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. Yes ý No o

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

As of July 31, 2003, 19,523,805 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 June 30, 2003 and December 31, 2002
		Consolidated Statements of Income for the Three Months Ended June 30, 2003 and 2002
		Consolidated Statements of Income for the Six Months Ended June 30, 2003 and 2002
		Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2003 and 2002
		Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 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.		Submissions 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

(Unaudited)

EVERGREEN RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of June 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 a coal bed methane project in Alaska's Cook Inlet-Susitna Basin and is also in the process of acquiring unconventional natural gas prospects in the Forest City Basin of eastern Kansas, the Piceance Basin of western Colorado, the Uintah Basin of eastern Utah, and western Sedimentary Basin of Canada.

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 statement 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 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 June 30, 2003 and 2002 and the results of its operations and statements of comprehensive income for the three and six months then ended and the cash flows for the six 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 six months ended June 30, 2003 and 2002, Evergreen capitalized $4.8 million and $2.9 million of internal costs. Of these amounts, approximately $2.6 million and $1.8 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. During the six months ended June 30, 2003 and 2002, approximately $0.5 million and $0.7 million of interest was capitalized.

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.

Depreciation and 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.

Through June 2003, the Company has acquired approximately 480,000 acres of prospective unconventional natural gas properties in the Forest City Basin of eastern Kansas. The Company is in the process of acquiring an additional 43,000 acres which would bring Evergreen's total acreage position in the Forest City Basin to more than 520,000 acres. The Company has invested approximately $24.1 million in these properties from the fourth quarter of 2002 through June 30, 2003 (including 248,538 shares of Evergreen common stock issued in April 2003 valued at $12.4 million). The Company plans to drill and complete an estimated 33 coal bed methane wells and seven water disposal wells in the Forest City Basin in the fourth quarter of 2003. Evergreen holds a 100% working interest in the Kansas acreage. The acreage generally lies in the Forest City Basin and Cherokee Platform which contains shallow gas potential from coals, fractured shales and sands.

Evergreen announced on March 31, 2003 that it intends to acquire 100% of the outstanding common stock of Carbon Energy Corporation ("Carbon"). 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 properties in the United States are located in the Piceance Basin in Colorado and in the Uintah Basin in Utah. Carbon's properties in Canada are located in central Alberta and southeast Saskatchewan. Under the terms of the merger agreement, Carbon's shareholders will receive 0.275 shares of Evergreen common stock for each common share of Carbon. The exchange ratio was based upon the relative values of the two securities at the time of the merger agreement. This will require Evergreen to issue approximately 1.69 million new shares of Evergreen common stock to Carbon's shareholders based on the outstanding Carbon common stock at March 31, 2003. Based upon the average closing price of Evergreen's common stock for a period two days before and after announcement of the merger, the average value per share is $45.43 per share, and the total value of the stock to be issued is approximately $76.8 million. The aggregate value of the transaction, including transaction costs of approximately $7.0 million and the fair value of Carbon employee stock options to be assumed by Evergreen of approximately $5.4 million, is approximately $89.2 million. The actual amount of the common stock and options will not be known until the closing of the transaction. The transaction is expected to be non-taxable to the stockholders of both companies. The exchange rate and per-share information set forth above has not been adjusted for the two-for-one stock split payable to shareholders of record on August 29, 2003. See Note 6.

The transaction is subject to the approval of Carbon's shareholders. The boards of directors of both companies have unanimously approved the merger. Completion of the transaction is expected to close on or about September 30, 2003. The acquired Carbon properties are estimated to contain at least 88 billion cubic feet equivalent 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 57 billion cubic feet ("Bcf") and 31 Bcf, respectively, of which 39% and 66% 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 gas production in the United States and Canada is more than 14 million cubic feet of gas equivalent. The gross acreage position is approximately 150,000 acres in the United States and 77,000 acres in Canada.

Subsequent to the execution of the merger agreement, Evergreen has received indications of interest from several oil and gas companies about the purchase from Evergreen of the Carbon Piceance and Uintah Basin assets. Evergreen has conducted preliminary discussions with these companies. After the closing of the merger, Evergreen intends to seek additional prospective purchasers and to consider a potential sale of these United States assets to one or more acceptable purchasers on advantageous terms.

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 six months ended June 30, 2003 and 2002:

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 June 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 468,830 shares of common stock during the six months ended June 30, 2003 which included the issuance of 248,538 common shares for unconventional natural gas properties in the Forest City Basin of eastern Kansas (see Note 3), the issuance of 9,432 common shares as employee compensation and the issuance of 210,860 common shares in conjunction with the exercise of stock purchase options.

Evergreen's board of directors recently approved a two-for-one split of Evergreen common stock. Shareholders of record on August 29, 2003, the record date, will be issued a certificate representing one additional share of common stock for each share of common stock held on the record date. The additional shares will be mailed or delivered on or about September 15, 2003 by the Company's transfer agent, Computershare Trust Company. Upon completion of the split, the Company will have approximately 39 million shares outstanding. In addition to the 39 million shares outstanding, the Company has committed for the potential issuance of an additional approximate 10.5 million shares (post stock-split) under the Carbon acquisition (discussed in Note 4), the senior convertible notes, stock purchase options and unvested restricted stock grants.

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 June 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.

As of June 30, 2003, the Company had recorded net unrealized losses of approximately $18.0 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 liability of $14.9 million and a non-current liability of $3.1 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 June 30, 2003, the Company expects to reclassify net losses of $14.9 million into earnings related to the these derivative contracts during the next 12 months. Actual gains or losses recognized may be materially different than what was estimated at June 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 six months ended June 30, 2003, the Company recognized approximately $2.9 million and $14.8 million in hedging losses, respectively, related to natural gas derivative contracts designated as cash flow hedges. Net hedging losses of $6.1 million and $6.0 million were recognized related to natural gas derivative contracts designated as cash flow hedges during the three and six months ended June 30, 2002. The losses are included in natural gas revenues in the Consolidated Statements of Income for each period presented.

In addition to the derivative instruments reflected in the above table, the Company also 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 $0.8 million loss on these derivative instruments in the second quarter of 2003 related to the change in the fair market value of these instruments. This loss is included in other expense in the Consolidated Statement of Income. The cash payments for these instruments are included in Investing Activities in the Consolidated Statement of Cash Flows. At June 30, 2003 the estimated net fair value of these instruments was a $0.2 million liability which is presented on the Consolidated Balance Sheet as a current liability of $0.6 million and a current asset of $0.4 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 $0.1 and a $0.2 million loss on this contract during the three and six months ended June 30, 2002, which is included in interest expense in the Consolidated Statement of Income 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.

Under the Company's 2000 Stock Incentive Plan, shares of common stock may be granted to key employees under terms and conditions determined by management. These stock grants generally vest over a period of four to six years and are distributed to the employees as the shares vest. The Company determines employee 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.

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.

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 and earnings 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:

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 June 30, 2003, Evergreen had $130 million of outstanding borrowings under this credit facility, with a current average interest rate of approximately 2.9%. The Company was in compliance with all loan covenants at June 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 $50 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 June 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.

Cash paid during the six months ended June 30, 2003 and 2002 for interest was approximately $4.6 million and $3.8 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 six months ended June 30, 2003:

	Asset Retirement Obligation
	(in thousands)
Upon adoption at January 1, 2003	$	4,631
Liabilities incurred		490
Liabilities settled		—
Accretion		164
Revisions to estimate		—

	$	5,285

The schedule below reflects, on a pro forma basis, the net income (loss), net income (loss) per share amounts and the liability for asset retirement obligations as if SFAS No. 143 had been applied during all the periods presented.

In June 2001, the FASB issued SFAS No. 141, "Business Combinations," which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets," which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The amortization provisions apply to goodwill and intangible assets acquired after June 30, 2001. SFAS No. 141 and 142 clarify that more assets should be distinguished and classified between tangible and intangible. The Company did not change or reclassify contractual mineral rights held under lease and other contractual arrangements included in oil and gas properties on the balance sheet upon adoption of SFAS No. 142. The Company believes the treatment of such mineral rights as tangible assets under the full cost method of accounting for crude oil and natural gas properties is appropriate. However, the staff of the SEC has recently questioned whether costs associated with mineral rights held under lease and other contractual arrangements should be reflected as intangible assets in the balance sheet apart from capitalized oil and gas properties. Evergreen is currently unable to predict the potential impact on its financial statements if the Company is ultimately required to account for mineral rights held under lease and other contractual arrangements under the provisions of SFAS 142.

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 were 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, and Section 21E of the Securities Exchange Act of 1934, as amended, 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, (v) the impact of government regulation, (vi) financial market conditions, (vii) wars and acts of terrorism or sabotage and (viii) the risk associated with integration of acquired companies. 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 transaction is subject to the approval of Carbon's shareholders. The boards of directors of both companies have unanimously approved the merger. The transaction is expected to close on or about September 30, 2003. The acquired Carbon properties are estimated to contain at least 88 billion cubic feet equivalent 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 57 billion cubic feet ("Bcf") and 31 Bcf, respectively, of which 39% and 66% 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 gas production in the United States and Canada is more than 14 million cubic feet of gas equivalent. The gross acreage position is approximately 150,000 acres in the United States and 77,000 acres in Canada.

Through June 2003, the Company has acquired approximately 480,000 acres of prospective unconventional natural gas properties in the Forest City Basin of eastern Kansas. The Company is in the process of acquiring an additional 43,000 acres, which would bring Evergreen's total acreage position in the Forest City Basin to more than 520,000 acres. The Company has invested approximately $24.1 million in these properties from the fourth quarter of 2002 through June 30, 2003 (including 248,538 shares of Evergreen common stock issued in April 2003 valued at $12.4 million). The Company plans to drill and complete an estimated 33 coal bed methane wells and seven water disposal wells in the Forest City Basin in the fourth quarter of 2003. Evergreen holds a 100% working interest in the Kansas acreage. The acreage generally lies in the Forest City Basin and Cherokee Platform and also contains shallow gas potential from coals, fractured shales and sands.

Evergreen increased its proven reserves 5% during the first six months of 2003 to an estimated 1.305 trillion cubic feet ("Tcf") of natural gas as of June 30, 2003, up from 1.239 Tcf at year-end 2002. Evergreen added 87.7 billion cubic feet Bcf of gas reserves with immaterial revisions and produced 21.7 Bcf during the first half of 2003. The reserve increase was attributable to Evergreen's successful drilling and recompletion efforts in the Raton Basin.

Natural gas in the southern Colorado portion of the Raton Basin constitutes all of Evergreen's net proven reserves, 65% of which were classified as developed as of June 30, 2003. The mid-year 2003 reserve estimate is based on a total of 1,398 gas wells, including 398 classified as proved undeveloped locations. Evergreen estimates that it has at least 700 additional wells to drill in the Raton Basin, including the proved undeveloped locations. Independent petroleum engineering consultants Netherland Sewell & Associates, Inc. audited the mid-year reserve estimate.

The present value of estimated future net revenues from Evergreen's proven reserves, discounted at 10%, was $2.0 billion (before income taxes) as of June 30, 2003. Using guidelines established by the Securities and Exchange Commission, the calculation for the mid-year 2003 reserve estimate was based on an unescalated gas price of $4.71 per Mcf, reflecting prevailing gas prices at June 30, 2003. The 2002 year-end present value of estimated future net revenues was $1.6 billion which used a gas price of $4.22 per Mcf.

Evergreen's board of directors recently approved a two-for-one split of Evergreen common stock. Shareholders of record on August 29, 2003, the record date, will be issued a certificate representing one additional share of common stock for each share of common stock held on the record date. The additional shares will be mailed or delivered on or about September 15, 2003 by the Company's transfer agent, Computershare Trust Company. Upon completion of the split, the Company will have approximately 39 million shares outstanding. In addition to the 39 million shares outstanding, the Company has committed for the potential issuance of an additional approximate 10.5 million shares (post stock-split) under the Carbon acquisition (discussed above), the senior convertible notes, stock purchase options and unvested restricted stock grants.

The Company has drilled 113 coal bed methane wells in the Raton Basin from the beginning of the year through July 31, 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 July 2003 were approximately 123 million cubic feet per day.

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. All four wells at the Company's first pilot project were fracture stimulated as was one well at the Company's second four-well pilot project. All five wells are in various stages of de-watering with production-potential data expected in the fourth quarter. The Company will drill four or five cored stratigraphic tests in the fourth quarter of 2003 to gain additional geologic and petrophysical information on the total coal bed methane resource.

Results of Operations—Three and Six Months Ended June 30, 2003 compared to the Three and Six Months Ended June 30, 2002

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

		Three Months Ended June 30,		Six Months Ended June 30,
		2003		2002		2003		2002
Natural gas production (MMcf)			11,174			9,498			21,689			18,326
Average realized sales price per Mcf*		$	4.74		$	2.45		$	4.70		$	2.37
Cost per Mcf:
	Lease operating expenses		$	0.47		$	0.42		$	0.46		$	0.42
	Transportation costs		$	0.32		$	0.32		$	0.32		$	0.32
	Production and property taxes		$	0.27		$	0.15		$	0.27		$	0.14
	Depreciation, depletion and amortization		$	0.55		$	0.55		$	0.54		$	0.55
	General and administrative expense		$	0.29		$	0.25		$	0.27		$	0.25
	Interest expense		$	0.19		$	0.21		$	0.20		$	0.22

The Company reported net income of $18.4 million or $0.92 per diluted share for the three months ended June 30, 2003, compared to net income of $3.3 million or $0.17 per diluted share for the same period in 2002. For the six months ended June 30, 2003, the Company reported net income of $35.4 million or $1.78 per diluted share compared to net income of $5.7 million or $0.29 per diluted share in 2002. The increase in net income during the three and six months ended June 30, 2003, as compared to the prior year periods, was primarily attributable to increases in the average realized gas prices and production as discussed below.

Natural gas revenues increased to $53.0 million during the three months ended June 30, 2003, from $23.3 million for the same period in the prior year. During the six months ended June 30, 2003, natural gas revenues increased to $102.0 million from $43.5 million for the same period in the prior year. The increase in natural gas revenues for the three and six month periods ended June 30, 2003 compared to the same periods in 2002 were due to a 93% and 98% increase in the average realized natural gas price to $4.74 and $4.70 per Mcf in 2003 from $2.45 and $2.37 per Mcf in 2002. Approximately 75% of Evergreen's net production during the second quarter of 2003 was hedged using financial instruments. The Company realized $2.9 million and $14.8 million in net losses related to its financial hedges during the three and six months ended June 30, 2003, compared to net losses of $6.1 million and $6.0 million during the three and six months ended June 30, 2002.

Net gas production for the three and six months ended June 30, 2003 increased to 11.2 Bcf and 21.7 Bcf, or an average of 122.8 MMcf and 119.8 MMcf per day, from 9.5 Bcf and 18.3 Bcf, or an average of 104.4 MMcf and 101.2 MMcf per day, for the comparable periods in 2002.

Evergreen had 909 net producing gas wells at June 30, 2003 compared to 754 at June 30, 2002. Evergreen drilled 108 coal bed methane wells in the Raton Basin during the first six months of this year compared to 101 coal bed methane wells in the first six months of 2002.

Lease operating expenses for the three months ended June 30, 2003 were $5.3 million or $0.47 per Mcf compared to $4.0 million or $0.42 per Mcf for the same period in 2002. During the six months ended June 30, 2003, lease operating expenses were $10.0 million or $0.46 per Mcf as compared to $7.6 million or $0.42 per Mcf for the same period in the prior year. The increases of $1.3 million and $2.4 million for the three and six months ended June 30, 2003 from 2002 were primarily due to increases in well repairs and field supplies of $1.1 million and $2.0 million, respectively. The increase in well repairs is partially attributable to an increasing number of older wells and surface systems in the Raton Basin. The Company is in the process of performing a field-wide review of the producing properties in the Raton Basin in order to achieve enhanced operational efficiencies through improved design of replacement equipment, which should result in longer run times and more consistent production. Higher operating costs are expected to continue through 2003.

Transportation costs remained unchanged at $0.32 per Mcf for three and six months ended June 30, 2003 and 2002.

Production and property taxes for the three months ended June 30, 2003 were $3.0 million compared to $1.4 million for the same period in 2002. For the six months ended June 30, 2002, production and property taxes were $6.0 million as compared to $2.6 million for the same period in the prior year. The increases in production taxes were primarily due to higher natural gas revenues. The Company pays production taxes on the value of its natural gas physically sold. Accordingly, any financial hedging gains and losses realized by the Company, which are recorded as a component of natural gas revenues, are not subject to production taxes. Excluding the financial hedging losses discussed above for the periods presented, production and property taxes as a percentage of natural gas sales for the three and six months ended June 30, 2003 were approximately 5.3% and 5.1%, respectively, and approximately 4.9% and 5.3% for the three and six months ended June 30, 2002, respectively.

Depreciation, depletion and amortization expense for the three months ended June 30, 2003 was $6.2 million compared to $5.2 million for the same period in 2002. On an equivalent Mcf basis, depreciation, depletion and amortization expense was $0.55 per Mcf for both of the three months ended June 30, 2003 and 2002. During the six months ended June 30, 2003, depreciation, depletion and amortization expense was $11.7 million or $0.54 per Mcf as compared to $10.0 million or $0.55 per Mcf for the same period in the prior year.

General and administrative expenses were $3.3 million during the three months ended June 30, 2003, as compared to $2.4 million during the same period in 2002. The $0.9 million increase was primarily attributable to a $0.6 million increase in general and administrative salaries and $0.2 million increase in professional services. For the six months ended June 30, 2003, general and administrative expenses were $5.9 million as compared to $4.6 million for the same period in the prior year. The $1.3 million increase in general and administrative expense was primarily attributable to a $0.9 million increase in general and administrative salaries and a $0.2 million increase in professional services.

Interest expense was $2.1 and $2.0 million for the three months ended June 30, 2003 and 2002, respectively. During the six months ended June 30, 2003, interest expense was $4.3 million compared to $4.0 million in the first half of the prior year. Although average debt balances were higher in the first six months of 2003 than compared to the first six months of 2002, interest expense increased only marginally due to a reduction in average interest rates from approximately 4.6% during the first six months of 2002 to 4.1% during the first six months of 2003.

Other expense of $0.9 million for the three months ended June 30, 2003 primarily includes a $1.0 million gain on the sale of an investment in common stock, a $0.4 million charge for plugging, abandonment and restoration operations in the United Kingdom, Northern Ireland and the Republic of Ireland, a $0.8 million unrealized loss on derivative instruments, and a $0.5 million minority interest expense which was primarily related to an approximate 25% minority ownership interest in Long Canyon Gas Company, LLC. Other expense of $0.9 million for the six months ended June 30, 2003 primarily includes a $1.0 million gain on the sale of common stock in an unaffiliated company, a $1.0 million foreign currency exchange gain related to the Company's planned exit of its United Kingdom operations, a $1.2 million charge for plugging, abandonment and restoration operations in the United Kingdom, Northern Ireland and the Republic of Ireland, a $0.8 million unrealized loss on derivative instruments, and a $0.5 million of 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.

Other expense of $0.2 million for the three and six months ended June 30, 2002 is primarily attributable to losses on the disposals of assets.

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 three and six months ended June 30, 2003 at a rate of 36.5% versus a 35.5% rate for the three and six months ended June 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.

In March 2003, Evergreen's Board of Directors authorized a significant increase in the Company's capital expenditure budget for 2003 from $110 million to $275 million as a result of the currently proposed and recently completed asset acquisitions of unconventional natural gas properties in North America, including the Carbon Energy Corporation merger (approximately $112 million, which includes development expenditures of $23 million), Kansas property acquisitions (approximately $31 million), equipment purchases related to the development of the Kansas property acquisitions (approximately $12 million) and other costs (approximately $10 million.) Of the $275 million capital budget, 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 these expenditures. Further, management believes that the Company has the capacity to increase its line of credit and borrowing base to $300 million if required. As of July 31, 2003, the Company had $77 million available under its line of credit. The Company also has access to additional capital sources which management believes it could utilize if required. As discussed under "Recent Developments", the Company has received indications of interest from several oil and gas companies about the purchase from Evergreen of the Carbon Piance and Uintah Basin assets after the merger is completed. Such a transaction would enable the Company to reduce debt and interest expense on a prospective basis.

The $275 million capital expenditure budget is allocated as follows: $101 million for the development of the Raton Basin, primarily for the drilling of 160 wells and related infrastructure costs; $54 million for exploration projects and equipment in Alaska and Kansas; $8 million for other property acquisitions and equipment; and $112 million for the Carbon acquisition and development.

Cash flows provided by operating activities were $56.7 million for the six months ended June 30, 2003, as compared to $12.7 million for the same period in 2002. The increase of $44.0 million was primarily due to a $48.0 million increase in income before income taxes and cumulative effect of change in accounting principle in the first six months of 2003 as compared to the first six months of 2002, offset by a $8.1 million increase in accounts receivable from December 31, 2002 to June 30, 2003. The increase in accounts receivable was a result of higher natural gas prices in June 2003 as compared to December 2002.

Cash flows used in investing activities were $56.6 million during the six months ended June 30, 2003, versus $63.0 million in the first six months of 2002. The decrease in 2003 was primarily due to the Company spending less on international projects and support equipment in the first six months of 2003 compared to 2002.

Capital expenditures in the first half of 2003 were $78.2 million. These capital costs included $21.0 million for the drilling and completion of 108 Raton Basin gas wells, $11.0 million primarily for recompletions and $16.8 million for the Raton Basin gas collection system. Approximately $26.5 million was used for exploration projects, including $21.9 million for acreage acquisitions in eastern Kansas and $4.6 million for operations in the Cook Inlet Basin of Alaska.

Cash flows provided by financing activities during the first six months of 2003 were $3.7 million compared to cash provided by financing activities of $49.9 million during the first six months of 2002. The change of $46.2 million was primarily associated with the increase in cash flows provided by operating activities in the first six months 2003 as compared to the first six months of 2002, which enabled the Company to fund its capital projects with cash flows from operations and pay down its revolving credit facility $6.0 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. These transactions limit Evergreen's exposure to declines in prices, but also limit the benefits Evergreen would realize if prices increase. The Company does not enter into derivative instruments for trading purposes.

Based on the calculated fair values at June 30, 2003, the Company expects to reclassify net losses of approximately $14.9 million into earnings related to the above derivative contracts during the next 12 months.

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 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 June 30, 2003, the Company was exposed to some market risk with respect to long-term debt, foreign currency and natural gas prices.

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 six months ended June 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 $5.7 million on an annual basis.

Interest Rate Risk. At June 30, 2003, Evergreen had long-term debt outstanding of $230 million. The interest rates on the Company's revolving credit facility, under which $130 million in indebtedness was outstanding at June 30, 2003, range from LIBO rate plus 1.50% to prime plus 0.25% 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 June 30, 2003 would equal approximately 29 basis points. Such an increase in interest rates would impact Evergreen's annual interest expense by approximately $0.4 million, assuming borrowed amounts under the credit facility remained at $130 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 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.

As of June 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.

The following summarizes the votes at the Company's Annual Meeting of Shareholders held on May 6, 2003:

Election of Directors—with terms expiring at the Annual Meeting of Shareholders in 2005 and 2006:

Name	Term to Expire	For	Withheld
Alain G. Blanchard	2006	12,112,334	4,726,739
Robert J. Clark	2006	12,111,593	4,727,480
Andrew D. Lundquist	2005	12,111,393	4,727,680
Scott D. Sheffield	2006	12,111,493	4,727,580

Ratification of the appointment of BDO Seidman, LLP as independent auditors for the year ending December 31, 2003

For		Against		Abstain
16,584,826		252,386		1,861

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

On April 28, 2003, Evergreen Resources Inc. furnished a Form 8-K under Item 9 to report, pursuant to Item 12, its financial results for its first quarter ended March 31, 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: June 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		84-0834147
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification Number)

1401 17th Street Suite 1200 Denver, Colorado		80202
(Address of Principal Executive Offices)		(Zip Code)

			June 30, 2003			December 31, 2002
			(unaudited)
			(in thousands)
ASSETS
Current:
	Cash and cash equivalents		$	4,646		$	871
	Accounts receivable			25,223			17,684
	Other current assets (Note 7)			4,981			1,384

Total current assets				34,850			19,939

Property and equipment, at cost, (Notes 2, 3, 4, 5, 9, 11, 12 and 13)
	Oil and gas properties, full cost method of accounting:
		Proved, net of accumulated depletion of $62,984 and $54,061		410,787			384,232
		Unproved		53,860			29,163

				464,647			413,395
	Other property and equipment, net of accumulated depreciation and amortization of $24,546 and $20,370			183,271			167,021

Total net property and equipment				647,918			580,416

Other assets				4,227			6,406

			$	686,995		$	606,761

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	5,556		$	4,109
	Amounts payable to oil and gas property owners			8,776			5,871
	Production and property taxes payable			6,911			5,731
	Derivative instruments (Note 7)			15,464			1,454
	Accrued expenses and other			8,869			7,912

Total current liabilities				45,576			25,077
Notes payable and senior convertible notes (Note 9)				230,000			236,000
Deferred income tax liabilities				39,618			27,666
Production taxes payable and other (Note 7)				6,132			4,328
Asset retirement obligation (Note 12)				5,285			—

Total liabilities				326,611			293,071

Minority interests in subsidiaries (Notes 1 and 5)				4,762			1,262

Stockholders' equity (Notes 3, 4, 6 and 8):
	Preferred stock, $1.00 par value; shares authorized, 24,900; none outstanding			—			—
	Common stock, $0.01 stated value; shares authorized, 50,000; shares issued and outstanding 19,522 and 19,053			195			190
	Additional paid-in capital			280,773			262,083
	Retained earnings			85,827			50,471
	Accumulated other comprehensive loss			(11,173	)		(316	)

Total stockholders' equity				355,622			312,428

			$	686,995		$	606,761

		Three Months Ended June 30,
		2003		2002
		(in thousands, except per share data)
Revenues:
	Natural gas revenues	$	53,010	$	23,317
	Interest and other		278		111

Total revenues			53,288		23,428

Expenses:
	Lease operating expenses		5,292		3,952
	Transportation costs		3,556		3,055
	Production and property taxes		2,972		1,442
	Depreciation, depletion and amortization		6,187		5,208
	General and administrative expenses		3,269		2,421
	Interest expense		2,074		2,033
	Other expense (Notes 7 and 10)		935		217

Total expenses			24,285		18,328

Income before income taxes			29,003		5,100
Income tax provision—deferred			10,586		1,810

Net income		$	18,417	$	3,290

Basic income per common share (Note 6)		$	0.95	$	0.17

Diluted income per common share (Note 6)		$	0.92	$	0.17

		Six Months Ended June 30,
		2003		2002
		(in thousands, except per share data)
Revenues:
	Natural gas revenues	$	101,986	$	43,509
	Interest and other		423		233

Total revenues			102,409		43,742

Expenses:
	Lease operating expenses		10,008		7,637
	Transportation costs		6,922		5,890
	Production and property taxes		5,952		2,632
	Depreciation, depletion and amortization		11,716		10,000
	General and administrative expenses		5,876		4,610
	Interest expense		4,274		3,952
	Other expense (Notes 7 and 10)		859		224

Total expenses			45,607		34,945

Income before income taxes and cumulative effect of change in accounting principle			56,802		8,797
Income tax provision—deferred			20,733		3,123

Net income before cumulative effect of change in accounting principle			36,069		5,674
Cumulative effect of change in accounting principle, net of tax (Note 12)			713		—

Net income		$	35,356	$	5,674

Basic income per common share (Note 6):
	Earnings before cumulative effect of change in accounting principle	$	1.88	$	0.30
	Cumulative effect of change in accounting principle, net of tax		0.04		—

		$	1.84	$	0.30

Diluted income per common share (Note 6):
	Earnings before cumulative effect of change in accounting principle	$	1.81	$	0.29
	Cumulative effect of change in accounting principle, net of tax		0.03		—

		$	1.78	$	0.29

Remaining Contract Period	Type of Instrument(s)	Volume in MMBtu/day	Weighted Average $/MMBtu		Unrealized Loss at June 30, 2003
					(in thousands)
Jul 03 - Dec 03	Swaps	70,000	$	4.37	$	8,493
Jul 03 - Dec 03	Costless Collar	20,000	$	3.26/5.02		1,689
Jan 04 - Dec 04	Swap	10,000	$	3.75		3,865
Jan 04 - Dec 04	Costless Collar	20,000	$	3.21/4.91		3,937

					$	17,984

	Three Months Ended June 30, 2002			Six Months Ended June 30, 2002			Years Ended December 31,
	Three Months Ended June 30, 2002			Six Months Ended June 30, 2002			2002			2001			2000
	(in thousands, except per share data)
Net income (loss) attributable to common stockholders, as reported	$	3,290		$	5,674		$	(8,324	)	$	38,527		$	14,063
Pro forma adjustments, net of tax		(63	)		(126	)		(251	)		(187	)		(104	)

Net income (loss) attributable to common stockholders, pro forma	$	3,227		$	5,548		$	(8,575	)	$	38,340		$	13,959

Basic net income (loss) per common share, as reported	$	0.17		$	0.30		$	(0.44	)	$	2.08		$	0.91

Basic net income (loss) per common share, pro forma	$	0.17		$	0.29		$	(0.45	)	$	2.07		$	0.90

Diluted net income (loss) per common share, as reported	$	0.17		$	0.29		$	(0.44	)	$	1.98		$	0.87

Diluted net income (loss) per common share, pro forma	$	0.16		$	0.28		$	(0.45	)	$	1.98		$	0.86

			December 31,
	June 30, 2002		December 31,
	June 30, 2002		2002		2001		2000
Asset retirement obligation	$	4,125	$	4,631	$	3,618	$	2,583

		EVERGREEN RESOURCES, INC. (Registrant)
Date: August 12, 2003		By:		/s/ KEVIN R. COLLINS Kevin R. Collins EVP—Finance, Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer)