase was primarily attributable to a $1.2 million increase in general and administrative salaries and $0.2 million increase in professional services. For the nine months ended September 30, 2003, general and administrative expenses were $9.6 million as compared to $6.7 million for the same period in the prior year. The $2.9 million increase in general and administrative expense was primarily attributable to a $2.1 million increase in general and administrative salaries and a $0.4 million increase in professional services.

Interest expense was $2.0 million and $2.2 million for the three months ended September 30, 2003 and 2002. During the nine months ended September 30, 2003, interest expense was $6.3 million compared to $6.1 million in the nine months of the prior year. Although average debt balances were higher in each period of 2003 compared to 2002, interest expense remained relatively consistent due to a reduction in average interest rates from approximately 4.5% during the first nine months of 2002 to 4.1% during the first nine months of 2003.

Other income of $1.2 million and $1.6 million for the three and nine months ended September 30, 2003 includes realized gains on the sale of common stock held in other companies which were partially offset by losses on derivative instruments and minority interest expense, which was primarily related to an approximate 25% minority ownership interest in Long Canyon Gas Company, LLC. See Note 10 to the Consolidated Financial Statements for a table of the components of other (income) expense for the three and nine months ended September 30, 2003 and 2002.

Effective January 1, 2003, the Company adopted Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires the fair value of a liability for an asset retirement obligation to 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 adoption of this Statement required the Company to record a non-cash expense, net of tax, of approximately $0.7 million as a cumulative effect of change in accounting principle in the first quarter of 2003. In addition, the Company recorded a non-current liability of approximately $4.6 million and an addition to oil and gas properties and the gas collection system of approximately $3.9 million. See Note 12 to the Consolidated Financial Statements.

The Company provided for deferred taxes for the nine months ended September 30, 2003 at a rate of 36.5% versus a 35.5% rate used for the nine months ended September 30, 2002. The one percent increase in the effective tax rate was primarily due to an anticipated increase in the Company's federal tax rate.

The Company's primary sources of liquidity are cash provided by operations and debt financing. Capital markets have also been utilized in order to maintain the Company's indebtedness at moderate levels in order to provide sufficient financial flexibility to react to future opportunities. The Company's primary needs for cash are for exploration, development and acquisitions of oil and gas properties and working capital obligations.

The Company's anticipated capital expenditures for 2003 are approximately $265.4 million. Of the $265.4 million, approximately $94 million is expected to be paid in the form of Evergreen common stock. Currently, the Company has sufficient capacity under its $200 million line of credit to fund the cash expenditures. Management also believes that the Company has the capacity to increase its line of credit and borrowing base to $300 million if required. As of October 28, 2003, the Company has $70 million available under its line of credit. The Company also has access to additional capital sources which management believes it could utilize.

During the nine months ended September 30, 2003, the Company incurred a total of $124.8 million in capital expenditures. Of this total, exploration expenditures amounted to $40.8 million. Included in exploration costs are acquisition costs for acreage in Kansas of approximately $35.1 million. Capital expenditures also included approximately $2.5 million for expenditures in the United Kingdom and Ireland, which were primarily associated with the plugging and abandonment of the wells. Approximately $30.6 million of costs were incurred on the drilling and completion of wells in the Raton Basin and $17.1 million on remediation projects and other Raton Basin development costs. Additions to the gas gathering system in the Raton Basin amounted to $30.9 million for the nine months ended September 30, 2003.

The Company estimates that it will spend $140.6 million during the quarter ending December 31, 2003. Of this amount, approximately $96.5 million will be for the Carbon acquisition ($94 million of which will be paid in Evergreen common stock), $19.1 million for exploration projects in Kansas and Alaska, $24.8 million for Raton Basin projects and $0.2 million for other projects.

The Company has completed its capital budget for 2004. The total capital expenditures are estimated to be $220 million. Of this amount, approximately $90.3 million will be for the coal bed methane operations in the Raton Basin, which includes $32.4 million for infrastructure, $38.2 million for the drilling and completion of 160 wells, and $19.7 million for recompletions and other miscellaneous items. Total capital costs in Alaska will amount to $6.3 million for the drilling of wells and acreage acquisition.

The Company has started to drill unconventional gas wells in eastern Kansas in the fourth quarter of 2003. During 2004, Evergreen will continue the development of the Kansas properties with a capital budget of $57.9 million. This amount includes drilling and completion costs for 150 wells (including core wells and water disposal wells) of approximately $16.2 million, infrastructure costs of $18.5 million, and acreage acquisition and equipment costs of $23.2 million.

