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United States Securities and Exchange Commission
Washington, DC 20549

Form 10-Q

For the quarterly period ended: June 30, 2002.

For the transition period from                              to                             

Commission file number: 001-13171

EVERGREEN RESOURCES, INC.
(Exact name of registrant as specified in its charter)

Registrant's Telephone Number, Including Area Code: (303) 298-8100

        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

        As of July 31, 2002, 18,977,775 shares of the Registrant's Common Stock, no par value, were outstanding.

EVERGREEN RESOURCES, INC.
INDEX

PART I. FINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

EVERGREEN RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS

See accompanying notes to consolidated financial statements.

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

See accompanying notes to consolidated financial statements.

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

See accompanying notes to consolidated financial statements.

EVERGREEN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

See accompanying notes to consolidated financial statements.

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

See accompanying notes to consolidated financial statements.

EVERGREEN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of June 30, 2002
(Unaudited)

1.

Basis of Presentation

        Evergreen Resources, Inc. ("Evergreen" or the "Company") 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. The Company has also begun coal bed methane projects in the United Kingdom and Alaska. In addition, the Company is engaged in the exploration of natural gas prospects in Northern Ireland and the Republic of Ireland and owns additional interests in other domestic and international areas.

        Consolidation

        The financial statements include the accounts of Evergreen and its wholly-owned subsidiaries, Evergreen Operating Corporation, Evergreen Resources (UK) Ltd, Evergreen Well Service Company, Primero Gas Marketing Company, Primero Gas Company, LLC, XYZ Minerals, Inc., Evergreen Resources (Alaska) Corporation, Long Canyon Gas Company, LLC and Evergreen Supply and Distribution Company. The Company also has a majority-owned subsidiary, Lorencito Gas Gathering, LLC.

        The Company 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, 2001. 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, 2002 and 2001 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. The results of operations for interim periods are not necessarily indicative of results to be expected for a full year.

2.

Oil and Gas Properties

        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 the activities. 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. 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.

3.

Earnings per Share

        The following tables set forth the computation of basic and diluted earnings per share:

4.

Derivatives and Hedging Activities

        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 minimize the risks using the most effective methods to eliminate or reduce the impacts of these exposures.

        The Company periodically 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 designated as cash flow hedges. To qualify as a cash flow hedge, these derivative contracts must be designated as cash flow hedges and changes in their fair value must correlate with changes in the price of anticipated future production such that the Company's exposure to the effects of commodity price changes is reduced.

        At June 30, 2002, the Company had entered into the following natural gas swap and costless collar contracts by contract period. ("MMBtu" means million British thermal units.) The contracts are based on regional price indexes where the Company physically delivers its natural gas.

*

Represents average floor and ceiling prices

        As of June 30, 2002, the Company had recorded net unrealized gains of $896,000 which represented the estimated aggregate fair values of the Company's open derivative contracts as of that date. These gains are presented on the balance sheet as a current asset of $741,000, a non-current asset of $1,039,000 and a current liability of $884,000. The fair values of the derivatives 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. Based on the calculated fair values at June 30, 2002, the Company expects to reclassify net losses of $143,000 into earnings related to the derivative contracts during the next twelve months. Actual gains or losses recognized may be materially different than what was estimated at June 30, 2002 and will depend solely on the regional price indexes of the commodities on the specified settlement dates provided by the derivative contracts.

        The Company recognized $6,061,000 and $6,008,000 in net losses related to its natural gas swaps and collars during the three and six months ended June 30, 2002 compared to gains of $3,251,000 and $2,975,000 during the three and six months ended June 30, 2001 on the natural gas swaps the Company had in place during the first six months of 2001. These gains and losses are included in natural gas revenues in the Consolidated Statements of Income for each period presented.

        In April 2001, the Company entered into an interest rate swap designated as a cash flow hedge to manage fluctuations in cash flows resulting from interest rate risk. The interest rate swap had a notional amount of $25 million at a London InterBank Offered Rate ("LIBOR") of 4.4% and was effective April 23, 2001 through April 23, 2002. The Company recognized losses of $51,000 and $215,000 on the contract during the three and six months ended June 30, 2002 and recognized a $9,000 loss during the three and six months ended June 30, 2001. These losses are included in interest expense in the Consolidated Statements of Income for each period presented.

        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.

5.

Related Party Transaction

        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 Pegasus Technologies, Inc. subsidiary ("Pegasus"), representing an approximate 8.8% as converted interest in Pegasus, for $1.5 million. Under the terms of the agreement, KFx was required to repurchase the interest on January 31, 2002 unless Evergreen elected to extend it to January 1, 2003. Evergreen extended the

repurchase date to January 1, 2003 in consideration for the option to purchase additional convertible preferred stock in Pegasus for $1.2 million through January 1, 2003. On May 1, 2002, KFx repurchased the convertible preferred stock from the Company for $2.0 million plus accrued interest.

        In connection with the purchase of the convertible preferred on February 9, 2001, Evergreen was provided with a five-year warrant to purchase 1 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.

        The President and Chief Executive Officer of Evergreen is on the board of directors of KFx, and the Chief Financial Officer of Evergreen is on the board of directors of Pegasus.

6.

Supplemental Disclosures of Cash Flow Information

        Cash paid during the six months ended June 30, 2002 and 2001 for interest was approximately $3.8 million and $3.7 million. During the six months ended June 30, 2002 and 2001, approximately $0.7 million and $0.5 million of interest was capitalized.

7.

Notes Payable and Senior Convertible Notes

        In May 2002, the Company extended its $200 million revolving credit facility with a bank group (the "Banks") from July 1, 2003 to 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 LIBOR, plus a margin of 1.125% to 1.50%, or the prime rate plus a margin of 0% or 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 unused facility fee equal to 0.375% is charged quarterly for any unused portion of the credit line. The agreement is collateralized by 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, 2002, Evergreen had $130 million of outstanding borrowings under this credit facility, with an average interest rate of 3.4%.

        In December 2001, the Company issued $100 million in senior unsecured convertible notes. The notes 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 interest discussed above, 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 exceeds 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 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 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 $50 conversion price or if the average trading value 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 common shares 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 and 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.

8.

Recent Accounting Pronouncements

        On January 1, 2002, the Company adopted Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standards ("SFAS") No. 142, "Goodwill and Other Intangible Assets" and SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." The adoption of these statements has not had a material effect on the Company's financial statements.

        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 is effective for fiscal years beginning after June 15, 2002. Management is currently evaluating the impact of the adoption of this statement and accordingly has not quantified the impact on the Company's financial statements.

        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," to eliminate an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. This statement also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. This statement is effective for fiscal years beginning after May 15, 2002. The Company does not expect the adoption of this statement to 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 is effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. The Company does not expect the adoption of this statement to 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.

General

        Evergreen Resources, Inc. ("Evergreen" or the "Company") 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. The Company also has begun coal bed methane projects in the United Kingdom and Alaska. In addition, the Company is engaged in the exploration of natural gas prospects in Northern Ireland and the Republic of Ireland and owns additional interests in other domestic and international areas.

Developments

Mid-Year Proven Reserves

        Evergreen increased its proven reserves 8% during the first six months of 2002 to an estimated 1.134 trillion cubic feet ("Tcf") of natural gas as of June 30, 2002, up from 1.051 Tcf at year-end 2001. Evergreen added 101.3 billion cubic feet ("Bcf") of gas reserves and produced 18.3 Bcf during the first six months of 2002. The reserve increase was due entirely 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, 68% of which were classified as developed as of June 30, 2002. The mid-year 2002 reserve estimate was based on a total of 1,164 gas wells, including 333 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% ("PV10"), was $825 million before income taxes as of June 30, 2002. Using guidelines established by the Securities and Exchange Commission, the calculation for the mid-year 2002 reserve estimate was based on an unescalated average net gas price of $2.77 per thousand cubic feet ("Mcf"),

reflecting prevailing gas prices at June 30, 2002. The 2001 year-end PV10 calculation of $598 million used a gas price of $2.32 per Mcf.

        Because of the volatile history of natural gas prices, certain hypothetical present value calculations were also performed using various gas price scenarios. Using an unescalated net gas price of $3.50 per Mcf (the NYMEX equivalent of approximately $3.85 per Mcf), the PV10 of Evergreen's proven reserves at June 30, 2002 would have been $1.2 billion before income taxes. At $4.00 per Mcf (the NYMEX equivalent of approximately $4.35 per Mcf), Evergreen's PV10 reserve value would have been $1.4 billion before income taxes as of June 30, 2002.

Domestic Operations

Raton Basin

        Evergreen drilled a total of 101 gas wells in the Raton Basin from the beginning of the year through June 30, 2002. During July 2002, the Company drilled an additional 13 gas wells, bringing the year-to-date total to 114 as of July 31, 2002. Evergreen originally planned to drill a total of 152 wells in 2002. However, Evergreen will increase its 2002 drilling program to as many as 165 wells due in part to the results of production testing and gas shows encountered during drilling operations on the Company's five deeper test wells drilled in the Raton Basin during 2001. The additional wells will be targeted to deeper unconventional gas formations, which include upper and middle Cretaceous-age targets, and will be drilled in the fourth quarter of 2002 and early 2003. The total depth of the deeper wells will be approximately 4,000 feet to 7,000 feet. Daily net sales from the Raton Basin for the month of July 2002 were approximately 109.7 MMcf of gas.

Alaska

        In 2001, the Company acquired a 100% working interest in approximately 64,000 gross acres of prospective coal bed methane properties in Alaska. The acreage is located in the Cook Inlet-Susitna Basin approximately 30 miles north of Anchorage. Using equipment of its wholly owned well service subsidiary, Evergreen plans to drill a total of eight wells beginning in September 2002. The wells will be drilled in two pilot areas in groups of four wells each. Completion and production testing operations are expected to follow in the fourth quarter of 2002.

International Operations

United Kingdom

        The Company has completed its drilling program for the year on its United Kingdom acreage in the Cheshire Basin. Two coal mine methane (gob gas) wells were completed to depths of 1,496 feet and 1,965 feet. Preliminary production tests indicate that both of these wells are capable of commercial production. The Company is performing reservoir pressure testing to establish a recoverable reserve estimate and sustainable production flow rates. Also during the second quarter the Company completed fracture stimulation of an interaction well (a well drilled into the fractured area surrounding an abandoned coal mine) at Sutton Manor, which was drilled to a depth of 1,453 feet. A progressive cavity pump is being installed with production testing to follow. The Company also fracture stimulated two interaction wells at Cronton, which were drilled in 2001, adding productive zones. Production testing on these interaction wells is expected to begin in the third quarter of 2002.

        Ireland

        The Company has completed fracture stimulation operations on five of its six tight gas sand wells in Northern Ireland and the Republic of Ireland. Bottom hole pressure tests and production tests on all five wells are currently being performed. Evergreen expects to complete the testing of these wells and set temporary bridge plugs at the end of 2002's third quarter.

        The results of the bottom hole pressure tests and production tests on the five wells have been mixed. Evergreen is reviewing the data to determine locations for drilling additional wells in 2003 or 2004. The Company plans to initiate a seismic data program in 2003.

Results of Operations—Three and Six Months Ended June 30, 2002 Compared to the Three and Six Months Ended June 30, 2001

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

*

Includes the effects of hedging

        The Company reported net income of $3.3 million or $0.17 per diluted share for the three months ended June 30, 2002, compared to net income of $11.2 million or $0.57 per diluted share for the same period in 2001. For the six months ended June 30, 2002, the Company reported net income of $5.7 million or $0.29 per diluted share compared to net income of $26.1 million or $1.35 per diluted share in 2001. The decrease in net income during the three and six months ended June 30, 2002, as compared to the prior year periods, was primarily attributable to decreases in the average realized gas prices as discussed below.

        Natural gas revenues decreased to $23.3 million during the three months ended June 30, 2002, from $32.6 million for the same period in the prior year. During the six months ended June 30, 2002, natural gas revenues decreased to $43.5 million from $70.4 million for the same period in the prior year. The decreases in natural gas revenues for the three and six month periods ended June 30, 2002 compared to the same periods in 2001, were due to 45% and 52% decreases in average realized natural gas prices to $2.45 and $2.37 per Mcf in 2002 from $4.49 and $4.95 per Mcf in 2001. The decreases in average realized natural gas prices were partially offset by increases in production.

        Net gas production for the three and six months ended June 30, 2002 increased to 9.5 Bcf and 18.3 Bcf or an average of 104.4 and 101.2 MMcf per day, from 7.3 Bcf and 14.2 Bcf or an average of 79.8 MMcf and 78.6 MMcf per day for the comparable periods in 2001.

        Approximately 90% of Evergreen's net production during the second quarter of 2002 was either sold under fixed-price contractual arrangements or hedged using financial instruments, resulting in an averaged hedged price of approximately $2.39 per Mcf. The Company recognized $6.1 million and $6.0 million in net losses related to its financial hedges during the three and six months ended June 30, 2002, compared to gains of $3.3 million and $3.0 million during the three and six months ended June 30, 2001.

        Evergreen had 754 net producing gas wells at June 30, 2002 compared to 593 at June 30, 2001. Evergreen drilled 101 coal bed methane wells and one water disposal well in the Raton Basin during the first six months of this year compared to 80 coal bed methane wells in the first six months of 2001.

        Lease operating expenses for the three months ended June 30, 2002 were $4.0 million or $0.42 per Mcf compared to $2.8 million or $0.38 per Mcf for the same period in 2001. During the six months ended June 30, 2002, lease operating expenses were $7.6 million or $0.42 per Mcf as compared to $5.3 million or $0.37 per Mcf for the same period in the prior year. The increases of $1.2 million and $2.4 million for the three and six months ended June 30, 2002 from 2001 were primarily due to increases in personnel, well repairs, and compressor maintenance for three major overhauls and compressor rental costs. These increases were partially offset by decreases in water disposal costs, water testing, and contract labor.

        Production and property taxes for the three months ended June 30, 2002 increased to $1.4 million or $0.15 per Mcf from $1.2 million or $0.16 per Mcf for the same period in 2001. For the six months ended June 30, 2002, production and property taxes were $2.6 million or $0.14 per Mcf as compared to $2.8 million or $0.20 per Mcf for the same period in the prior year. The decreases on a per-Mcf basis in both periods were due to the decreases in the average realized natural gas prices in 2002 as compared with 2001.

        Depreciation, depletion and amortization expense for the three months ended June 30, 2002 was $5.2 million compared to $3.9 million for the same period in 2001. On an equivalent Mcf basis, depreciation, depletion and amortization expense was $0.55 per Mcf for the three months ended June 30, 2002 as compared to $0.54 per Mcf for the same period in the prior year. During the six months ended June 30, 2002, depreciation, depletion and amortization expense was $10.0 million or $0.55 per Mcf as compared to $7.5 million or $0.52 per Mcf for the same period in the prior year.

        General and administrative expenses were $2.4 million during the three months ended June 30, 2002, as compared to $2.1 million during the same period in 2001. For the six months ended June 30, 2002, general and administrative expenses were $4.6 million as compared to $3.6 million for the same period in the prior year. The increase over 2001 was due to an increase in general and administrative personnel, salaries, related benefits, an increase in rent expense due to additional office space leased in April 2001 and other increases in office expense, professional services, travel, conferences and public information. General and administrative expense on a per-unit of production basis was $0.25 per Mcf for both the three and six months ended June 30, 2002, compared to $0.29 and $0.25 per Mcf in the same periods in 2001.

        Interest expense was $2.0 million for the three months ended June 30, 2002 and 2001. During the six months ended June 30, 2001, interest expense was $4.0 million compared to $4.5 million in the first half of the prior year. Although average debt balances were higher in the second quarter of 2002 compared to the second quarter of 2001, interest expense remained relatively consistent due to a reduction in average interest rates from approximately 7.1% during the first six months of 2001 to 4.6% during the first six months of 2002.

        The Company provided for deferred income taxes for the six months ended June 30, 2002 at an effective rate of 35.5%. For the first six months of 2001, the Company provided for deferred income taxes at an effective rate of 38%. The decrease in the tax rate is primarily due to Colorado income tax credits the Company now expects to be able to utilize. The tax credits resulted from the Company's development activities in the Raton Basin.

Liquidity and Capital Resources

        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 London InterBank Offered Rate ("LIBOR") plus a margin of 1.125% to 1.50% or the prime rate plus a margin of 0% or 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, 2002, Evergreen had $130 million of outstanding borrowings under this credit facility, with a current average interest rate of approximately 3.4%.

        As the Company continues to grow and expand, management believes that additional capital may be required to fund development of its projects. On April 23, 2002, the Company filed a shelf registration statement with the SEC providing for the offering to the public from time to time of debt securities, common or preferred stock or other securities with an aggregate offering amount of up to $300 million. The Company plans to use the proceeds from possible sales of securities for general corporate purposes, which could include debt repayment, working capital, capital expenditures or acquisitions.

        The Company also filed an acquisition shelf registration statement on April 23, 2002 with the SEC providing for the offering of the Company's common stock in connection with acquisitions of other businesses and assets. The aggregate offering amount under the acquisition shelf registration statement is $50 million.

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

Capital Requirements

        The Company expects to continue to utilize cash from operations as well as its available funds under its revolving credit facility to fund capital expenditures and working capital obligations during 2002. As of July 31, 2002, the Company had $72 million available under its revolving credit facility. Future cash flows will be influenced, among other factors, by the market price of natural gas as well as the number of producing properties on line. To the extent that gas prices decline, the Company's revenues, cash flows and earnings would be adversely affected, which would require the Company to rely more heavily on its revolving credit facility to fund its 2002 capital budget. The Company's management believes that if gas prices were to decline to a level that would have a material adverse effect on cash flows, the Company would continue to meet its working capital obligations and its 2002 capital budget (as discussed below) through its capacity on the revolving credit facility.

        The Company's 2002 capital budget is $106.1 million. Of this total, the Company plans to direct approximately $87.9 million to Evergreen's coal bed methane operations in the Raton Basin, which includes approximately $31.2 million for infrastructure and gas collection, approximately $36.6 million for the drilling and completion of 165 wells and $20.1 million primarily for recompletions and equipment. Approximately $9.6 million of the 2002 capital budget is expected to be spent on the Company's coal bed methane project in the United Kingdom and tight gas sand project in Northern Ireland and the Republic of Ireland, and the remaining $8.6 million largely will be used for domestic exploration projects.

        Capital additions in the first six months of 2002 totaled $69.5 million. These additions included $22.8 million on drilling and completion activities in the Raton Basin, $7.6 million primarily for recompletions, $23.7 million for the Raton Basin gas collection system, $1.2 million for domestic exploration projects and $7.8 million for international exploration projects. The remaining amount of

$6.4 million was primarily related to the Company's wholly-owned well service company, including the subsidiary's purchase of a second fleet of fracture stimulating and cementing units.

Cash Flows

        Cash flows provided by operating activities were $12.7 million for the six months ended June 30, 2002, as compared to $57.0 million for the same period in 2001. The decrease of $44.3 million was primarily due to a $33.3 million decrease in net income before taxes in the first six months of 2002 as compared to the first six months of 2001. The decrease in net income was primarily due to the reduction of realized gas prices in 2002 as compared to 2001. The remaining difference in cash flows provided by operating activities was primarily attributable to the $13.4 million fluctuation in the changes in operating assets and liabilities.

        Cash flows used in investing activities were $63.0 million during the six months ended June 30, 2002, versus $54.5 million in the first six months of 2001. The increase in 2002 was primarily due to the costs associated with the drilling of 102 wells through June 2002 compared to 80 wells through June 2001.

        Cash flows provided by financing activities during the six months ended June 30, 2002 were $49.9 million compared to $0.6 million in the first six months of 2001. The increase of $49.3 million was primarily attributable to the decrease in cash flows from operating activities of $44.3 million. This $44.3 million decrease was primarily due to the decrease in realized gas prices in 2002 as compared to 2001. The reduction in cash flows from operations resulted in the Company having to use proceeds from its revolving credit facility to fund its investment in property and equipment.

Derivatives and Hedging

        The Company periodically enters into agreements 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.

        At June 30, 2002, the Company had the following open derivative contracts in place: ("MMBtu" means million British thermal units.)

*

Represents average floor and ceiling prices

        As of June 30, 2002, the Company had recorded net unrealized gains of $896,000 which represented the estimated aggregate fair values of the Company's open derivative contracts as of that date. The fair values of the derivatives 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. Based on the calculated fair values at June 30, 2002, the Company expects to reclassify net losses of $143,000 into earnings related to these derivative contracts during the next twelve months. Actual gains or losses recognized may be

materially different than what was estimated at June 30, 2002 and will depend solely on the regional price indexes of the commodities on the specified settlement dates provided by the derivative contracts.

        The following table provides a reconciliation of the fair value of the Company's open derivative commodity contracts at December 31, 2001 to the fair value at June 30, 2002:

        In addition to the derivative contracts discussed above, the Company had the following physical delivery contracts in place at June 30, 2002.

•

a maximum of 4,000 MMBtu per day from July 1, 2002 through April 30, 2003 at an average price of $2.34 per MMBtu plus transportation costs, and



•

10,000 MMBtu per day from July 1, 2002 through March 31, 2003 for the lesser of current market price or a gross price of $2.45 per MMBtu.

Recent Accounting Pronouncements

        On January 1, 2002, the Company adopted Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standards ("SFAS") No. 142, "Goodwill and Other Intangible Assets" and SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." The adoption of these statements has not had a material effect on the Company's financial statements.

        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 is effective for fiscal years beginning after June 15, 2002. Management is currently evaluating the impact of the adoption of this statement and accordingly has not quantified the impact on the Company's financial statements.

        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", to eliminate an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. This statement also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. This statement is effective for fiscal years beginning after May 15, 2002. The Company does not expect the adoption of this statement to 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 is effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. The Company does not expect the adoption of this statement to have a material effect on the Company's financial statements.

ITEM 3.    QUANTATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

        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 United States 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 production and the percent of gas hedged remained unchanged, a hypothetical 10% decline in prevailing market prices would reduce the Company's natural gas revenues by approximately $3.6 million on an annual basis.

        Interest Rate Risk.    At June 30, 2002, 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, 2002, range from LIBOR 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 June 30, 2002 would equal approximately 34 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 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.

        Approximately $10 million of the 2002 capital budget is expected to be spent on the Company's coal bed methane project in the United Kingdom and tight gas sand project in Northern Ireland and the Republic of Ireland. Any significant change in the exchange rate for the British pound sterling and/or euro would have an impact on the cost of the foreign exploration projects.

PART II. OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

        There are no material pending legal proceedings to which the Company or its subsidiaries is a party or to which any of their property is subject.

ITEM 2.    CHANGES IN SECURITIES AND USE OF PROCEEDS

        Not applicable.

ITEM 3.    DEFAULTS UPON SENIOR SECURITIES

        Not applicable.

ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

        The following summarizes the votes at the Company's Annual Meeting of Shareholders held on May 7, 2002:

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

Ratification of the appointment of BDO Seidman, LLP as independent auditors for the year ending December 31, 2002

ITEM 5.    OTHER INFORMATION

        Not applicable.

ITEM 6.    EXHIBITS AND REPORTS ON FORM 8-K

(a)

Exhibits.

        10.1 Second Amended and Restated Credit Agreement, dated effective as of May 31, 2002 among Evergreen Resources, Inc., as borrower, and Hibernia National Bank, as Administrative Agent and Syndication Agent, BNP-Paribas, as Documentation Agent and the Banks

        99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

        99.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

(b)

Reports on Form 8-K.

None

SIGNATURES

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

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