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TABLE OF CONTENTS
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

FORM 10-K

Commission file number 0-13171

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

(303) 298-8100
(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

None

        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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K, is not contained herein and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

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

        As of March 27, 2003, the Registrant had 19,078,019 common shares outstanding. As of June 30, 2002, the aggregate market value of the common shares held by non-affiliates was approximately $756 million based upon the closing price of $42.50 per share for the common stock on June 28, 2002, as reported on the New York Stock Exchange.

        DOCUMENTS INCORPORATED BY REFERENCE: DEFINITIVE PROXY MATERIALS FOR 2003 ANNUAL MEETING OF STOCKHOLDERS—PART III, ITEMS 10, 11, 12, AND 13.

TABLE OF CONTENTS

CERTAIN DEFINITIONS

        The following are definitions of terms commonly used in the oil and natural gas industry and this document.

        Unless otherwise indicated in this document, natural gas volumes are stated at the legal pressure base of the state or area in which the reserves are located at 60 (degrees) Fahrenheit. As used in this document, the following terms have the following specific meanings: "Mcf" means thousand cubic feet, "MMcf" means million cubic feet, "Bcf" means billion cubic feet, "Tcf" means trillion cubic feet, and "MMBtu" means million British thermal units.

        Average finding cost.    The amount of total capital expenditures, including acquisition costs, and exploration and abandonment costs, for oil and natural gas activities divided by the amount of proved reserves added in a specified period.

        Coal Bed Methane ("CBM").    A form of natural gas, predominately methane, which is generated during coal formation and is contained in the coal microstructure.

        Capital expenditures.    Investment outlays for exploratory and development drilling (including exploratory dry holes); leasehold acquisitions; seismic data acquisitions; geological, geophysical and land related overhead expenditures; delay rentals; producing property acquisitions; other miscellaneous capital expenditures; compression equipment and pipeline costs.

        Developed acreage.    The number of acres which are allocated or assignable to producing wells or wells capable of production.

        Development well.    A well drilled within the proved area of an oil or natural gas reservoir to the depth of a producing horizon known to be productive.

        Exploratory well.    A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.

        Coal Mine Gas.    Methane that has collected in abandoned underground coal mines.

        Gross acres or gross wells.    The total acres or wells, as the case may be, in which the Company has a working interest.

        Lease Operating Expenses ("LOE").    All operating costs related to production activities including direct costs such as direct labor, direct materials, certain workover costs, repairs and maintenance, insurance costs, and gas collection costs.

        Mine gas interaction well.    A well drilled into the fractured area surrounding an abandoned underground coal mine.

        Net acres or net wells.    A net acre or well is deemed to exist when the sum of the Company's fractional ownership working interests in gross acres or wells, as the case may be, equals one. The number of net acres or wells is the sum of the fractional working interests owned in gross acres or wells, as the case may be, expressed as whole numbers and fractions thereof.

        Operator.    The individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.

        Present value of future net revenues or PV-10.    The present value of estimated future net revenues to be generated from the production of proved reserves, net of estimated production and ad valorem taxes, future capital costs and operating expenses, using prices and costs in effect as of the

date indicated, without giving effect to federal and state income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their "present value." The present value reflects the effect of time on the present value of the revenue stream. PV-10 should not be construed as being representative of the fair market value of the properties.

        Recompletion.    The deepening of a well to another horizon or attempting to secure production from a shallower horizon.

        Reserves.    Natural gas and crude oil, condensate and natural gas liquids on a net revenue interest basis, estimated to be commercially recoverable. "Proved developed reserves" include proved developed producing reserves and proved developed behind-pipe reserves. "Proved developed producing reserves" include only those reserves expected to be recovered from existing completion intervals in existing wells. "Proved undeveloped reserves" include those reserves expected to be recovered from new wells on proved undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

        Undeveloped acreage.    Lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether or not such acreage contains proved reserves.

        Working interest.    An interest in an oil and natural gas lease that gives the owner of the interest the right to drill and produce oil and natural gas on the leased acreage and requires the owner to pay their proportionate share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to governmental tax receipts and mineral interest royalties.

PART I

ITEM 1. BUSINESS

General

        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. The Company has also begun a coal bed methane project in southern Alaska.

        Evergreen maintains its principal executive offices at 1401 17th Street, Suite 1200, Denver, Colorado 80202; telephone (303) 298-8100. The Company's website is www.evergreengas.com. The Company makes available free of charge on its website its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC.

        The authorized capitalization of the Company is 50,000,000 shares of no par value common stock, of which 19,052,737 shares were issued and outstanding at December 31, 2002, and 24,900,000 shares of $1.00 par value preferred stock, none of which were issued and outstanding at December 31, 2002.

        This report on Form 10-K contains 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, (v) the outcome of litigation and the impact of governmental regulation, (vi) financial market conditions, (vii) wars and acts of terrorism or sabotage and (viii) the risks 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, 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 are discussed under the heading "Business—Certain Risks." 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.

        For a discussion of the development of the Company's business, see Item 2 and for a discussion of the assets by geographic area, see Note 14 to the Consolidated Financial Statements.

Business Activities

Recent Developments

        Subsequent to December 31, 2002, Evergreen's Board of Directors has authorized a significant increase in the Company's capital expenditure budget for 2003 in anticipation of potential targeted company and asset acquisitions of unconventional natural gas properties in North America. The Company is in various stages of negotiations to complete one or more acquisition transactions within

the first six months of 2003. The Company is in the final stages of negotiations with respect to a stock-for-stock acquisition of a company whose reserves and revenues represent approximately seven percent and thirteen percent of the combined company's reserves and revenues, respectively, on a pro-forma basis. This transaction would be subject to the satisfactory completion of due diligence, shareholder approval by the acquired company's shareholders and other customary conditions. The successful completion of certain other contemplated transactions is dependent upon, among other things, the Company emerging as the winning bidder in a competitive bid process, completion of negotiations, and satisfactory results of due diligence procedures on the transactions. At this time no assurances can be given that any one or more of these potential transactions will be completed.

Raton Basin

        The Company's current operations are principally focused on developing and expanding its coal bed methane project located in the Raton Basin in southern Colorado.

        The Company is one of the largest holders of oil and gas leases in the Raton Basin. Evergreen holds interests in approximately 325,000 gross acres of coal bed methane properties in the Basin. At December 31, 2002, the Company had estimated net proved reserves of 1.24 Tcf, 64% of which were proved developed, with a PV-10 of approximately $1.6 billion. The Company's net daily gas sales for the month of December 2002 were approximately 114 MMcf from a total of 837 net producing wells. Evergreen's Raton Basin drilling program has enabled the Company to build an extensive inventory of additional drilling locations. The Company has identified at least 700 additional drilling locations on its Raton Basin acreage, of which 377 were included in its estimated proved reserve base at December 31, 2002. The Company operates and has a 100% working interest in substantially all of its Raton Basin acreage and wells.

        Since Evergreen began its drilling efforts in the Raton Basin, the Company has drilled more than 650 wells and achieved a success rate of approximately 98%. In addition, the Company has acquired over 250 producing wells in the Raton Basin since the beginning of the Raton Basin project. From March 31, 1995 through December 31, 2002, Evergreen grew its estimated proved reserves from 58 Bcf to 1,239 Bcf, which represents a compound annual growth rate of approximately 48%. During the same period, the Company's net daily gas sales increased from just over 1 MMcf to approximately 114 MMcf.

        Management believes the Company's success in the Raton Basin has enabled Evergreen to become one of the lowest-cost finders, developers and producers among U.S. publicly traded independent oil and gas companies. From the beginning of the Company's Raton Basin project through December 31, 2002, the Company has spent approximately $330 million on the drilling and completion of its wells, pipelines, gas collection systems and compression equipment, and $244 million on the acquisition of additional properties. This represents an estimated total finding and development cost of $0.33 per proved Mcf excluding acquisitions and $0.44 per proved Mcf including acquisitions.

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. Evergreen began drilling operations in Alaska in late October 2002. By year-end, the Company had drilled two four-well pilot projects. All eight wells penetrated coal seams with aggregate thicknesses in excess of 100 feet. Completion and production testing operations are expected to be completed in the spring of 2003.

Impairment of International Properties

        During the year ended December 31, 2002, the Company recorded impairment charges of $51.5 million related to property interests in the United Kingdom, Northern Ireland, the Republic of Ireland, the Falkland Islands and Chile.

United Kingdom

        The drilling and evaluation program for 2002 included the hydraulic fracture stimulation of multiple coal seams in three mine gas interaction wells ("interaction wells"), the drilling of three coal mine methane wells (gob gas wells) and one interaction well as well as production testing on several existing coal bed methane wells.

        During the second quarter of 2002, the fracture stimulation work was completed on the three interaction wells with production testing completed in the third quarter of 2002. The resulting production was not significant enough for commercial production and therefore, the wells were temporarily shut-in.

        The 2002 drilling program yielded positive results with two coal mine methane wells that are capable of commercial production, with estimated daily rates in the range of 500 Mcf to 750 Mcf of gas per well. These wells are currently shut-in, pending pipeline construction and negotiations (gas purchase contract, gas price and take-or-pay volume) with several end-users.

        The production testing of the CBM wells did not produce consistent daily rates in excess of 20 Mcf to 50 Mcf. A reasonable possibility exists that these wells may, over the long term, achieve satisfactory production rates. However, the Company has concluded that the slow desorption and dewatering of the coals using vertically drilled and conventionally fracture stimulated wellbores will take an excessive time period to recover economic reserves. This is due primarily to the very low permeability and slow diffusivity rates of the UK Westphalian-age coals. Because the vertical well concept did not appear to yield economic production rates, the Company in the summer of 2002 began investigating the use of "horizontal branched lateral wells" for the CBM project. The horizontal well concept had worked in similar age and coal rank-wells in the Mid-Continent and Appalachian Basin in the United States. Generally, through a vertical wellbore, the horizontal laterals radiate out from the vertical wellbore, intersecting the natural fractures and permeability of single or multiple coal seams. The horizontal laterals pattern can drain up to 1,200 acres versus an average 160-acre drainage from a vertical well bore. Horizontal wells do not require fracture stimulation. The horizontal well concept may work in the UK for a number of reasons. The unknown variables for the concept are as follows: cost, production rate, production profile, recovery factors, hole stability and artificial lift of produced water.

        The Company had completed production testing on substantially all wells in the third quarter of 2002. Because of the results previously described, the Company recorded a partial impairment to the asset value of the United Kingdom properties in the third quarter of 2002. Subsequent to September 30, 2002, the Company believed there was sufficient value and interest by other entities in the coal mine methane gas wells and the horizontal lateral well concept that a value of $15 to $16 million would be realized through a corporate or asset transaction. However, a transaction could not be completed to allow Evergreen to exit the United Kingdom without extensive ongoing involvement from Evergreen technical personnel. Therefore, due to an unfavorable regulatory environment, high capital costs, the lack of infrastructure for oil and gas development and delays in approval processes, the Company determined to redirect its efforts to North America, and as such the Company will not invest any additional funds for the development of the horizontal lateral well concept or the drilling of additional coal mine methane wells. As a result, the Company recorded an impairment of approximately $17.2 million in the fourth quarter of 2002, representing the remaining carrying value of the UK properties at December 31, 2002. The United Kingdom properties are being

offered for sale, and the Company expects any remaining international operations to conclude by the end of 2003's second quarter.

Northern Ireland and the Republic of Ireland

        During the quarter ended September 30, 2002, Evergreen completed its evaluation of the five wells drilled in Northern Ireland and the Republic of Ireland. In the first and second quarter of 2002, the wells were hydraulic fracture stimulated. The Company completed its production testing and determined that estimated gas production from the Mullaghmore and Dowra sandstone were not at a level that would provide an adequate return to the Company. Therefore, the Company recorded an impairment against the carrying value of $13.7 million, net of a foreign currency gain of approximately $1.0 million. The five remaining wells in Northern Ireland and the Republic of Ireland are in the process of being plugged and abandoned and the licenses are also being relinquished.

Other International

        Evergreen is maintaining its interest in the Falkland Islands and in Chile but was unable to determine when these projects would be drilled or monetized. As a result, an impairment of $4.7 million was taken in the third quarter of 2002 to eliminate the carrying value of these assets.

        The Company plans to concentrate its development efforts primarily in North America, including the continental United States, Alaska and Canada.

Business Strategy

        The Company's objective is to enhance shareholder value by increasing reserves, production, cash flow, earnings and net asset value per share. To accomplish this objective, the Company intends to capitalize on its experience and operating expertise in coal bed methane properties and on its other competitive strengths, which include:

•

an extensive inventory of drilling locations;



•

a track record for significantly growing the Company's reserve base through development drilling and acquisitions; and



•

an industry leading position as a low-cost finder, developer and producer of natural gas.

Customers and Markets

        Gas Marketing.    Primero Gas Marketing Company ("Primero") is a wholly-owned subsidiary of the Company that was formed to market and sell natural gas for the Company and third parties. To date, Primero has marketed and sold gas only on behalf of the Company, royalty interest and working interest partners. Primero also operates the Company's gas collection systems and purchases all the Company's production from its Raton Basin wells.

        Gas production from the Raton Basin is transported by Colorado Interstate Gas Co. ("CIG") through the Campo Lateral, a 115 mile, 16-inch pipeline, and the Picketwire Lateral, which is a 10-inch and 20-inch looped line that connects to CIG's main pipeline system and permits Evergreen to sell its gas into the Mid-Continent markets.

        Current Raton Basin gas sales total approximately 208 MMcf per day. Takeaway capacity on the CIG system from the Raton Basin is currently estimated at 290 MMcf per day. The Company expects that the extra capacity of approximately 82 MMcf per day is sufficient to accommodate the expected growth in its sales volumes in the future.

        The Company's current firm transportation commitments are 112 MMcf of gross gas sales per day. In addition, the Company has committed to an additional 15 MMcf per day, subject to a ramp-up schedule which anticipates 5 MMcf per day increments each four months from June 2003 through February 2004. Thus, Evergreen's total transportation commitments will increase in increments to a total of 127 MMcf gross gas sales per day by February 2004.

        Major Customers.    Evergreen has three major customers, Xcel Energy and subsidiaries, Natural Gas Transmission Services, Inc., and West Texas Gas, which purchased approximately 29%, 28% and 13%, respectively, of the Company's gas production for the year ended December 31, 2002. Based on the general demand for gas, the Company does not believe that a loss of any or all of these customers would have a material adverse effect on Evergreen's business. Currently, the Company's gas is sold at spot market prices or under short-term contracts.

        Competition.    The Company competes in virtually all facets of its business with numerous other companies, including many that have significantly greater resources. Such competitors may be able to pay more for desirable leases and to evaluate, bid for and purchase a greater number of properties than the financial or personnel resources of the Company permit. The ability of the Company to increase reserves in the future will be dependent on its ability to select and acquire suitable producing properties and prospects for future exploration and development. The availability of a market for oil and natural gas production depends upon numerous factors beyond the control of producers, including but not limited to the availability of other domestic or imported production, the locations and capacity of pipelines, and the effect of federal and state regulation on such production.

Government Regulation of the Oil and Gas Industry

        General.    The Company's business is affected by numerous laws and regulations, including, among others, laws and regulations relating to energy, environment, conservation and tax. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of injunctive relief or both. Moreover, changes in any of these laws and regulations could have a material adverse effect on the Company's business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to the Company, the Company cannot predict the overall effect of such laws and regulations on its future operations.

        The Company believes that its operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on the Company's method of operations than on other similar companies in the energy industry.

        The following discussion contains summaries of certain laws and regulations and is qualified in its entirety by the foregoing.

        Federal Regulation of the Sale and Transportation of Oil and Gas.    Various aspects of the Company's oil and natural gas operations are regulated by agencies of the Federal government. The Federal Energy Regulatory Commission ("FERC") regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 ("NGA") and the Natural Gas Policy Act of 1978 ("NGPA"). In the past, the Federal government has regulated the prices at which oil and gas could be sold. While "first sales" by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead sales in the natural gas industry began with the enactment of the NGPA in 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act (the "Decontrol Act"). The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

        Commencing in April 1992, the FERC issued Orders Nos. 636, 636-A, 636-B, 636-C and 636-D ("Order No. 636"), which require interstate pipelines to provide transportation services separate, or "unbundled," from the pipelines' sales of gas. Also, Order No. 636 requires pipelines to provide open access transportation on a nondiscriminatory basis that is equal for all natural gas shippers. Although Order No. 636 does not directly regulate the Company's production activities, the FERC has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry. It is unclear what impact, if any, increased competition within the natural gas industry under Order No. 636 will have on the Company's activities.

        The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the FERC continues to review and modify its open access regulations. In particular, the FERC is conducting a broad review of its transportation regulations, including how they operate in conjunction with state proposals for retail gas marketing restructuring, whether to eliminate cost-of-service rates for short-term transportation, whether to allocate all short-term capacity on the basis of competitive auctions, and whether changes to long-term transportation policies may also be appropriate to avoid a market bias toward short-term contracts. In February 2000, the FERC issued Order No. 637 amending certain regulations governing interstate natural gas pipeline companies in response to the development of more competitive markets for natural gas and natural gas transportation. The goal of Order No. 637 is to "fine tune" the open access regulations implemented by Order No. 636 and to accommodate subsequent changes in the market. Key provisions of Order No. 637 include: (1) waiving the price ceiling for short-term capacity release transactions until September 30, 2002, subject to review and possible extension of the program at that time; (2) permitting value-oriented peak/off peak rates to better allocate revenue responsibility between short-term and long-term markets; (3) permitting term-differentiated rates, in order to better allocate risks between shippers and the pipeline; (4) revising the regulations related to scheduling procedures, capacity, segmentation, imbalance management, and penalties; (5) retaining the right of first refusal ("ROFR") and the five-year matching cap for long-term shippers at maximum rates, but significantly narrowing the ROFR for customers that the FERC does not deem to be captive; and (6) adopting new website reporting requirements that include daily transactional data on all firm and interruptible contracts and daily reporting of scheduled quantities at points or segments. The new reporting requirements became effective September 1, 2000. The Company cannot predict what action the FERC will take on these matters in the future, nor can it accurately predict whether the FERC's actions will, over the long term, achieve the goal of increasing competition in markets in which the Company's natural gas is sold. However, the Company does not believe that it will be affected by any FERC-related action in a materially different manner than other natural gas producers and marketers with which it competes.

        Commencing in October 1993, the FERC issued a series of rules (Order Nos. 561 and 561-A) establishing an indexing system under which oil pipelines will be able to change their transportation rates, subject to prescribed ceiling levels. The indexing system, which allows pipelines to make rate changes to track changes in the Producer Price Index for Finished Goods, minus one percent, became effective January 1, 1995. The Company does not believe that, if it were to produce crude oil, these rules would affect the Company any differently than other oil producers and marketers with which it would compete.

        The FERC has also issued numerous orders confirming the sale and abandonment of natural gas gathering facilities previously owned by interstate pipelines and acknowledging that if the FERC does not have jurisdiction over services provided thereon, then such facilities and services may be subject to regulation by state authorities in accordance with state law. A number of states have either enacted new laws or are considering the adequacy of existing laws affecting gathering rates and/or services. Other state regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation.

Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in the future. The Company's gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services, although the Company does not believe that it would be affected by such regulation any differently than other natural gas producers or gatherers. In addition, the FERC's approval of transfers of previously regulated gathering systems to independent or pipeline affiliated gathering companies that are not subject to FERC regulation may affect competition for gathering or natural gas marketing services in areas served by those systems and thus may affect both the costs and the nature of gathering services that may be available to interested producers or shippers in the future.

        The Company owns certain natural gas pipeline facilities that it believes meet the traditional tests the FERC has used to establish a pipeline's status as a gatherer not subject to the FERC's jurisdiction. Whether on state or federal land, natural gas gathering may receive greater regulatory scrutiny in the post-Order No. 636 environment.

        The Company conducts certain operations on federal oil and gas leases, which are administered by the Minerals Management Service ("MMS"). Federal leases contain relatively standard terms and require compliance with detailed MMS regulations and orders, which are subject to change. Among other restrictions, the MMS has regulations restricting the flaring or venting of natural gas, and the MMS has proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Under certain circumstances, the MMS may require any company operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect the Company's financial condition, cash flows and operations. The MMS issued a final rule that amended its regulations governing the valuation of crude oil produced from federal leases. This rule, which became effective June 1, 2000, provides that the MMS will collect royalties based on the market value of oil produced from federal leases. The lawfulness of the new rule has been challenged in federal court. Evergreen cannot predict whether this new rule will be upheld in federal court, nor can the Company predict whether the MMS will take further action on this matter. However, the Company does not believe that, if it were to produce crude oil, this new rule would affect it any differently than other producers and marketers of crude oil.

        Additional proposals and proceedings that might affect the oil and gas industry are pending before Congress, the FERC, the MMS, state commissions and the courts. The Company cannot predict when or whether any such proposals and proceedings may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, the Company does not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon the capital expenditures, earnings or competitive position of the Company or its subsidiaries. No material portion of Evergreen's business is subject to re-negotiation of profits or termination of contracts or subcontracts at the election of the Federal government.

        Bureau of Land Management.    Of the Company's Raton Basin acreage, approximately 136,000 gross acres are held within three federal units that the Company operates and that are administered by the Federal Bureau of Land Management ("BLM"). See "Item 2. Properties—Raton Basin Properties and Operations." Inclusion of property within a unit simplifies lease maintenance for the Company and promotes orderly development.

        The BLM controls isolated parcels of federally owned surface and/or minerals in the Raton Basin. Drilling and development of federal minerals and construction activities on federal surface are subject to the National Environmental Policy Act ("NEPA"). BLM has completed an environmental assessment under NEPA. To date, 15 coal bed methane wells have been drilled on BLM minerals. All future wells are expected to be approved based on the results of the environmental assessment. Development of

adjacent fee lands and minerals has proceeded unhindered. Access to fee lands has not been hindered by the presence of isolated parcels of federal surface. The number of proposed wells on BLM minerals represents approximately seven and one-half percent of the total number of wells Evergreen has planned to drill in the Raton Basin during 2003.

        State Regulation.    The Company's operations are also subject to regulation at the state level and, in some cases, county, municipal and local governmental levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used and produced in connection with operations. The Company's operations are also subject to various conservation laws and regulations. These include: (1) proration units; (2) the density of wells that may be drilled; and (3) the unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, which generally limit the venting or flaring of gas and impose certain requirements regarding the ratability of production. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, but (except as noted above) does not generally entail rate regulation. These regulatory burdens may affect profitability, and the Company is unable to predict the future cost or impact of complying with such regulations.

        Environmental Matters.    The Company is subject to extensive federal, state and local environmental laws and regulations that, among other things, regulate the discharge or disposal of materials or substances into the environment and otherwise are intended to protect the environment. Numerous governmental agencies issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial administrative, civil and/or criminal penalties and, in some cases, injunctive relief for failure to comply. Some laws, rules and regulations relating to the protection of the environment may, in certain circumstances, impose "strict liability" for environmental contamination. Such laws render a person or company liable for environmental and natural resource damages, cleanup costs and, in the case of oil spills in certain states, consequential damages without regard to negligence or fault. Other laws, rules and regulations may require the rate of oil and natural gas production to be below the economically optimal rate or may even prohibit exploration or production activities in environmentally sensitive areas. In addition, state laws often require some form of remedial action such as closure of inactive pits and plugging of abandoned wells to prevent pollution from former or suspended operations. Legislation has been proposed and continues to be evaluated in Congress from time to time that would reclassify certain oil and gas exploration and production wastes as "hazardous wastes." This reclassification would make such wastes subject to much more stringent and expensive storage, treatment, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant adverse impact on the operating costs of the Company, as well as the oil and gas industry in general. Initiatives to regulate further the disposal of oil and gas wastes are also proposed in certain states from time to time and may include initiatives at county, municipal and local government levels. These various initiatives could have a similar adverse impact on the Company. The regulatory burden on the oil and natural gas industry increases its cost and risk of doing business and consequently affects its profitability.

        Compliance with these environmental requirements, including financial assurance requirements and the costs associated with the cleanup of any spill, could have a material adverse effect upon the Company's capital expenditures, earnings or competitive position. The Company believes that it is in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on it. Nevertheless, changes in environmental laws and regulations have the potential to adversely affect Evergreen's operations. For example, the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended ("CERCLA"), also known as the "Superfund" law, imposes liability,

without regard to fault (i.e., strict and joint and several liability) or the legality of the original conduct, on certain classes of persons with respect to the release of a "hazardous substance" into the environment. These persons include the current or prior owner or operator of the disposal site or sites where the release occurred and companies that transported, disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for the federal or state government to pursue such claims. It is also not uncommon for neighboring landowners and other third parties to file claims for personal injury or property or natural resource damages allegedly caused by the hazardous substances released into the environment. Under CERCLA, certain oil and gas materials and products are, by definition, excluded from the term "hazardous substances." At least two federal courts have held that certain wastes associated with the production of crude oil may be classified as hazardous substances under CERCLA. Similarly, under the federal Resource, Conservation and Recovery Act of 1976, as amended ("RCRA"), which governs the generation, treatment, storage and disposal of "solid wastes" and "hazardous wastes," certain exploration and production wastes are exempt from the definition of "hazardous wastes." This exemption continues to be subject to judicial interpretation and increasingly stringent state interpretation. During the normal course of the Company's operations, the Company generates or has generated in the past exempt and non-exempt wastes, including hazardous wastes, that are subject to RCRA and comparable state statutes and implementing regulations. The federal Environmental Protection Agency ("EPA") and various state agencies continue to promulgate regulations that limit the disposal and permitting options for certain hazardous and non-hazardous wastes.

        The Company currently owns or leases, and has in the past owned or leased, several properties that have long been used to store and maintain oil and gas exploration and production equipment. In particular, current and prior operations of the Company included oil and gas production in the Rocky Mountain states and the portion of the Permian Basin that lies within the State of New Mexico. Although the Company utilized operating and disposal practices that were standard for the industry at the time, hydrocarbons, materials and/or solid or hazardous wastes may in the past have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where such wastes have been taken or placed for disposal. In addition, many of these properties have from time to time been operated by third parties whose management of hydrocarbons, hazardous materials and/or solid or hazardous wastes was not under the Company's control. These properties and the hydrocarbons, materials or wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws and regulations. Under such laws and regulations, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination).

        In connection with the Company's coal bed methane gas production, the Company from time to time conducts production enhancement techniques, including various activities designed to induce hydraulic fracturing of the coal bed. While the Company performs its production enhancement techniques in substantial compliance with the requirements set forth by the State of Colorado, neither Colorado nor EPA regulates this coal bed formation hydraulic fracturing as a form of underground injection. It is possible that hydraulic fracturing of coal beds for methane gas production will become regulated within the United States as a form of underground injection, resulting in the imposition of stricter performance standards (which, if not met, could result in diminished opportunities for methane gas production enhancement) and increased administrative and operating costs for the Company. Evergreen's management cannot predict whether potential future regulation of hydraulic fracturing as a form of underground injection would have an adverse material effect on the Company's operations or financial position. However, such regulation is not expected to be any more burdensome to the Company than it would be to other similarly situated companies involved in coal bed methane gas production or tight gas sands production within the United States.

        In Evergreen's coal bed methane gas production, the Company typically brings naturally occurring groundwater to the surface as a by-product of the production of methane gas. This "produced water" is either re-injected into the subsurface or stored or disposed of in evaporation ponds or permitted natural collection features located on the surface at or near the well-site in compliance with federal and state statutes and regulations. In some cases, the produced water is used for stock watering, agricultural or dust suppression purposes, also in substantial compliance with federal, state and local laws and regulations. Under the Clean Water Act and various other state requirements and regulations, EPA and the State of Colorado's Department of Public Health and the Environment ("CDPHE") assert administrative and regulatory enforcement authority over the discharge of produced water. Where the Company can meet federal and state regulatory requirements and applicable water quality standards, disposal of produced water by discharge to surface water is an option.

        The Company's operations involve the use of gas-fired compressors to transport collected gas; these compressors are subject to federal and state regulations for the control of air emissions. The Company has obtained construction permits for additional compression in excess of current needs in anticipation of increased production from the Raton Basin. However, in the future, additional facilities could become subject to additional monitoring and pollution control requirements as compressor facilities are expanded.

        At this time, the Company has no plans to make any material capital expenditures for environmental control facilities.

        Although the Company maintains insurance against some, but not all, of the risks described above, including insuring the costs of clean-up operations, public liability and physical damage, there is no assurance that such insurance will be adequate to cover all such costs, that such insurance will continue to be available in the future or that such insurance will be available at premium levels that justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on the Company's financial condition and operations.

Title to Properties

        As is customary in the oil and gas industry, only a preliminary title examination is conducted at the time the Company acquires leases of properties believed to be suitable for drilling operations. Prior to the commencement of drilling operations, a thorough title examination of the drill site tract is conducted by independent attorneys. Once production from a given well is established, the Company prepares a division order title report indicating the proper parties and percentages for payment of production proceeds, including royalties. The Company believes that the titles to its leasehold properties are good and defensible in accordance with standards generally acceptable in the oil and gas industry.

Employees

        At February 28, 2003, the Company had 273 full-time employees.

Certain Risks

Oil and gas prices are volatile, and an extended decline in prices would hurt the Company's profitability and financial condition.

        Evergreen's revenues, operating results, profitability, future rate of growth and the carrying value of its oil and gas properties depend heavily on prevailing market prices for oil and gas. Management of the Company expects the markets for oil and gas to continue to be volatile. Any substantial or extended decline in the price of oil or gas would have a material adverse effect on the Company's financial condition and results of operations. Such a decline could reduce the Company's cash flow and

borrowing capacity, as well as the value and the amount of its gas reserves. All of Evergreen's proved reserves are natural gas. Therefore, the Company is more directly impacted by volatility in the price of natural gas. Various factors beyond the Company's control can affect prices of oil and gas, including:

•

worldwide and domestic supplies of oil and gas,



•

the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls,



•

political instability or armed conflict in oil or gas producing regions,



•

the price and level of foreign imports,



•

worldwide economic conditions,



•

marketability of production,



•

the level of consumer demand,



•

the price, availability and acceptance of alternative fuels,



•

the availability of pipeline capacity,



•

weather conditions, and



•

actions of federal, state, local and foreign authorities.

        These external factors and the volatile nature of the energy markets make it difficult to estimate future commodity prices.

        The Company periodically reviews the carrying value of its oil and gas properties under the full cost accounting rules of the Securities and Exchange Commission. Under these rules, capitalized costs of proved oil and gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenue at the unescalated prices in effect as of the end of each fiscal quarter and requires a write-down for accounting purposes if the ceiling is exceeded, even if prices were depressed for only a short period of time. The Company may be required to write down or impair the carrying value of its oil and gas properties when oil and gas prices are depressed or unusually volatile. If a write-down is required, it would result in a charge to earnings, and book value but would not impact cash flow from operating activities. Once incurred, a write-down of oil and gas properties is not reversible at a later date.

The Company's operations require large amounts of capital.

        Evergreen's current development plans will require it to make large capital expenditures for the exploration and development of its natural gas properties. Historically, Evergreen has funded its capital expenditures through a combination of funds generated internally from sales of production or properties, the issuance of equity, long-term debt financing and short-term financing arrangements. Management cannot be sure that any additional financing will be available to the Company on acceptable terms. Future cash flows and the availability of financing will be subject to a number of variables, such as:

•

the success of the Company's coal bed methane project in the Raton Basin,



•

the Company's success in locating and producing new reserves,



•

the level of production from existing wells, and



•

prices of oil and natural gas.

        Issuing equity securities to satisfy the Company's financing requirements could cause substantial dilution to existing shareholders. Debt financing could lead to:

•

a substantial portion of the Company's operating cash flow being dedicated to the payment of principal and interest,



•

the Company being more vulnerable to competitive pressures and economic downturns, and



•

restrictions on the Company's operations.

        If the Company's revenues were to decrease due to lower oil and natural gas prices, decreased production or other reasons, and if it could not obtain capital through its credit facility or otherwise, the Company's ability to execute its development plans, replace its reserves or maintain its production levels could be greatly limited.

Information concerning the Company's reserves and future net revenue estimates is uncertain.

        There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their values, including many factors beyond the control of the Company. Estimates of proved undeveloped reserves, which comprise a significant portion of the Company's reserves, are by their nature uncertain. The reserve data included in this Form 10-K are estimated. Although management believes they are reasonable, estimates of production, revenues and reserve expenditures will likely vary from actual, and these variances may be material.

        Estimates of oil and natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and natural gas prices, future operating costs, severance, ad valorem and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves. Actual production, revenues and expenditures with respect to the Company's reserves will likely vary from estimates, and such variances may be material. See "Item 2. Properties—Natural Gas Reserves."

        Analysts and investors should not construe PV-10 as the current market value of the estimated oil and natural gas reserves attributable to the Company's properties. Management has based the estimated discounted future net cash flows from proved reserves on prices and costs as of the date of the estimate, in accordance with applicable regulations, whereas actual future prices and costs may be materially higher or lower. Many factors will affect actual future net cash flows, including:

•

the amount and timing of actual production,



•

supply and demand for natural gas,



•

curtailments or increases in consumption by natural gas purchasers, and



•

changes in governmental regulations or taxation.

        The timing of the production of oil and natural gas properties and the related expenses affect the timing of actual future net cash flows from proved reserves and, thus, their actual present value. In addition, the 10% discount factor, which the Company is required to use to calculate PV-10 for reporting purposes, is not necessarily the most appropriate discount factor given actual interest rates and risks to which Evergreen's business or the oil and natural gas industry in general are subject.

The Company depends heavily on expansion and development of the Raton Basin.

        All of Evergreen's proved reserves are in the Raton Basin, and its future growth plans rely heavily on increasing production and reserves in the Raton Basin. The Company's proved reserves will decline as reserves are depleted, except to the extent the Company conducts successful exploration or development activities or acquires other properties containing proved reserves.

        At December 31, 2002, the Company had estimated net proved undeveloped reserves of approximately 443 Bcf, which constituted approximately 36% of its total estimated net proved reserves. The Company's development plan includes increasing its reserve base through continued drilling and development of its existing properties in the Raton Basin. Evergreen cannot be sure that its planned projects in the Raton Basin will lead to significant additional reserves or that it will be able to continue drilling productive wells at anticipated finding and development costs.

Future acquisitions pose risks to our business and growth prospects.

        As part of the Company's growth strategy, the Company may make acquisitions of businesses and properties. However, suitable acquisition candidates may not be available on terms and conditions the Company finds acceptable. In pursuing acquisitions, the Company competes with other companies, many of which have greater financial and other resources than Evergreen to acquire attractive companies and properties. Even if completed, the following are some of the risks associated with acquisitions that could have a material adverse effect on the Company's business, financial condition and results of operations:

•

some of the acquired businesses or properties may not produce anticipated revenues, earnings or cash flow,



•

the Company may assume liabilities that were not disclosed or exceed the Company's estimates,



•

the Company may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems,



•

acquisitions could disrupt the Company's ongoing business, distract management, divert resources and make it difficult to maintain the Company's current business standards, controls and procedures,



•

the Company may finance future acquisitions by issuing common stock for some or all of the purchase price, which could dilute the ownership interests of the Company's shareholders, and



•

the Company may incur additional debt related to future acquisitions.

The Company's industry is highly competitive.

        Major oil companies, independent producers and institutional and individual investors are actively seeking oil and gas properties throughout the world, along with the equipment, labor and materials required to operate properties. Many of the Company's competitors have financial and technological resources vastly exceeding those available to Evergreen. Many oil and gas properties are sold in a competitive bidding process in which the Company may lack the technological information or expertise

available to other bidders. The Company cannot be sure that it will be successful in acquiring and developing profitable properties in the face of this competition.

The oil and gas exploration business involves a high degree of business and financial risk.

        The business of exploring for and, to a lesser extent, developing oil and gas properties is an activity that involves a high degree of business and financial risk. Property acquisition decisions generally are based on various assumptions and subjective judgments that are speculative. Although available geological and geophysical information can provide information about the potential of a property, it is impossible to predict accurately the ultimate production potential, if any, of a particular property or well. Moreover, the successful completion of an oil or gas well does not ensure a profit on investment. A variety of factors, both geological and market-related, can cause a well to become uneconomic or marginally economic.

The Company's business is subject to operating hazards that could result in substantial losses.

        The oil and natural gas business involves operating hazards such as well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks, any of which could cause the Company a substantial loss. In addition, the Company may be held liable for environmental damage caused by previous owners of property it owns or leases. As a result, the Company may face substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development or acquisitions or cause Evergreen to incur losses. An event that is not fully covered by insurance—for example, losses resulting from pollution and environmental risks, which are not fully insurable—could have a material adverse effect on the Company's financial condition and results of operations.

Exploratory drilling is an uncertain process with many risks.

        Exploratory drilling involves numerous risks, including the risk that the Company will not find any commercially productive natural gas or oil reservoirs. The cost of drilling, completing and operating wells is often uncertain, and a number of factors can delay or prevent drilling operations, including:

•

unexpected drilling conditions,



•

pressure or irregularities in formations,



•

equipment failures or accidents,



•

adverse weather conditions,



•

compliance with governmental requirements, and



•

shortages or delays in the availability of drilling rigs and the delivery of equipment.

        The Company's future drilling activities may not be successful, nor can Evergreen management be sure that the Company's overall drilling success rate or its drilling success rate for activity within a particular area will not decline. Unsuccessful drilling activities could have a material adverse effect on the Company's results of operations and financial condition. Also, Evergreen may not be able to obtain any options or lease rights in potential drilling locations that it identifies. Although the Company has identified numerous potential drilling locations, management cannot be sure that Evergreen will ever drill them or that it will produce natural gas from them or any other potential drilling locations.

Hedging transactions may limit the Company's potential gains or expose the Company to loss.

        To manage Evergreen's exposure to price risks in the marketing of its natural gas, the Company enters into natural gas fixed-price physical delivery contracts as well as commodity price-swap contracts from time to time with respect to a portion of its current or future production. While intended to reduce the effects of volatile natural gas prices, these transactions may limit the Company's potential gains if natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose Evergreen to the risk of financial loss in certain circumstances, including instances in which:

•

the Company's production is less than expected,



•

there is a widening of price differentials between delivery points for the Company's production and the delivery point assumed in the hedge arrangement,



•

the counterparties to the Company's futures contracts fail to perform the contracts, or



•

a sudden, unexpected event materially impacts natural gas prices.

The Company may face unanticipated water disposal costs.

        Management believes that the State of Colorado will continue to routinely approve permits for the use of well-site pits, water disposal wells and evaporation ponds for the disposal of produced water. Where groundwater produced from the Raton Basin coal seams meets surface discharge permit levels, Evergreen can lawfully discharge the water into arroyos and surface waters pursuant to permits it has obtained from the State of Colorado. All of these disposal options require a laboratory analysis program to ensure compliance with state permit standards. Additionally, the Company contracts with an independent water sampling company that collects the water samples and monitors the Company's water management program. These monitoring costs are directly related to the number of well-site pits, evaporation ponds and discharge points.

        Where water of lesser quality is discovered or the Company's wells produce water in excess of the applicable volumetric permit limits, Evergreen may have to drill additional disposal wells to re-inject the produced water back into deep underground rock formations. Produced water is currently injected at eight such wells, and two more of these underground injection control (UIC) wells are under development. The costs to dispose of this produced water may increase, which could have a material adverse effect on the Company's operations in this area, if any of the following occur: (1) the Company cannot obtain future permits from the State of Colorado; (2) water of lesser quality is discovered; (3) the Company's wells produce excess water; or (4) new laws or regulations require water to be disposed of in a different manner.

The Company has limited protection for its technology and depends on technology owned by others.

        The Company uses operating practices that management believes are of significant value in developing coal bed methane resources. In most cases, patent or other intellectual property protection is unavailable for this technology. The Company's use of independent contractors in most aspects of its drilling and some completion operations makes the protection of such technology more difficult. Moreover, the Company relies on the technological expertise of the independent contractors that it retains for its oil and gas operations. The Company has no long-term agreements with these contractors, and management cannot be sure that the Company will continue to have access to this expertise.

The Company's industry is heavily regulated.

        Federal, state and local authorities extensively regulate the oil and gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may affect, among other things, the pricing or marketing of oil and gas production. Noncompliance with statutes and regulations may lead to substantial penalties, and the overall regulatory burden on the industry increases the cost of doing business and, in turn, decreases profitability. State and local authorities regulate various aspects of oil and gas drilling and production activities, including the drilling of wells (through permit and bonding requirements), the positioning of wells, the unitization or pooling of oil and gas properties, environmental matters, safety standards, the sharing of markets, production limitations, plugging and abandonment, and restoration.

The Company must comply with complex environmental regulations.

        The Company's operations are subject to complex and constantly changing environmental laws and regulations adopted by federal, state and local governmental authorities. New laws or regulations, or changes to current requirements, could have a material adverse effect on its business. State, federal and local environmental agencies have relatively little experience with the regulation of coal bed methane operations, which are technologically different from conventional oil and gas operations. This inexperience has created uncertainty regarding how these agencies will interpret air, water and waste requirements and other regulations to coal bed methane drilling, fracture stimulation methods, production and water disposal operations. Evergreen will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. The Company could face significant liabilities to the government and third parties for discharges of oil, natural gas or other pollutants into the air, soil or water, and Evergreen could have to spend substantial amounts on investigations, litigation and remediation. The Company cannot be sure that existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced or altered in the future, will not materially adversely affect its results of operations and financial condition. As a result, the Company may face material indemnity claims with respect to properties it owns or leases or has owned or has leased.

The Company's business depends on transportation facilities owned by others.

        The marketability of the Company's gas production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties. Although the Company has some contractual control over the transportation of its product, material changes in these business relationships could materially affect its operations. Federal and state regulation of gas and oil production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, and general economic conditions could adversely affect the Company's ability to produce, gather and transport natural gas.

Market conditions could cause the Company to incur losses on its transportation contracts.

        The Company has gas transportation contracts that require it to transport minimum volumes of natural gas. If the Company ships smaller volumes, it may be liable for the shortfall. Unforeseen events, including production problems or substantial decreases in the price for natural gas, could cause the Company to ship less than the required volumes, resulting in losses on these contracts. See Note 12 to the Consolidated Financial Statements.

The Company depends on key personnel.

        Evergreen's success will continue to depend on the continued services of its executive officers and a limited number of other senior management and technical personnel. Loss of the services of any of

these people could have a material adverse effect on the Company's operations. The Company does not have employment agreements with its executive officers.

The Company does not pay dividends.

        The Company has never declared nor paid any cash dividends on its common stock and management has no intention to do so in the near future.

The Company's articles of incorporation and bylaws have provisions that discourage corporate takeovers and could prevent shareholders from realizing a premium on their investment.

        The Company's articles of incorporation and bylaws contain provisions that may have the effect of delaying or preventing a change in control. These provisions, among other things, provide for noncumulative voting in the election of the board and impose procedural requirements on shareholders who wish to make nominations for the election of directors or propose other actions at shareholders' meetings. Also, the Company's articles of incorporation authorize the Board to issue up to 24,900,000 shares of preferred stock without shareholder approval and to set the rights, preferences and other designations, including voting rights, of those shares as the Board may determine. These provisions, alone or in combination with each other and with the rights plan described below, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to shareholders for their common stock.

        On July 7, 1997 Evergreen's Board of Directors adopted a shareholder rights agreement, pursuant to which uncertificated stock purchase rights were distributed to shareholders of the Company at a rate of one right for each share of common stock held of record as of July 22, 1997. The rights plan is designed to enhance the Board's ability to prevent an acquirer from depriving shareholders of the long-term value of their investment and to protect shareholders against attempts to acquire Evergreen by means of unfair or abusive takeover tactics. However, the existence of the rights plan may impede a takeover of Evergreen not supported by the Board, including a takeover that may be desired by a majority of the Company's shareholders or involving a premium over the prevailing stock price.

The Company's stock price has been and is likely to continue to be volatile.

        The market price of Evergreen common stock has been volatile. During 2002, the sale price of the common stock on the NYSE has ranged from a low of $30.90 per share to a high of $47.00 per share. The market price of the Company's common stock is subject to many factors, including:

•

prices for oil and natural gas,



•

general stock market conditions,



•

conditions in the Company's industry,



•

changes in the Company's revenues and earnings, and



•

changes in analyst recommendations and projections.

ITEM 2. PROPERTIES

Operations

        The Company's wholly-owned operating subsidiary, Evergreen Operating Corporation ("EOC"), is primarily responsible for drilling, evaluation and production activities associated with various properties. As of February 28, 2003, EOC was serving as operator for approximately 900 gross producing wells owned by the Company.

        The Company believes that, as operator, it is in a better position to control costs, safety and timeliness of work as well as other critical factors affecting the economics of a well or a property, including maintaining good community relations.

        EOC presently operates wells which represent 100% of Evergreen's proved reserves.

Natural Gas Reserves

        The table below sets forth the Company's quantities of proved reserves, as audited as of December 31, 2002, 2001 and 2000 by independent petroleum engineers Netherland Sewell & Associates, Inc. ("NSAI"). All proved reserves are located in the continental U.S., and the present value of estimated future net revenues from these reserves was calculated on a non-escalated price basis discounted at 10% per year as of the periods indicated. There has been no major discovery or other favorable or adverse event that is believed to have caused a significant change in estimated proved reserves subsequent to December 31, 2002.

        Reference should be made to Note 14 (Supplemental Oil and Gas Information) to the Consolidated Financial Statements for additional information pertaining to the Company's proved oil and gas reserves. During fiscal 2002, the Company did not file any reports that included estimates of total proved net oil or gas reserves with any federal agency other than the Securities and Exchange Commission and the Department of Energy.

Sales

        The following table sets forth the Company's net natural gas sales for the periods indicated.

Average Sales Prices, Lease Operating Expenses, Transportation Costs and Production and Property Taxes

        The following table sets forth the sales price per Mcf and the lease operating expenses, transportation costs and production and property taxes per Mcf, for the periods indicated.

*

Includes effects of hedging transactions

Productive Wells

        The following table sets forth the number of gross and net producing wells the Company had as of December 31 for each of the last five fiscal year ends. The Company had no producing oil wells during the last five years.

Acreage

        At December 31, 2002, Evergreen held developed and undeveloped acreage as set forth below:

        The table above does not reflect 1,085,000 gross and net undeveloped acres held by the Company in Northern Ireland and the Republic of Ireland as of December 31, 2002, which are being relinquished in the first part of 2003. In addition, the table does not reflect approximately 369,000 gross and net undeveloped acres in the United Kingdom as of December 31, 2002, which are being held for sale or relinquished in the first part of 2003. See Note 3 to the Consolidated Financial Statements.

        The following table sets forth the expiration dates of the gross and net acres subject to domestic leases summarized in the table of undeveloped acreage.

Drilling Activities

        The Company's drilling activities for the periods indicated are set forth below:

Coal Bed Methane Versus Traditional Natural Gas

        Methane is the primary commercial component of the natural gas stream produced from traditional gas wells. Methane also exists in its natural state in coal seams. Natural gas produced from traditional wells also contains, in varying amounts, other hydrocarbons. However, the natural gas produced from coal beds generally contains only methane and, after simple dehydration, becomes pipeline-quality gas.

        Coal bed methane production is similar to traditional natural gas production in terms of the physical producing facilities and the product produced. However, the subsurface mechanisms that allow the gas to move to the wellbore and the producing characteristics of coal bed methane wells differ greatly from traditional natural gas production. Unlike conventional gas wells, which require a porous and permeable reservoir, hydrocarbon migration and a natural structural and/or stratigraphic trap, coal bed methane gas is trapped in the molecular structure of the coal itself until released by pressure changes resulting from the removal of in situ water or natural gas in the micropore system.

        Methane is created as part of the coalification process, though coals vary in their methane content per ton. In addition to residing in open spaces in the coal structure, methane is absorbed onto the inner coal surfaces. When the coal is hydraulically fracture stimulated and exposed to lower pressures through the de-watering process, the gas is released from (desorbs from) the coal. Whether a coal bed will produce commercial quantities of methane gas depends on the coal quality, its original content of gas per ton of coal, the thickness of the coal beds, the reservoir pressure, the rate at which gas is released from the coal (diffusivity) and the existence of natural fractures and cleating (permeability) through which the released gas can flow to the wellbore. Frequently, coal beds are partly or completely saturated with water. As the water is produced, internal pressures on the coal are decreased, allowing the gas to desorb from the coal and flow to the wellbore. Unlike traditional gas wells, new coal bed methane wells often produce water for several months and then, as the water production decreases, natural gas production increases as the coal seams de-water.

        In order to establish commercial gas production rates, a permanent conduit between the individual coal seams and the wellbore must be created. This is accomplished by hydraulically creating, and propping open with special quality sand, artificial fractures within the coal seams (known as "fracing" in the industry) so the pathway for water and gas migration to the wellbore is enhanced. These fractures are filled (propped) with uniform sized sand and become the enhanced conduits for water and methane to reach the well. The rate at which the gas is released from the coal and the ability of gas to move through the coal to the wellbore are the key determinants of the rate at which a well will produce.

Raton Basin Properties and Operations

        The Raton Basin covers an area that is approximately 80 miles long, north to south, and about 50 miles wide, east to west, encompassing southeastern Colorado and northeastern New Mexico. The Raton Basin contains two coal-bearing formations, the Vermejo formation coals located at depths of between 450 and 4,000 feet and the shallower Raton formation coals, located at the surface to approximately 3,000 feet in depth. Production from the Vermejo coals represents approximately 75% of the total production from the Raton Basin and approximately 70% of the total proved reserves in the Raton Basin. To date, the majority of Evergreen's production has been from the Vermejo formation coals; however, the Raton formation coal seams and interbedded sandstones are now being successfully developed as well.

Development History

        Exploration for coal bed methane began in the Raton Basin in the late 1970s and continued through the late 1980s, with several companies drilling and testing more than 100 wells during this period. The absence of a pipeline to transport gas from the Raton Basin prevented full-scale development until January 1995, when CIG completed the construction of the Picketwire Lateral.

        Since December 1991, the Company has acquired oil and gas leases covering approximately 325,000 gross acres in the Raton Basin. The initial 70,000 acres were acquired in 1991, and additional acreage was purchased from individual owners under various lease terms. The Company has also increased its acreage positions and production through several acquisitions beginning in 1998 through 2001.

        Evergreen has a 100% working interest in three federal units, the Spanish Peaks Unit, the Cottontail Pass Unit and the Sangre de Cristo Unit. The total gross acreage in the federal units is approximately 136,000 acres. The Company is the named operator for all of these units. Formation of a unit simplifies lease maintenance so that the Company, as the operator, can base development decisions within the unit on technical, geologic and geophysical data and operational and cultural considerations rather than on the fulfillment of lease term obligations.

        Because of the inclusion of federal leases in the unit, administration within a federal unit is governed by federal rules. Production from any well in the unit area will maintain all of the leases beyond their primary terms. In October 1997, the first "participating area" was designated by the federal Bureau of Land Management under the Unit Agreement. Gas production in the participating area is pooled and shared by the royalty owners, overriding royalty owners and working interest owners in that area in proportion to their acreage ownership of the mineral estate in the area. The participating area is adjusted annually to encompass additional acreage as additional wells are completed.

        Evergreen also has working interests of between 75% and 100% in areas adjacent to the federal units, which include the Long Canyon and Lorencito areas and the Primero, Rita, Sarcillo and Weston tracts. These areas comprise approximately 189,000 gross acres.

Raton Basin Geology

        Evergreen produces coal bed methane from the high quality bituminous coal resource of the Raton Basin. The Basin is a large asymmetric sedimentary trough that developed along the western margin of an ancient Rocky Mountain seaway during the Cretaceous and Tertiary period between 65 to 45 million years ago. Today, the geologic history of what was once a lush tropical coastline and alluvial plain cut by meandering rivers, which subsequently underwent deep burial, tectonism, igneous intrusion, and uplift, is recorded in the rocks of the region; the continued exploration of the Basin by Company geologists is increasing the understanding of the coal bed methane resource base and identifying new hydrocarbon systems and additional unconventional reservoir types.

        The Company's current acreage sits squarely in the middle of the Basin and contains some of the thickest documented net coal packages in the region. The coal-bearing strata are located primarily in two major groups, the Vermejo and Raton formations, and represent coal development in two slightly contrasting environments. The Vermejo coals represent peat accumulation on an expansive flat-lying flood-plain which was partially protected from erosion by sandy coastal barriers of the underlying Trinidad Sandstone, while the Raton coals represent peat development on a broad, open, humid alluvial fan. Collectively, both formations reflect the development of substantial peat swamps and thick boggy mires, which covered most of the region during Cretaceous and Tertiary times. Subsequent burial under high pressures and temperatures has caused the original peat accumulation to convert into coal, which has high rank and consequentially high gas storage capacity. During burial, small fractured surfaces (cleats) developed throughout the coal, which, coupled with the tectonic forces acting on the region during the building of the Rocky Mountains, has provided significant permeability within the coals, allowing for the extraction of coal bed methane gas and associated water.

        Today the Company produces methane from approximately 900 wells that are generally completed in the laterally continuous Vermejo coals. Individual Vermejo coal seams can be readily traced over several miles, commonly from well to well. Total net Vermejo coal thickness can locally approach 35 feet in five to 15 individual seams, which may vary in thickness from one to 10 feet.

        The shallower Raton formation coals are generally less continuous from well to well, but increasingly represent a very significant resource throughout the Basin. Total net Raton coal thickness locally approaches 90 feet in 10 to 25 individual seams, which may vary in thickness from one to 15 feet. Commonly interbedded with the Raton coals are large sandstone channel complexes, which are increasingly identified as additional potential tight-gas and unconventional sand reservoirs.

Deep Fractured Shales, Raton Conglomerate and Sandstone reservoirs

        In 2002, the Company embarked on a series of detailed geological studies and drilled exploratory wells aimed at evaluating additional unconventional reservoir systems throughout the Raton Basin. These ongoing studies have focused efforts on gas-charged sandstones and conglomerates interbedded

within the currently producing Vermejo and Raton formation coals and deeper gas-bearing shales, which underlie the entire region.

        The conglomerate and sandstones currently being identified (and actively produced in several parts of the Company's acreage), reflect stacked large scale meandering river channel complexes and regional sandy braided alluvial fans that at one time crosscut the Cretaceous—Tertiary peat swamps. During burial, excess gas generated during the coalification process locally became trapped within the pore spaces of these sandstones and now form "Tight-Gas Sand" reservoirs. The increasing recognition of the orientation in the subsurface of such ancient drainage system is allowing the strategic sighting of wells in specific sand prone areas, which may ultimately increase the region's total resource base.

        The Raton Basin shales, termed the Niobrara and Pierre Shale formations, are approximately 3,000-feet thick and underlie the currently producing intervals. The shales collectively reflect deposits of blanket-like organic rich mudstones, which accumulated in quiet water condition on the sea floor. Deeper exploratory test wells (2,000 to 6,000 feet) aimed at identifying areas of enhanced fracture permeability may ultimately lead to the development of a significant "Shale Gas" resource.

Coal Bed Methane Technology

        Thin multi-layer coal bed methane and unconventional tight-gas reservoirs create a multitude of challenges for drilling, reservoir and production engineers, including the challenge of minimizing formation damage and then isolating and completing individual zones in order to maximize recovery of the resource in place. Management believes that the Company has developed highly effective procedures for drilling and completing such reservoirs.

        Damage to the Raton Basin coals from conventional drilling mud systems invading the cleat fracture surfaces and reducing their permeability has been mitigated by utilizing specialized air-drilling techniques using percussion air-hammers.

        All coals in the Raton Basin require hydraulic fracture stimulation to attain economic production rates. Through its wholly-owned subsidiary, Evergreen Well Service Company ("EWS"), the Company has developed technology that the Company believes is at the leading edge of coal bed methane well completions. The new technology uses proprietary high quality nitrogen foamed fluids as the fracturing media and the industry's first "built-for-purpose" 2⁷/8-inch diameter coiled tubing fracturing units to selectively place proppant in individual seams. The Company believes that this fracturing technology demonstrates its commitment to the continued role that technology innovation will play in developing some of the region's resources.

Water Production and Disposal

        Based on the Company's experience in coal bed methane production in the Raton Basin and extensive laboratory analysis of water samples taken from its coal bed methane wells, management believes that the groundwater produced from the Raton Basin coal seams will not exceed permit levels and will be suitable for discharge into arroyos, surface water, well-site pits or evaporation ponds pursuant to permits obtained from the State of Colorado. Recent gas analyses confirm that the gas stream is 99% pure methane and lacks other hydrocarbon sources of contamination. In some cases the water is of such quality that it can be discharged to arroyos and surface water under general water discharge permits issued to the Company by the State of Colorado. These permits give Evergreen the flexibility to add water discharge points on an as-needed basis with minimal administrative paperwork and within 30 days or less of application. Evergreen has in excess of 300 approved discharge points and has received an increase in the total volume of water permitted for surface discharge. Approval of these requests is uncertain and is dependent upon completion of additional study by the State of Colorado. Additionally, the Company contracts with an independent water sampling company that collects the water samples and monitors all the Company's water management program. These

monitoring costs are directly related to the number of well-site pits, evaporation ponds and discharge points. Because it originates in a natural groundwater system, there is some uncertainty whether water currently being discharged to streams and arroyos will continue to meet permit standards for total iron and suspended solids. Water not meeting these discharge standards can be disposed of in well-site pits and evaporation ponds. When water of lesser quality is discovered or Evergreen's wells produce water in excess of the applicable permit limits, the Company may have to drill additional disposal wells to re-inject the produced water into deeper sandstone horizons. Such drilling and disposal would require the Company to obtain permits, similar to those obtained in the past.

Raton Basin Production

        Evergreen's natural gas sales from the Raton Basin did not commence until the completion of a pipeline system in January 1995, which connected its Raton Basin wells to the CIG pipelines. From January 1995 through December 2002, the Company sold an aggregate of approximately 122 Bcf of coal bed methane gas from the Raton Basin. Evergreen's net daily gas sales at March 15, 2003 were averaging approximately 120 MMcf. Because of the importance of removing water from the coal seams to enhance gas production, the Company expects to continue production from more modest wells because of the beneficial ambient effect of pressure reduction in adjacent, more productive wells. Each well creates its own "cone of depression" around the wellbore. The Company believes that some of its Raton Basin wells on adjacent 160-acre sites have already created overlapping cones of depression, enhancing gas production in each well within this pattern. In some cases this pattern of interference can be enhanced by drilling a fifth and sixth well in the 640-acre section.

        Raton Basin gas contains insignificant amounts of contaminants, such as hydrogen sulfide, carbon dioxide or nitrogen, that are sometimes present in conventional natural gas production. Therefore, the properties of Raton Basin gas, such as heat content per unit volume (British Thermal units, or "Btu"), are close to the average properties of pipeline gas from conventional gas wells.

Office and Operations Facilities

        The Company leases its corporate offices in Denver, Colorado. The Company has an office lease for approximately $0.6 million per year through 2008. The Company believes its office space will be sufficient for the foreseeable future.

ITEM 3. LEGAL PROCEEDINGS

        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.

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

        Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS

Price Range of Common Stock

        Evergreen's common stock has been listed on the New York Stock Exchange under the market symbol "EVG" since September 8, 2000. Prior to that date, it was included for quotation in the Nasdaq National Market under the symbol "EVER." The following table sets forth the range of high and low sales prices per share of common stock for the periods indicated.

        As of March 14, 2003, there were approximately 1,500 holders of record of the common stock.

Dividend Policy

        The Company has not declared nor paid and does not anticipate declaring or paying any dividends on its common stock in the near future. Any future determination as to the declaration and payment of dividends will be at the discretion of the Company's board of directors and will depend on then existing conditions, including the Company's financial condition, results of operations, contractual restrictions, capital requirements, business prospects, and such other factors as the board deems relevant.

ITEM 6. SELECTED FINANCIAL DATA

        The selected consolidated financial information presented below for the years ended December 31, 1998 through 2002 is derived from the Consolidated Financial Statements of the Company.

        This information should be read in conjunction with the Consolidated Financial Statements and Notes thereto and Management's Discussion and Analysis of Financial Condition and Results of Operations. In 2002, the Company impaired approximately $51.5 million of international oil and gas properties net of a foreign currency exchange gain of approximately $1.0 million (see Note 3 to the Consolidated Financial Statements). The Company acquired certain properties effective September 2000 and included the operations of these properties in its consolidated operations beginning September 1, 2000. Effective February 18, 1999, Evergreen sold its 49% interest in Maverick Stimulation Company ("Maverick") and recorded a gain net of tax of approximately $0.5 million or $0.03 per diluted share. This transaction was accounted for as a discontinued operation and the results of operations have been excluded from continuing operations in the consolidated statements of income for all periods presented.

        Certain reclassifications have been made to prior financial statements to conform with the current presentation.

ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        The following information should be read in conjunction with the Consolidated Financial Statements and Notes presented elsewhere in this Form 10-K. The Company follows the full-cost method of accounting for oil and gas properties. See "Summary of Accounting Policies," included in Note 1 to the Consolidated Financial Statements.

General

        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. The Company has begun a coal bed methane project in southern Alaska.

        The Company had 837 net producing gas wells at December 31, 2002. The Company's average net daily natural gas sales during the month of December 31, 2002 were approximately 114 MMcf.

        The following table sets forth certain operating data of the Company for the periods presented:

*

Includes effects of hedging

Results of Operations

Year ended December 31, 2002 compared to year ended December 31, 2001

        The Company recorded a net loss of $8.3 million or $0.44 per diluted share for the year ended December 31, 2002, compared to net income of $38.5 million or $1.98 per diluted share for the year ended December 31, 2001. The decrease in net income of approximately $46.8 million compared to the prior year was due primarily to a non-cash after-tax impairment charge, net of a foreign currency gain, of $33.2 million related to the Company's international properties as discussed below.

        Natural gas revenues decreased to $111.6 million during the year ended December 31, 2002 from $119.7 million in the prior year. This decrease was due to a 26% decline in average realized natural gas prices from $3.89 per Mcf in 2001 to $2.86 per Mcf in 2002. The decrease in average realized gas prices was partially offset by a 27% increase in natural gas production. The Company recognized $6.5 million of hedging losses for the year ended December 31, 2002 compared to gains of $13.9 million during 2001. These transactions are included in natural gas sales. See "Hedging Transactions" within Liquidity and Capital Resources for more information regarding the Company's

hedging activities, including information on hedges currently in place for the years ending December 31, 2003 and 2004.

        Net gas production for the year ended December 31, 2002 increased to 39.0 Bcf or an average 106.8 MMcf per day from 30.8 Bcf or an average of 84.4 MMcf per day in the prior year. The number of net producing wells increased to 837 at December 31, 2002 from 681 at December 31, 2001. Evergreen drilled 158 coal bed methane wells in the Raton Basin during 2002 compared to 145 coal bed methane wells during 2001.

        Interest and other income decreased to $0.6 million during the year ended December 31, 2002 as compared to $1.0 million in 2001. The decrease was primarily due to the accretion of a $0.5 million discount in 2001 on convertible preferred stock that the Company purchased in February 2001. The preferred stock was redeemed in May 2002. (See Note 13 to the Consolidated Financial Statements.)

        Lease operating expenses for the year ended December 31, 2002 were $16.2 million compared to $12.2 million during 2001. While overall lease operating expenses increased by $4.0 million, lease operating expenses on a per Mcf basis remained generally consistent at $0.41 per Mcf for the year ended December 31, 2002 compared to $0.40 for the year ended December 31, 2001. The increase of $0.01 per Mcf was due primarily to $0.03 per Mcf increase in well repairs and compressor maintenance which was partially offset by a $0.02 per Mcf decrease in water disposal costs.

        Transportation costs were $12.2 million for the year ended December 31, 2002 compared to $9.5 million for the year ended December 31, 2001. On an equivalent Mcf basis, transportation costs remained consistent at $0.31 per Mcf during each period.

        For the year ended December 31, 2002, production and property taxes were $6.0 million as compared to $5.5 million in 2001. 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 hedging losses of $6.5 million for the year ended December 31, 2002 and hedging gains of $13.9 million for the year ended December 31, 2001, production and property taxes as a percent of natural gas sales were approximately 5.0% and 5.2%, respectively.

        Depreciation, depletion and amortization expense for the year ended December 31, 2002 was $20.9 million compared to $16.2 million for the year ended December 31, 2001. On an equivalent Mcf basis, depreciation, depletion and amortization expense remained generally consistent at $0.54 per Mcf during 2002 as compared to $0.53 per Mcf during 2001.

        During the year ended December 31, 2002, the Company recorded impairment charges of $51.5 million, net of a foreign currency exchange gain of approximately $1.0 million, related to property interests in the United Kingdom, Northern Ireland, the Republic of Ireland, the Falkland Islands and Chile as discussed below.

        United Kingdom:    The drilling and evaluation program for 2002 included the hydraulic fracture stimulation of multiple coal seams in three mine gas interaction wells ("interaction wells"), the drilling of three coal mine methane wells ("gob gas wells") and one interaction well, as well as production testing on several existing coal bed methane wells.

        During the second quarter of 2002, the fracture stimulation work was completed on the three interaction wells with production testing completed in the third quarter of 2002. The resulting production was not significant enough for commercial production and therefore, the wells were temporarily shut-in.

        The 2002 drilling program yielded positive results with two coal mine methane wells that are capable of commercial production, with estimated daily rates in the range of 500 Mcf to 750 Mcf of gas

per well. These wells are currently shut-in, pending pipeline construction and negotiations (gas purchase contract, gas price and take-or-pay volume) with several end-users.

        The production testing of the CBM wells did not produce consistent daily rates in excess of 50 Mcf. A reasonable possibility exists that these wells may, over the long term, achieve satisfactory production rates. However, the Company has concluded that the slow desorption and dewatering of the coals using vertically drilled and conventionally fracture stimulated wellbores will take an excessive time period to recover economic reserves. This is due primarily to the very low permeability and slow diffusivity rates of the UK Westphalian-age coals. Because the vertical well concept did not appear to yield economic production rates, the Company in the summer of 2002 began investigating the use of "horizontal branched lateral wells" for the CBM project. The horizontal well concept had worked in similar age and coal rank-wells in the Mid-Continent and Appalachian Basin in the United States. Generally, through a vertical wellbore, the horizontal laterals radiate out from the vertical wellbore, intersecting the natural fractures and permeability of single or multiple coal seams. The horizontal laterals pattern can drain up to 1,200 acres versus an average 160-acre drainage from a vertical well bore. Horizontal wells do not require fracture stimulation. The horizontal well concept may work in the UK for a number of reasons. The unknown variables for the concept are as follows: cost, production rate, production profile, recovery factors, hole stability and artificial lift of produced water.

        The Company had completed the production testing on substantially all wells in the third quarter of 2002. Because of the results previously described, the Company recorded a partial impairment of $15.9 million to the asset value of the United Kingdom properties in the third quarter of 2002. Subsequent to September 30, 2002, the Company believed there was sufficient value and interest by other entities in the coal mine methane gas wells and the horizontal lateral well concept that a value of $15 to $16 million would be realized through a corporate or asset transaction. However, a transaction could not be completed to allow Evergreen to exit the United Kingdom without extensive ongoing involvement from Evergreen's technical personnel. Therefore, due to an unfavorable regulatory environment, high capital costs, the lack of infrastructure for oil and gas development and delays in approval processes, the Company determined to redirect its efforts to North America, and as such the Company will not invest any additional funds for the development of the horizontal lateral well concept or the drilling of additional coal mine methane wells. As a result, the Company recorded an impairment of approximately $17.2 million in the fourth quarter of 2002, representing the remaining carrying value of the UK properties as of December 31, 2002. The United Kingdom properties are being offered for sale, and the Company expects any remaining international operations to conclude by the end of 2003's second quarter.

        Northern Ireland and the Republic of Ireland:    During the quarter ended September 30, 2002, Evergreen completed its evaluation of the five wells drilled in Northern Ireland and the Republic of Ireland. In the first and second quarter of 2002, the wells were hydraulic fracture stimulated. The Company completed its production testing and determined that estimated gas production from the Mullaghmore and Dowra sandstone were not at a level that would provide an adequate return to the Company. Therefore, the Company recorded an impairment against the carrying value of $13.7 million, net of a foreign currency exchange gain of approximately $1.0 million. The five remaining wells in Northern Ireland and the Republic of Ireland are in the process of being plugged and abandoned and the licenses are also being relinquished.

        Other international:    Evergreen is maintaining its interest in the Falkland Islands and in Chile but was unable to determine when these projects would be drilled or monetized. As a result, an impairment of $4.7 million was taken in the third quarter of 2002 to eliminate the carrying value of these assets.

        The impairments of the Company's international assets were based on estimates made by management using probability-weighted expected future cash flows with consideration given to plugging and abandonment liabilities and possible sales proceeds. Given the uncertainty of such estimates, it is

possible that these estimates may change in the future. The Company expects to recognize a $1.0 million foreign currency exchange gain in the first quarter of 2003 related to the exit of its United Kingdom operations.

        General and administrative expenses were $9.2 million during the year ended December 31, 2002 as compared to $7.0 million during 2001. The increase over 2001 was primarily due to a $1.2 million increase in general and administrative salaries, bonuses and related benefits. General and administrative expense on a per-unit of production basis was $0.24 for the year ended December 31, 2002 compared to $0.23 per Mcf during 2001.

        Interest expense, net of capitalized amounts, was $8.3 million during each of the years ended December 31, 2002 and 2001. Although average debt balances were higher during 2002 than during 2001, interest expense remained consistent due to a reduction in average interest rates from approximately 6.1% during 2001 to 4.4% during 2002. The increase in average borrowings was due to the funds used for the Company's exploration and development activities during 2002.

        The Company provided for deferred taxes at a rate equal to 35.5% of net loss before taxes for the year ended December 31, 2002. For the first six months of 2001, the Company provided for deferred income taxes at an effective rate of 38% and reduced the percentage to 35.5% in the third of quarter of 2001 primarily due to Colorado income tax credits the Company expected to be able to utilize on a prospective basis. The tax credits relate to the Company's development activities in the Raton Basin.

        On a quarterly basis the Company is required to review the carrying value of its oil and gas properties under the full cost accounting rules of the Securities and Exchange Commission. Under these rules, capitalized costs of proved oil and gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenue at the unescalated prices in effect as of the last day of the quarter and requires a write-down for accounting purposes if the ceiling is exceeded. At December 31, 2002, the spot price that the Company would have realized for its natural gas sales was $4.22 per Mcf. At this price level, the Company did not have a write-down as the present value of the Company's future net revenues, discounted at 10%, exceeded the Company's capitalized costs. If natural gas prices were to drop to lower levels during future periods, the Company could be required to record a write-down of its capitalized costs.

Year ended December 31, 2001 compared to year ended December 31, 2000

        Net income attributable to common stockholders was $38.5 million or $1.98 per diluted share for the year ended December 31, 2001 versus net income attributable to common stockholders of $14.1 million or $0.87 per diluted share in 2000.

        Natural gas revenues increased to $119.7 million during the year ended December 31, 2001 from $59.1 million in the prior year. The increase in natural gas revenues of $60.6 million, or 103%, was due to a 58% increase in sales volumes to 30.8 Bcf from 19.5 Bcf and a 28% increase in average gas prices to $3.89 per Mcf in 2001 from $3.03 per Mcf in 2000. The 28% increase in average gas prices was partially due to an increase in hedging gains to $13.9 million in 2001 compared to $0.3 million in 2000. The increase in sales volumes was due to increased drilling activity and to two property acquisitions, which occurred in September 2000 and June 2001, respectively. The number of net producing Raton Basin wells increased to 681 at December 31, 2001 from 491 at December 31, 2000. Net sales from drilling operations increased by 23% to 20.1 Bcf (55.1 MMcf per day) in 2001 from 16.3 Bcf (44.5 MMcf per day) in 2000. Net sales from the acquired properties increased to 10.7 Bcf in 2001 from 3.2 Bcf in 2000. The increase in the property acquisition sales was primarily due to a full year of operations of the KLT properties in 2001 versus four months in 2000 and the addition of the Lorencito properties in mid-2001. On a daily sales comparison the average daily sales from the acquired properties were 29.3 MMcf per day in 2001 versus 26.5 MMcf per day in 2000.

        Interest and other income increased to $1.0 million during the year ended December 31, 2001 as compared to $0.6 million in 2000, an increase of 81%. The increase was primarily due to the accretion of a $0.5 million discount on convertible preferred stock the Company purchased in February 2001. (See Note 13 to the Consolidated Financial Statements for more information.)

        During the year ended December 31, 2001, lease operating expenses were $12.2 million as compared to $7.5 million in the prior year. The increase in lease operating expense was due to the increase in the number of producing wells, an increase in the number of compressors, an increase in field personnel and workover costs related to well repairs. On a per Mcf basis, lease operating expenses were $0.40 per Mcf for the year ended December 31, 2001 compared to $0.38 per Mcf for the year ended December 31, 2000. The $0.02 increase was primarily attributable to a $0.02 per Mcf increase in labor costs, a $0.01 per Mcf increase in well repairs and a $0.01 per Mcf increase in compressor rentals, which were offset by a $0.02 per Mcf decrease in water disposal costs.

        Transportation costs increased $3.6 million from $5.9 million for the year ended December 31, 2000 to $9.5 million for the year ended December 31, 2001. The increase of 61% was primarily due to the 58% increase in sales volumes.

        For the year ended December 31, 2001, production and property taxes were $5.5 million or $0.18 per Mcf as compared to $2.6 million or $0.13 per Mcf in the prior year. The increase in both total dollars and cost per Mcf was primarily due to higher natural gas prices. As a percentage of natural gas sales, production and property taxes were 4.6% and 4.3% for the years ending December 31, 2001 and 2000, respectively.

        Depreciation, depletion and amortization expense for the year ended December 31, 2001 was $16.2 million versus $8.2 million in 2000. Depreciation, depletion and amortization expense increased to $0.53 per Mcf in 2001 as compared to $0.42 per Mcf in 2000. The increase in cost per Mcf was primarily due to the KLT property acquisition in September 2000, which had an acquisition cost of $1.12 per Mcf.

        General and administrative expenses were $7.0 million during the year ended December 31, 2001 versus $4.4 million in 2000. The increase in 2001 of $2.6 million was due to the expected increase in the overall growth in corporate activity. During 2001, personnel costs increased $1.2 million due to the addition of new staff, salary and bonus increases and related benefits, professional fees increased approximately $0.3 million and office expense increased $0.6 million primarily related to additional office space. Although the overall general and administrative expenses increased $2.6 million for the year ended December 31, 2001, the cost per Mcf increased only slightly to $0.23 from $0.22 in the prior year.

        Interest expense, net of capitalized amounts, was $8.3 million during the year ended December 31, 2001 as compared to $3.3 million in 2000. The $5.0 million increase for 2001 over the prior year was due to the increased average outstanding balance on the revolving credit facility in 2001 of approximately $155 million compared to approximately $53 million in 2000. The increase in the average amount outstanding on the revolving credit facility was offset by a decrease in the average interest rate on the revolving credit facility during 2001 to approximately 6%. The increase in average borrowings was due to the funds used for redemption of the mandatory redeemable preferred stock in December 2000, the KLT property acquisition in September 2000 and the accelerated development in the Raton Basin during 2001.

        Other expense of $0.7 million for the year ended December 31, 2001 included a $0.3 million charge to earnings related to the write-off of the majority of the assets of EnviroSeis, LLC, a wholly-owned 2-D seismic company.

        In connection with the KLT property acquisition in September 2000, the Company issued $100 million in redeemable preferred stock with an annual dividend rate of 9.5%. Dividends of

$2.9 million were paid during the period ended December 31, 2000. The redeemable preferred stock was redeemed on December 22, 2000 with funds from the Company's line of credit.

        The Company provided for deferred taxes for the first six months of 2001 at a rate of 38% and at a rate of 35.5% for the second half of 2001 versus 38.6% during 2000. The decrease in the tax rate was primarily due to state income tax credits the Company now expects to be able to utilize. The enterprise zone tax credits are due to the Company's development in Las Animas County. The Company had originally estimated that it would start to pay taxes in the second quarter of 2001.

Liquidity and Capital Resources

Sources and Uses

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

        The Company 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 December 31, 2002, Evergreen had $136 million of outstanding borrowings under this credit facility, with a current average interest rate of approximately 3.2%. The Company was in compliance with all loan covenants for all periods presented.

        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 2003. As of February 28, 2003, the Company had $72 million available under its line of credit. 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 could be adversely affected, which could require the Company to rely more heavily on its revolving credit facility to fund its 2003 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 2003 capital budget (as discussed below) through its capacity under the revolving credit facility. The Company has reduced its exposure to declines in natural gas prices throughout 2003 by hedging a portion of its natural gas production. See "Hedging Activities" below for more information.

        The Company's 2003 capital budget is estimated to be approximately $110.0 million. Of this total, approximately $97.1 million will be directed to Evergreen's coal bed methane operations in the Raton Basin, which includes approximately $33.4 million for infrastructure, approximately $40.6 million for the drilling and completion of 160 wells, and approximately $23.1 for recompletions and equipment. Approximately $12.9 million of the 2003 capital budget is expected to be spent on the Company's coal bed methane project in southern Alaska and other exploration projects.

        Subsequent to December 31, 2002, Evergreen's Board of Directors has authorized a significant increase in the Company's capital expenditure budget for 2003, in addition to the capital budget of $110.0 million discussed above, in anticipation of potential targeted company and asset acquisitions of unconventional natural gas properties in North America. The Company is in various stages of negotiations to complete one or more acquisition transactions within the first six months of 2003. The Company is in the final stages of negotiations with respect to a stock-for-stock acquisition of a company whose reserves and revenues represent approximately seven percent and thirteen percent of the combined company's reserves and revenues, respectively, on a pro-forma basis. This transaction would be subject to the satisfactory completion of due diligence, shareholder approval by the acquired company's shareholders and other customary conditions. The successful completion of certain other contemplated transactions is dependent upon, among other things, the Company emerging as the winning bidder in a competitive bid process, completion of negotiations, and satisfactory results of due diligence procedures on the transactions. At this time no assurances can be given that any one or more of these potential transactions will be completed. The Company believes it has sufficient ability to fund these potential acquisitions through a combination of cash flow from generated from operations, the issuance of Evergreen common stock or other securities, and increased availability under the Company's line of credit. The Company is in the process of negotiating with its bank group an increase of $100 million in the borrowing base on its existing line of credit, which increase, if received, would raise the maximum availability under the line of credit from $200 million to $300 million. In addition, the Company has filed a shelf registration with the SEC for the issuance 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. In addition, the Company has filed a shelf registration statement providing for the offering of common stock in connection with acquisitions of other businesses and assets. The aggregate offering amount under the acquisition shelf registration statement is $50 million.

Cash Flows and Capital Expenditures

        Cash flows provided by operating activities were $53.6 million for the year ended December 31, 2002 as compared to cash flows provided by operating activities of $90.1 million for the year ended December 31, 2001. The decrease of $36.5 million or 41%, was primarily attributable to a $19.0 million change in operating assets and liabilities as well as a 26% decrease in average realized gas price on a per unit basis. The year-over-year change in accounts receivable represented approximately $12.1 million of the $19.0 million change in operating assets and liabilities. This was primarily due to higher natural gas prices during December 2002 and 2000 compared to December 2001.

        Cash flows used in investing activities were $114.8 million during the year ended December 31, 2002, versus $122.5 million in 2001. The decrease of $7.7 million was primarily attributable to a sale leaseback transaction in 2002, which involved the sale a portion of the Company's well service equipment for approximately $10.0 million. This equipment is now leased under the terms of an operating lease which provides for annual payments of approximately $2.0 million over the next five years.

        Total capital expenditures for the year ended December 31, 2002 were $130.7 million. These capital costs included: $45.9 million to drill and complete 161 Raton Basin wells; $13.6 million for other Raton Basin drilling projects; $37.0 million for the Raton Basin gas collection facilities; and $24.4 million for exploration projects, consisting of $14.6 million for international projects and $9.8 million for domestic exploration, including Alaska. The remaining amount of approximately $9.8 million consisted primarily of capital expenditures by the Company's wholly-owned well service company, which included the purchase of a coiled tubing unit, two workover rigs and a second fleet of fracture stimulation and cementing units.

        Cash flows provided by financing activities were $59.0 million during the year ended December 31, 2002, as compared to cash flows provided by financing activities of $31.5 million in 2001. The increase of $27.5 was primarily attributable to the $36.5 million decrease in operating cash flows resulting in increased borrowings under the revolving credit facility.

Contractual Obligations

        In addition to the revolving credit facility discussed above, the Company had various other contractual obligations as of December 31, 2002. The following table lists the Company's significant commitments at December 31, 2002, including the revolving credit facility and the senior convertible notes:

        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 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 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 Company leases its corporate offices in Denver, Colorado under the terms of an operating lease, which expires in 2008. Yearly payments under the lease are approximately $0.6 million. The remaining operating lease commitments represent vehicle and well service equipment leases, which expire beginning in 2003 through 2007.

        At December 31, 2002, Evergreen's firm transportation commitments were 107 MMcf of gross gas sales per day. In addition, the Company had committed to an additional 20 MMcf per day, subject to a ramp-up schedule which anticipates five MMcf per day increments each four months from February 2003 through February 2004. Thus, Evergreen's total transportation commitments will increase in increments to a total of 127 MMcf gross gas sales per day by February 2004.

        At December 31, 2002, the Company had entered into agreements with a vendor to construct and deliver three gas compressors at a total cost of approximately $5.4 million.

Hedging Transactions

        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.

        At December 31, 2002, the Company had the following open derivative contracts in place (the instruments are denoted in MMBtu, which convert on an approximate 1-for-1 basis into Mcf):

        Based on the calculated fair values at December 31, 2002, the Company expects to reclassify net losses of approximately $1.4 million into the statement of operations related to the above derivative contracts during the next 12 months.

        The following table provides a reconciliation of the fair values of the Company's derivative commodity contracts at December 31, 2001 to the fair value at December 31, 2002.

        In addition to the derivative contracts discussed above, the Company had the following physical delivery contracts in place at December 31, 2002.

•

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



•

a maximum of 4,000 MMBtu per day from January 1, 2003 through April 30, 2003 at an average price of $2.54 per MMBtu plus transportation costs.

        Subsequent to December 31, 2002, the Company entered into the following commodity swap agreements:

Income Taxes and Net Operating Losses

        As of December 31, 2002, the Company had net operating loss carryforwards for tax purposes of approximately $66.8 million, which expire beginning in 2008 through 2022. Additionally, the Company

had tax credit carryforwards for tax purposes of approximately $7.3 million, $7.1 million of which relate to state tax credits and will expire beginning in 2003 through 2014.

        The state tax credits are subject to limitation, and the Company has concluded that, based upon expected future results, the future reversals of taxable temporary differences and the tax benefits derived from the exercise of employee stock options, there is no reasonable assurance that the entire tax benefit of the tax credits can be used. Accordingly, a valuation allowance has been established. See Note 6 to the Consolidated Financial Statements for categories of book and tax timing differences.

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. The adoption of this statement will require 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 will record a non-current liability of approximately $4.6 million and an addition to oil and gas properties and the gas collection system of approximately $3.9 million in connection with the adoption of this statement effective January 1, 2003.

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

        In December 2002, the FASB approved SFAS No. 148, "Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123." SFAS No. 148 amends SFAS No. 123, "Accounting for Stock-Based Compensation" to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on

reported results. The Company has adopted the disclosure requirements of SFAS No. 148 effective December 31, 2002 in its consolidated financial statements. The Company will continue to account for stock-based compensation using the methods detailed in the stock-based compensation accounting policy as described in Note 1 to the Consoldiated Financial Statements.

Critical Accounting Policies and Estimates

        The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of its Consolidated Financial Statements.

        Reserve Estimates:    The Company's estimates of oil and natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and natural gas prices, future operating costs, severance, ad valorem and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company's oil and gas properties and the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to the Company's reserves will likely vary from estimates, and such variances may be material.

        The Company's estimated quantities of proved reserves at December 31, 2002 were audited by independent petroleum engineers Netherland Sewell & Associates, Inc.

        Property, Equipment and Depreciation:    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 salaries, benefits and other internal salary-related costs directly attributable to these 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 (see Note 14 to the Consolidated Financial Statements), 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.

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

        The Company is required to review the carrying value of its oil and gas properties each quarter under the full cost accounting rules of the Securities and Exchange Commission. Under these rules, capitalized costs of proved oil and gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenue at the unescalated prices in effect as of the last day of the quarter and requires a write-down for accounting purposes if the ceiling is exceeded. Unproved oil and gas properties are not amortized, but are assessed for impairment either individually or on an aggregated basis using a comparison of the carrying values of the unproved properties to net future cash flows.

        Derivative Financial Instruments:    Effective January 2001, derivative financial instruments utilized to manage or reduce commodity price risk related to the Company's production are accounted for under the provisions of SFAS No. 133 "Accounting for Derivative Instruments and for Hedging Activities." Under this statement, all derivatives are carried on the balance sheet at fair value.

        The estimated fair values of the Company's derivative instruments require substantial judgment. The Company estimates the fair values of its commodity swaps using a discounted future cash flow technique and estimates the fair values of its commodity costless collars using the Black Scholes option-pricing model. The pricing and discounting variables used in the Company's valuations are sensitive to market volatility as well as changes in future price forecasts, regional price differentials and interest rates. Actual gains or losses recognized may be materially different than what the Company has estimated at December 31, 2002 and will depend solely on the regional price indexes of the commodities on the specified settlement dates provided by the derivative contracts.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

        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 December 31, 2002, the Company was exposed to some market risk with respect to long-term debt, foreign currency and natural gas prices; however, management did not believe such risk to be material.

        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, the percent of gas hedged and the average realized market price of the unhedged gas sold remained unchanged from the year ended December 31, 2002, a hypothetical 10% decline in the average market price the Company realized during the year ended December 31, 2002 on unhedged production would reduce the Company's natural gas revenues by approximately $3.0 million on an annual basis.

        Interest Rate Risk.    At December 31, 2002, Evergreen had long-term debt outstanding of $236 million. The interest rates on the Company's revolving credit facility, under which $136 million in indebtedness was outstanding at December 31, 2002, 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 December 30, 2002 would equal approximately 32 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 $136 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.

        The Company expects to spend only nominal amounts during 2003 for exiting 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.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES

        Not Applicable.

PART III

        The information required by Items 10, 11, 12 and 13 under Part III of Form 10-K is incorporated herein by reference to Registrant's definitive Proxy Statement to be filed in connection with the Annual Meeting of Shareholders to be held May 6, 2003.

ITEM 14. CONTROLS AND PROCEDURES

        Within 90 days prior to the date of this report, Evergreen management, including the Chief Executive Officer and Chief Financial Officer, have conducted an evaluation of the effectiveness of disclosure controls and procedures pursuant to Exchange Act Rule 13a-14. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures enable the Company to record, process, summarize and report in a timely manner the information that the Company is required to disclose in its Exchange Act reports. There have been no significant changes in the Company's internal controls, or in factors that could significantly affect internal controls, subsequent to the date the Chief Executive Officer and Chief Financial Officer completed their evaluation.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) 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.

POWER OF ATTORNEY

        KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Mark S. Sexton and Kevin R. Collins, and each of them, as true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all which said attorneys-in-fact and agents or any of them, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

CERTIFICATION PURSUANT TO
SECTION 302 OF
THE SARBANES-OXLEY ACT OF 2002

I, Mark S. Sexton, certify that:

1.

I have reviewed this annual report on Form 10-K of Evergreen Resources, Inc.

2.

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

3.

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

4.

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

a)

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

b)

evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and

c)

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

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors.

a)

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

b)

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

6.

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

Date:

CERTIFICATION PURSUANT TO
SECTION 302 OF
THE SARBANES-OXLEY ACT OF 2002

I, Kevin R. Collins, certify that:

1.

I have reviewed this annual report on Form 10-K of Evergreen Resources, Inc.

2.

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

3.

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

4.

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

a)

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

b)

evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and

c)

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

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors.

a)

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

b)

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

6.

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

Date:

Report of Independent Certified Public Accountants

To the Stockholders and Board of Directors
Evergreen Resources, Inc.
Denver, Colorado

        We have audited the accompanying consolidated balance sheets of Evergreen Resources, Inc. and subsidiaries as of December 31, 2002 and 2001 and the related consolidated statements of operations, stockholders' equity, cash flows, and comprehensive (loss) income for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Evergreen Resources, Inc. and subsidiaries at December 31, 2002 and 2001 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.

        As discussed in Note 1 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments.

/S/ BDO SEIDMAN, LLP

Houston, Texas
February 14, 2003

Evergreen Resources, Inc.

Consolidated Balance Sheets