With the completion of the Carbon Energy acquisition, the Company will drill a number of wells in both the Piceance/Uintah areas and Canada in 2004. The total number of gross wells drilled in the Piceance/Uintah areas will be 55 with total drilling and completion costs of $18 million, infrastructure costs of $5 million and other costs of $4.4 million. The total number of gross wells drilled in Canada will be 72 with total drilling and completion costs of $20 million, property acquisitions of $10 million and other costs of $4.2 million.

The Company believes that its credit facility and cash flow from operations should be sufficient to fund the capital expenditure budget for 2004.

The Company has no off-balance sheet financing arrangements (other than operating leases) or any unconsolidated special purpose entities.

Net cash provided by operating activities was $103.1 million for the nine months ended September 30, 2003, as compared to $33.6 million for the same period in 2002. The increase of

$69.5 million was primarily due to an $82.5 million increase in natural gas revenues in the first nine months of 2003 as compared to the first nine months of 2002. An increase in accounts receivable was the primary reason for the $4.5 million net change in operating assets and liabilities. Accounts receivable increased as a result of higher natural gas prices and production in September 2003 as compared to December 2002.

Net cash used in investing activities was $99.2 million during the nine months ended September 30, 2003, versus $88.4 million in the first nine months of 2002. The increase in 2003 was primarily due to a larger investment in property and equipment during the nine months ended September 30, 2003 as compared to the nine months ended September 30, 2002.

Cash flows provided by financing activities during the first nine months of 2003 were $3.3 million compared to cash provided by financing activities of $52.6 million during the first nine months of 2002. The change of $49.3 million was primarily associated with the increase in cash flows provided by operating activities in the first nine months 2003 as compared to the first nine months of 2002, which enabled the Company to fund its capital projects primarily with cash flows from operations without using debt financing, and pay down its revolving credit facility by $4.5 million.

The Company may use derivative instruments to manage exposures to commodity prices, foreign currency and interest rate risks. The Company's objectives for holding derivatives are to achieve a consistent level of cash flow to support its capital budgeting and expenditure plans and to maximize internal rates of return for capital projects including property acquisition investments. The Company does not enter into derivative instruments for trading purposes.

At September 30, 2003, the Company had the following open derivative contracts to manage price risk on a portion of its natural gas production. ("MMBtu" means million British thermal units and converts on an approximate one-for-one basis into Mcf.) The contracts are based on the regional price indexes where the Company physically delivers its natural gas.

Remaining Contract Period	Type of Instrument(s)	Volume in MMBtu/day	Weighted Average $/ MMBtu		Unrealized Gain (Loss) at September 30, 2003
					(in thousands)
Oct 03 - Dec 03	Swaps	70,000	$	4.37	$	20
Oct 03 - Dec 03	Costless Collar	20,000	$	3.26/5.02		(238	)
Jan 04 - Dec 04	Swap	10,000	$	3.75		(2,889	)
Jan 04 - Dec 04	Costless Collar	20,000	$	3.21/4.91		(2,779	)

					$	(5,886	)

Based on the calculated fair values at September 30, 2003, the Company expects to reclassify net losses of $4.4 million into earnings related to these derivative contracts during the next 12 months.

Subsequent to September 30, 2003, the Company entered into the following commodity swap agreements:

Contract Period	Market	Volume in MMBtu/day	Net Price in US $ per MMBtu
Nov 03 - Dec 03	NGPL—Midcontinent	45,000	$	5.36
Jan 04 - Dec 04	NGPL—Midcontinent	20,000	$	4.36
Jan 04 - Dec 04	Northwest Pipeline—Rockies	3,000	$	4.01
Jan 04 - Dec 04	AECO	4,739	$	4.29

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 addresses accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (Including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized and measured initially at fair value when the liability is incurred.

SFAS No. 146 was effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of this statement did not have a material effect on the Company's financial statements.

The Company measures its exposure to market risk at any point in time by comparing its open positions to a market risk of fair value. The market prices the Company uses to determine fair value are based on management's best estimates, which consider various factors including closing exchange prices, volatility factors and the time value of money. At September 30, 2003, the Company was exposed to some market risk with respect to natural gas prices, long-term debt and foreign currency.

Commodity Risk. The Company's major market risk exposure is in the pricing applicable to its natural gas production. Realized pricing is primarily driven by the prevailing price for crude oil and spot prices applicable to Evergreen's natural gas production. Historically, prices received for gas production have been volatile and unpredictable. Pricing volatility is expected to continue.

The Company periodically enters into agreements to hedge its natural gas production when market conditions are deemed favorable in order to manage price fluctuations and achieve a more predictable cash flow. The Company may use fixed-price physical delivery contracts and derivative instruments to manage exposures to commodity prices. The Company does not enter into derivative instruments for trading purposes.

Assuming that (i) production, (ii) the percent of gas hedged and (iii) the average realized market price of the unhedged gas sold remained unchanged from the nine months ended September 30, 2003, a hypothetical 10% decline in the average market price the Company realized on unhedged production would reduce the Company's natural gas revenues by approximately $5.8 million on an annual basis.

Interest Rate Risk. At September 30, 2003, Evergreen had long-term debt outstanding of $231.5 million. The interest rates on the Company's revolving credit facility, under which $131.5 million in indebtedness was outstanding at September 30, 2003, range from LIBO rate plus 1.375% to prime and are variable; however, they may be fixed at Evergreen's option for periods of time between 30 to 90 days. A 10% increase in short-term interest rates on the floating-rate debt outstanding at September 30, 2003 would equal approximately 26 basis points. Such an increase in interest rates would impact Evergreen's annual interest expense by approximately $0.3 million, assuming borrowed amounts under the credit facility remained at $131.5 million.

The $100 million of outstanding convertible notes have a fixed interest rate of 4.75%; however, up to an additional 0.40% may be paid as contingent interest if certain conditions are met. Accordingly, the Company's annual interest payment on the $100 million convertible notes will be a minimum of $4.75 million and a maximum of $5.15 million.

Foreign Currency Risk. Evergreen's net assets, revenue and expense accounts from its foreign operations are based on the U.S. dollar equivalent of such amounts measured in the British pound sterling or euro. Assets and liabilities of the foreign operations are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rates during the reporting period. The Company expects to spend

only nominal amounts during the remainder of 2003 for exiting and winding down its operations in the United Kingdom, Northern Ireland, and the Republic of Ireland. As such, any significant change in the exchange rate for the British pound sterling or euro would not have a material impact on the cost of such operations.

Evergreen completed the acquisition of Carbon effective October 29, 2003. Carbon conducts business in Canada through its Canadian subsidiary where the Canadian dollar has been designated as the functional currency. As such, the Carbon acquisition will subject the Company to foreign currency exchange risk on cash flows relating to sales, expenses, financing and investing transactions.

As of September 30, 2003, the Company's Chief Executive Officer and the Chief Financial Officer evaluated the effectiveness of the Company's disclosure controls and procedures in accordance with Rule 13a-15 under the Exchange Act. Based on their evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the Company's disclosure controls and procedures enable the Company to record, summarize and report in a timely manner the information that the Company is required to disclose in its Exchange Act reports.

There were no changes in the Company's internal control over financial reporting that occurred during the period covered by this report that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

On December 26, 2002, Evergreen was named as a defendant in a class action lawsuit filed in the United States District Court for the District of Colorado. The plaintiffs, Mountain West Exploration, Inc., Joel Nelson and Synergy Operations Company, LLC, are royalty owners and overriding royalty owners who are alleging that they were underpaid royalties and seek to recover damages and declaratory and injunctive relief. Evergreen intends to vigorously defend this action and has asserted numerous affirmative defenses. It is too early to provide an evaluation of the likelihood of an unfavorable outcome or an estimate of the amount or range of potential loss.

On July 31, 2003, Evergreen Resources Inc. furnished a Form 8-K under Item 12 to report its financial results for its second quarter ended June 30, 2003.

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.

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended: September 30, 2003.
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Colorado (State or Other Jurisdiction of Incorporation or Organization)		84-0834147 (I.R.S. Employer Identification Number)
1401 17th Street Suite 1200 Denver, Colorado (Address of Principal Executive Offices)		80202 (Zip Code)
Registrant's Telephone Number, Including Area Code: (303) 298-8100

			September 30, 2003			December 31, 2002
			(unaudited)
			(in thousands)
ASSETS
Current:
	Cash and cash equivalents		$	8,052		$	871
	Accounts receivable			25,489			17,684
	Other current assets			7,458			1,384

Total current assets				40,999			19,939

Property and equipment, at cost:
	Oil and gas properties, full cost method of accounting:
		Proved, net of accumulated depletion of $67,747 and $54,061		424,340			384,232
		Unproved		67,251			29,163

				491,591			413,395
	Other property and equipment, net of accumulated depreciation and amortization of $26,291 and $20,370			194,486			167,021

Total net property and equipment				686,077			580,416

Other assets				3,940			6,406

			$	731,016		$	606,761

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	8,114		$	4,109
	Amounts payable to oil and gas property owners			9,017			5,871
	Production and property taxes payable			8,183			5,731
	Derivative instruments			5,626			1,454
	Accrued expenses and other			12,305			7,912

Total current liabilities				43,245			25,077
Notes payable and senior convertible notes				231,500			236,000
Deferred income tax liabilities				53,885			27,666
Production taxes payable and other				5,905			4,328
Asset retirement obligation				5,494			—

Total liabilities				340,029			293,071

Minority interests in subsidiaries				5,073			1,262

Stockholders' equity:
	Preferred stock, $1.00 par value; shares authorized, 24,900; none outstanding			—			—
	Common stock, $0.005 stated value; shares authorized, 50,000; shares issued and outstanding 39,227 and 38,105			196			190
	Additional paid-in capital			284,005			262,083
	Retained earnings			105,451			50,471
	Accumulated other comprehensive loss			(3,738	)		(316	)

Total stockholders' equity				385,914			312,428

			$	731,016		$	606,761

		Three Months Ended September 30,
		2003			2002
		(in thousands, except per share data)
Revenues:
	Natural gas revenues	$	53,498		$	29,465
	Interest and other		469			225

Total revenues			53,967			29,690

Expenses:
	Lease operating expense		4,705			4,318
	Transportation costs		3,701			3,135
	Production and property taxes		2,331			1,294
	Depreciation, depletion and amortization		6,495			5,470
	General and administrative expense		3,766			2,113
	Interest expense		1,988			2,153
	Other (income) expense		(1,193	)		286
	Impairment of international properties		1,270			34,170

Total expenses			23,063			52,939

Income (loss) before income taxes			30,904			(23,249	)
Income tax provision (benefit)—deferred			11,280			(8,253	)

Net income (loss)		$	19,624		$	(14,996	)

Basic income (loss) per common share		$	0.50		$	(0.40	)

Diluted income (loss) per common share		$	0.49		$	(0.40	)

		Nine Months Ended September 30,
		2003			2002
		(in thousands, except per share data)
Revenues:
	Natural gas revenues	$	155,484		$	72,974
	Interest and other		893			458

Total revenues			156,377			73,432

Expenses:
	Lease operating expense		14,714			11,955
	Transportation costs		10,623			9,026
	Production and property taxes		8,284			3,927
	Depreciation, depletion and amortization		18,211			15,470
	General and administrative expense		9,642			6,724
	Interest expense		6,262			6,105
	Other (income) expense		(1,560	)		508
	Impairment of international properties		2,496			34,170

Total expenses			68,672			87,885

Income (loss) before income taxes and cumulative effect of change in accounting principle			87,705			(14,453	)
Income tax provision (benefit)—deferred			32,012			(5,131	)

Income (loss) before cumulative effect of change in accounting principle			55,693			(9,322	)
Cumulative effect of change in accounting principle, net of tax			713			—

Net income (loss)		$	54,980		$	(9,322	)

Basic income (loss) per common share:
	Income (loss) before cumulative effect of change in accounting principle	$	1.44		$	(0.25	)
	Cumulative effect of change in accounting principle, net of tax		0.02			—

		$	1.42		$	(0.25	)

Diluted income (loss) per common share:
	Income (loss) before cumulative effect of change in accounting principle	$	1.39		$	(0.25	)
	Cumulative effect of change in accounting principle, net of tax		0.01			—

		$	1.38		$	(0.25	)

31.1		Certification Pursuant to Rule 13a-14(a) or 15d-14(a) of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2		Certification Pursuant to Rule 13a-14(a) or 15d-14(a) of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

	EVERGREEN RESOURCES, INC.
	(Registrant)
Date: October 29, 2003	By:	/s/ KEVIN R. COLLINS Kevin R. Collins EVP—Finance, Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer)