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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)

        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. o

        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 January 31, 2004, the Registrant had 43,020,252 common shares outstanding. As of June 30, 2003, the aggregate market value of the common shares held by non-affiliates was approximately $1,011 million based upon the closing price of $27.16 per share (as adjusted to reflect Evergreen's two-for-one stock split effective September 16, 2003) for the common stock on June 30, 2003, as reported on the New York Stock Exchange.

DOCUMENTS INCORPORATED BY REFERENCE: DEFINITIVE PROXY MATERIALS FOR 2004 ANNUAL MEETING OF STOCKHOLDERS—PART III, ITEMS 10, 11, 12, 13 AND 14.

TABLE OF CONTENTS

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PART I

ITEM 1. BUSINESS

General

        Evergreen Resources, Inc. ("Evergreen" or "the Company") was incorporated in Colorado on January 14, 1981. Evergreen is an independent energy company primarily engaged in the operation, development, production, exploration and acquisition of North American unconventional natural gas properties. Evergreen is one of the leading developers of coal bed methane reserves in the United States. Evergreen's operations are principally focused on developing and expanding its coal bed methane project located in the Raton Basin in southern Colorado. Evergreen has recently acquired producing properties in the Piceance Basin in western Colorado, the Uintah Basin in eastern Utah and the Western Canada Sedimentary Basin. The Company has gas production from tight sands and shales in these newly acquired areas that it intends to enhance. The Company is also evaluating the additional coal bed methane and other gas resource potential within each of these recently acquired basins. In addition, Evergreen has initiated coal bed methane projects in the Forest City Basin in eastern Kansas and the Cook Inlet-Susitna Basin in 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 Securities and Exchange Commission ("SEC").

        The authorized capitalization of the Company is 100,000,000 shares of no par value common stock, of which 42,936,587 shares were issued and outstanding at December 31, 2003, and 24,900,000 shares of $1.00 par value preferred stock, none of which were issued and outstanding at December 31, 2003.

        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, (1) the Company's growth strategies, (2) anticipated trends in the Company's business and its future results of operations, (3) market conditions in the oil and gas industry, (4) the ability of the Company to make and integrate acquisitions, (5) the outcome of litigation and the impact of governmental regulation, (6) financial market conditions, (7) wars and acts of terrorism or sabotage and (8) 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, (1) a decline in oil and natural gas production, (2) a decline in oil and natural gas prices, (3) incorrect estimations of required capital expenditures, (4) increases in the cost of drilling, (5) completion and gas collection, (6) an increase in the cost of production and operations, (7) an inability to meet growth projections or (8) changes in general economic conditions. These and other risks are discussed under the heading "—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. Properties" and for a discussion of the oil and gas properties by geographic area, see Note 16 to the Consolidated Financial Statements.

        Reference should be made to the Glossary of Oil and Natural Gas Terms at the end of this document.

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Business Activities and Recent Developments

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 385,000 gross acres of coal bed methane properties in the Basin. At December 31, 2003, the Company had estimated net proved reserves in the Raton Basin of 1.4 Tcfe, 62% of which were proved developed, with a PV-10 of approximately $2.5 billion. The Company's net average daily gas sales from the Raton Basin for the month of December 2003 were approximately 131 MMcfe from a total of 973 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 1,000 additional drilling locations on its Raton Basin acreage, of which 468 were included in its estimated proved reserve base at December 31, 2003. The Company operates substantially all of its producing properties in the Raton Basin and holds working interests ranging from 75% to 100%.

        Since Evergreen began its drilling efforts in the Raton Basin, the Company has drilled more than 800 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, 2003, Evergreen grew its estimated proved reserves from 58 Bcfe to 1,393 Bcfe, which represents a compound annual growth rate of approximately 44%. During the same period, the Company's net average daily gas sales increased from just over 1 MMcfe to approximately 131 MMcfe.

        From the beginning of the Company's Raton Basin project through December 31, 2003, the Company has spent approximately $426 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 $0.36 per proved Mcfe excluding acquisitions and $0.45 per proved Mcfe including acquisitions.

Purchase of Carbon Energy Corporation

        Evergreen completed the acquisition of Carbon Energy Corporation ("Carbon") on October 29, 2003. Carbon was an independent oil and gas company engaged in the exploration, development and production of oil and natural gas in the United States and Canada. Carbon's areas of operations in the United States were the Piceance Basin in Colorado and the Uintah Basin in Utah. Carbon's area of operations in Canada were in south-central Alberta.

        Under the terms of the acquisition agreement, Carbon's shareholders received 0.55 shares of Evergreen common stock for each common share of Carbon. As a result, Evergreen issued approximately 3.5 million new shares of Evergreen common stock to Carbon's shareholders. The aggregate value of the transaction, including transaction costs, change in control payments and the fair value of Carbon employee stock options assumed by Evergreen was approximately $88.4 million. The net assets acquired included the assumption of Carbon's debt of approximately $20 million.

        At the time of the acquisition, Carbon's net oil and gas reserves in the United States and Canada were estimated at approximately 59 Bcfe and 38 Bcfe, respectively, of which 45% and 73%, respectively, were classified as proved developed and the remaining amounts were classified as proved undeveloped. Independent petroleum engineering consultants Netherland Sewell & Associates, Inc. prepared the reserve estimates of Carbon. Average daily net production in the United States and Canada during the month of December 2003 was approximately 13.4 MMcfe. The gross acreage position acquired in connection with the Carbon acquisition was approximately 150,000 acres in the United States and 130,000 acres in Canada.

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Kansas

        During 2002 and 2003, Evergreen acquired in excess of 700,000 gross acres of prospective unconventional natural gas properties in the Forest City Basin in eastern Kansas. The Company drilled and completed 18 coal bed methane wells and three water disposal wells in the Forest City Basin in the fourth quarter of 2003. Evergreen holds a 100% working interest in the Kansas acreage. The acreage generally lies in the Forest City Basin and also contains shallow gas potential from coals, fractured shales and sands. Management has recently decided to pursue a more moderate exploration and development program in the Forest City Basin in 2004 than was earlier anticipated.

Alaska

        Evergreen holds approximately 300,000 gross acres of prospective coal bed methane acreage in south-central Alaska. The acreage is located in the Cook Inlet-Susitna Basin approximately 30 miles north of Anchorage. Early in the second quarter of 2003, Evergreen completed five of its eight coal bed methane wells on the Pioneer Unit in Alaska's Cook Inlet-Susitna Basin. The initial production results indicate that the wells in these first two pilot projects are not capable of commercial production. In December 2003, the Company drilled the first of five planned stratigraphic core holes on various parts of its acreage base in Alaska to obtain additional petrophysical data, including information on coal quality and gas content. Based on the results of these core holes, the Company will determine potential locations in 2004 for additional core holes or multi-well pilots.

Customers and Markets

Gas Marketing and Transportation

        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 and its royalty interest and working interest partners. Primero operates the Company's gas collection system in the Raton Basin and purchases all of the Company's production from its Raton Basin wells.

        The Company sells its oil and natural gas on an index basis to creditworthy companies including utilities, other end users and energy marketing companies. Natural gas production from the Raton Basin is sold into the Mid-Continent markets by use of firm transportation contracts with Colorado Interstate Gas Company. Natural gas production from the Piceance and Uintah Basins is generally sold at prices based on the regional price set by the market place for natural gas deliveries to the interstate mainline transportation pipeline in the region, which is generally Northwest Pipeline Corp. Natural gas production from the Western Canada Sedimentary Basin is generally sold at prices based on the market price for natural gas deliveries to the Alberta Energy Company, Ltd. ("AECO") pipeline.

        In the United States, oil and natural gas liquids are sold under contracts extending up to a year based upon monthly refiner price postings, which generally approximate the price of West Texas Intermediate for crude oil and Applicable Conway, Kansas posting for natural gas liquids, adjusted to reflect transportation costs and quality. In Canada, oil and natural gas liquids are sold under short-term contracts at refiner posted prices for Alberta and Saskatchewan, adjusted to reflect transportation costs and quality. The Company's oil and natural gas liquids are sold at spot market prices or under short-term contracts.

        The Company also periodically enters into commodity derivative contracts to hedge its production when market conditions are deemed favorable in order to manage price fluctuations and achieve a more predictable cash flow.

        Current gross gas sales from the Raton Basin total approximately 240 MMcf per day. Evergreen's gross sales represent approximately 64% of the Raton Basin total. Takeaway capacity on the Colorado Interstate Gas Company system from the Raton Basin is currently estimated at 290 MMcf per day. The Company expects that, based on Evergreen's projected production growth and other operators

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projected growth, Colorado Interstate Gas Company will have to expand the takeaway capacity in the future. Colorado Interstate Gas Company is expected to expand the takeaway capacity to 400 MMcf per day.

        The Company's current firm transportation commitments are 127 MMcf of gross sales per day plus additional availability of firm transportation. The Company expects that it will be required to commit to additional firm transportation for Colorado Interstate Gas Company to expand takeaway capacity.

Major Customers

        Evergreen has three customers that represented in excess of 10% of the Company's total sales during 2003 which purchased approximately 24%, 15% and 14% of the Company's natural gas production for the year ended December 31, 2003. Based on the general demand for oil and natural 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.

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, state, provincial and local 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,

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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) permitting value-oriented peak/off peak rates to better allocate revenue responsibility between short-term and long-term markets; (2) permitting term-differentiated rates, in order to better allocate risks between shippers and the pipeline; (3) revising the regulations related to scheduling procedures, capacity, segmentation, imbalance management, and penalties; (4) 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 (5) 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. Most major aspects of Order No. 637 were upheld on judicial review, though certain issues, such as capacity segmentation and rights of first refusal, were remanded to the FERC, which issued a remand order in October of 2002. In January of 2004, the FERC denied rehearing of its October 2002 remand order. The Company cannot predict whether judicial review will be sought of the FERC's remand order and, if so, whether and to what extent FERC's market reforms will survive such review and, if they do, whether the FERC's actions will 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 action taken materially differently 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 these rules affect the Company any differently than other oil producers and marketers with which it competes.

        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.

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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. On August 20, 2003, the MMS issued a proposed rule that would change certain components of its valuation procedures for the calculation of royalties owed for crude oil sales. The proposed changes included changing the valuation basis for transactions not at arm's-length from spot to NYMEX prices adjusted for locality and quality differentials, and clarifying the treatment of transactions under a joint operating agreement. Final comments on the proposed rule were due on November 10, 2003. The Company has no way of knowing whether the MMS will implement the proposed changes in a final rule or what effect such changes, if implemented, will have on the Company's results of operations, However, the Company does not believe that this proposed 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 138,000 gross acres are held within three federal units that the Company operates and that are administered by the Bureau of Land Management ("BLM"). See "Item 2. Properties—Raton Basin Properties and Operations." Of the

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Company's Piceance and Uintah Basins acreage, approximately 20,000 gross acres are held within nine federal units that the Company operates. 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 in southern Colorado. The BLM controls a larger portion of the acreage within the Piceance Basin in northwestern Colorado and the Uintah Basin in northeastern Utah. 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, 28 wells have been drilled on BLM minerals in the Raton Basin and 143 wells in the Piceance and Uintah Basins. In the Raton Basin, the BLM has completed an environmental assessment, and all future wells are expected to be approved based on the results of the environmental assessment. Development of adjacent fee lands and minerals within the Raton Basin has proceeded unhindered and access to fee lands has not been hindered by the presence of isolated parcels of federal surface. Future activities within the Piceance and Uintah Basins will be subject to NEPA. The scope and effect are not known at the present time. The number of proposed wells on BLM minerals represents approximately 3% of the total number of wells Evergreen has planned to drill in the Raton Basin and over 90% of the total number of wells Evergreen has planned to drill in the Piceance and Uintah Basins during 2004.

State Regulations

        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 (1) requiring permits for the drilling of wells, (2) maintaining bonding requirements in order to drill or operate wells and (3) 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.

Canadian Regulations

        The oil and natural gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. Federal authorities do not regulate the price of oil and gas in export trade but instead rely on market forces to establish these prices. Legislation exists that regulates the quantities of oil and natural gas which may be removed from the provinces and exported from Canada. The Company does not expect that any of these controls and regulations will affect the Company in a manner significantly different than other oil and natural gas companies of similar size.

        The provinces in which the Company operates have legislation and regulation which govern land tenure, royalties, production rates and environmental protection. The royalty regime in the provinces in which the Company operates is a significant factor in the profitability of the Company's production. Crown royalties are determined by government regulation and are typically calculated as a percentage of the value of production. The value of the production and the rate of royalties payable depends on prescribed reference prices, well productivity, geographical location and the type or quality of the product produced.

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        In Alberta, the Company is entitled to a credit against Crown royalties on most of the properties in which the Company has an interest by virtue of the Alberta Royalty Tax Credit. The credit is determined by applying a rate to a maximum of CDN $2.0 million of Crown royalties payable in Alberta for each company or associated group of companies. The rate is a function of the royalty tax credit par prices which is determined quarterly by the Alberta Department of Energy. The rate ranges from 25% to 75% depending upon petroleum prices for the previous quarter.

Environmental Matters

        The Company is subject to extensive federal, foreign, state, provincial and local environmental laws and regulations that, among other things, regulate the discharge or disposal of 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 and regulations relating to the protection of the environment may, in certain circumstances, impose "strict liability" for environmental contamination. Such laws and regulations 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 and regulations may require the rate of oil and natural gas production to be below the economically optimal rate or may even restrict or 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. Moreover, from time to time, legislation or other initiatives are proposed to Congress or to state and local governments that would place more onerous conditions on the treatment, storage, disposal or clean-up of certain oil and gas exploration and production wastes. If such legislation or other initiatives were to be enacted or adopted, it could have an adverse impact on the operating costs of the Company, as well as the oil and gas industry in general. The regulatory burden on the oil and natural gas industry increases the Company's 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 the Company's operations. For example, the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended ("CERCLA"), also known as the "Superfund" law, and analogous state laws impose liability, without regard to fault 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 strict and 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."

        The Company currently owns or leases, and has in the past owned or leased, numerous properties that have long been used for oil and gas exploration and production. Although the Company has

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utilized operating and disposal practices that were standard for the industry at the time, substances 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 substances 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 substances was not under the Company's control. These properties and the substances disposed thereon may be subject to CERCLA, the Resource Conservation and Recovery Act, as amended, 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 by prior owners or operators), or to perform remedial plugging or pit closure operations to prevent future contamination. The Company is currently planning to perform remedial closures on three pits formerly operated by it in Huerfano County, Colorado, as well as on 40 to 50 pits formerly operated by Carbon in the Piceance and Uintah Basins. The Company believes that only soils are impacted beneath these pits and that they may be closed at a collective cost of less than $300,000 over the next year.

        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 the federal Environmental Protection Agency ("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 the Company'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 Federal Water Pollution Control Act (also referred to as the "Clean Water Act") and various other state requirements and regulations, the EPA and the State of Colorado's Department of Public Health and the Environment 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 Clean Water Act imposes restrictions and strict controls regarding the discharge of produced waters and other oil and gas wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters. The Clean Water Act and analogous state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other hazardous substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. State water discharge regulations and the federal National Pollutant Discharge Elimination System permits applicable to the oil and gas industry generally prohibit the discharge of produced water, sand and some other substances into coastal waters. The cost to

11

comply with zero discharges mandated under federal and state law has not had a material adverse impact on the Company's financial condition and results of operations. Some oil and gas exploration and production facilities are required to obtain permits for their storm water discharges. Costs may be incurred in connection with treatment of wastewater or developing storm water pollution prevention plans.

        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.

        The Oil Pollution Act of 1990 ("OPA") imposes regulations on "responsible parties" related to the prevention of oil spills and liability for damages resulting from spills in waters of the United States. A "responsible party" includes the owner or operator of an onshore facility, vessel or pipeline, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns strict, joint and several liability to each responsible party for oil removal costs and a variety of public and private damages, including natural resource damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation, or if the party fails to report a spill or to cooperate fully in the cleanup. Even if applicable, the liability limits for onshore facilities require the responsible party to pay all removal costs, plus up to $350 million in other damages. Few defenses exist to the liability imposed by OPA. Failure to comply with ongoing requirements or inadequate cooperation during a spill event may subject a responsible party to administrative, civil or criminal enforcement.

        At this time, the Company is not required and otherwise has no plans to make any material capital expenditures to install pollution control devices at facilities. However, the Company is currently evaluating options for reducing the level of noise at two compressor stations in the Raton Basin. The estimated cost for addressing this matter could be as high as $500,000, depending on the work actually performed.

        In Canada, the oil and natural gas industry is currently subject to environmental regulations pursuant to provincial and federal legislation. Environmental legislation provides for restrictions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such regulations may result in the imposition of fines and penalties, the suspension of operations and potential civil liability. The Alberta Environmental Protection and Enhancement Act imposes environmental standards and requires compliance with various legislative criteria in Alberta, including reporting and monitoring requirements. The Alberta Energy and Utility Board, pursuant to its governing legislation, also plays a role with respect to the regulation of environmental impacts of oil and gas activities.

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.

12

Employees

        At January 31, 2004, the Company had 354 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 management 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 negatively affect the Company's financial condition and results of operations. 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. A material decline could reduce the Company's cash flow and borrowing capacity, as well as the value and the amount of its oil and gas reserves. Substantially 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. These factors include:

•

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, foreign, state, provincial and local authorities.

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

        In addition, the Company may be required to write down or impair the carrying value of the Company's 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. Once incurred, a write-down of oil and gas properties is not reversible at a later date. The Company reviews, on a quarterly basis, the carrying value of its oil and gas properties under the full cost accounting rules of the SEC. Under these rules, capitalized costs of proved oil and gas properties, as adjusted for estimated asset retirement obligations, 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, after giving effect to the Company's cash flow hedge positions, 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's operations require large amounts of capital that may not be recovered.

        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 facilities or otherwise, the Company's ability to execute its development plans, replace its reserves or maintain its production levels could be greatly limited. Evergreen's current development plans will require it to make large capital expenditures for the exploration and development of its oil and natural gas properties.

13

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. Additional financing may not 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 projects in the Raton, Piceance, Uintah and Western Canada Sedimentary Basins;



•

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



•

the level of production from existing wells; and



•

the prices of oil and natural gas.

        Issuing equity securities to satisfy the Company's financing requirements could cause substantial dilution to existing stockholders. In addition, debt financing could lead to a diversion of cash flow to satisfy debt servicing obligations and restrictions on the Company's operations.

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

        Evergreen's SEC filings contain estimates of its proved oil and gas reserves and the estimated future net revenues from such reserves. Actual results will likely vary from amounts estimated, and any significant variance could have a material adverse effect on the Company's future results of operations.

        Reserve estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data. Therefore, these estimates are not precise.

        Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed by the Company. In addition, the Company may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond the Company's control.

        At December 31, 2003, approximately 38% of the Company's estimated proved reserves were proved undeveloped. Estimation of proved undeveloped reserves and proved developed non-producing reserves is nearly always based on volumetric calculations rather than the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Production revenues from proved developed non-producing reserves will not be realized until some time in the future. The reserve data assumes that Evergreen will make significant capital expenditures to develop its reserves. Although the Company has prepared estimates of its reserves and the costs associated with these reserves in accordance with industry standards, these estimated costs may not be accurate, development may not occur as scheduled and actual results may not be as estimated.

        Analysts and investors should not construe the present value of future net reserves, or PV-10, as the current market value of the estimated oil and natural gas reserves attributable to the Company's properties. The Company's 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;



•

the supply and demand for oil and natural gas;

14

•

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 of 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 the Company's business or the oil and natural gas industry in general are subject.

The Company's exploratory and development drilling activities may not be successful.

        The Company's future drilling activities may not be successful, and the Company's management cannot be sure that the Company's overall drilling success rate or the Company's drilling success rate for activity within a particular area will not decline. In addition, the wells that the Company drills may not recover all or any portion of the Company's capital investment in the wells, infrastructure or the underlying leaseholds. The Company is currently in the early stages of various exploration projects throughout the United States and Canada and the Company can offer no assurance that the development of these projects will occur as scheduled or that actual results will be in line with the Company's initial estimates. Unsuccessful drilling activities could negatively affect the Company's results of operations and financial condition. 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;



•

ability to hire and train personnel for drilling and completion services;



•

adverse weather conditions;



•

compliance with governmental requirements; and



•

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

15

        In addition, Evergreen may not be able to obtain any options or lease rights in potential drilling locations that it identifies. There is no guarantee that the potential drilling locations that the Company has identified will ever produce oil or natural gas.

The Company's acquisition activities may not be successful.

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

•

the acquired businesses or properties may not produce revenues, earnings or cash flow at anticipated levels;



•

the Company may assume liabilities that were not disclosed or that 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 stockholders; and



•

the Company may incur additional debt related to future acquisitions.

The Company faces risks inherent in expanding its operations into Canada.

        As a result of the Company's acquisition of Carbon in 2003, it acquired Carbon's working interests in Alberta, Canada. These international operations may be adversely affected by currency fluctuations. The revenues and expenses of such operations are denominated in Canadian dollars. As a result, the Company's Canadian operations are subject to risk of fluctuations in the relative value of the Canadian and United States dollars.

The Company may be affected by the gas prices in the Rocky Mountain region.

        As a result of the acquisition of Carbon in 2003, the Company acquired Carbon's working interests in the Piceance Basin in Colorado and the Uintah Basin in Utah. The prices to be received by the Company for the natural gas production from these properties will be determined mainly by factors affecting the regional supply of and demand for natural gas. Based on recent experience, regional differences could cause a negative basis differential between the published indices generally used to establish the price received for regional natural gas production and the actual price received by the Company for its natural gas production.

The Company faces strong competition in the oil and gas industry, and many of its competitors have greater resources than Evergreen.

        The Company operates in a highly competitive industry. The Company competes with major oil companies, independent producers and institutional and individual investors, which 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

16

bidding process in which the Company may lack the technological information or expertise available to other bidders. The Company can offer no assurance that it will be successful in acquiring and developing profitable properties in the face of this competition.

The Company's operations are subject to the business and financial risk of oil and gas exploration.

        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. 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.

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 derivative contracts from time to time with respect to a portion of its current or future production. These transactions may limit the Company's potential gains if natural gas prices were to rise substantially over the price established by the contracts. 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 arrangements;



•

the counterparties to the Company's futures contracts fail to perform the contracts; and



•

a sudden, unexpected event materially impacts natural gas prices.

The Company may face unanticipated water disposal costs.

        Where groundwater produced from Evergreen's coal bed methane projects fails to meet the quality requirements of applicable regulatory agencies or Evergreen's wells produce water in excess of the applicable volumetric permit limit, the Company may have to drill additional disposal wells to re-inject the produced water back into deep underground rock formations. The costs to dispose of this produced water may increase if any of the following occur:

•

Evergreen cannot obtain future permits from applicable regulatory agencies;



•

water of lesser quality is produced;



•

Evergreen's wells produce excess water; or



•

new laws or regulations require water to be disposed of in a different manner.

17

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 must comply with complex federal, foreign, state, provincial and local laws and regulations.

        Federal, foreign, state, provincial and local authorities extensively regulate the oil and gas industry. Noncompliance with these 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. Regulations affect various aspects of oil and gas drilling and production activities, including the pricing and marketing of oil and gas production, 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. These laws and regulations are under constant review for amendment or expansion.

The Company may incur substantial costs to comply with stringent environmental regulations.

        The Company's operations are subject to stringent and constantly changing environmental laws and regulations adopted by federal, foreign, state, provincial and local governmental authorities. The Company could be forced to expend significant resources to comply with new laws or regulations, or changes to current requirements. Governmental 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 laws and regulations and other requirements to coal bed methane drilling, fracture stimulation methods, production and water disposal operations. The Company will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between governmental environmental 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 the Company could have to spend substantial amounts on investigations, litigation and remediation. Moreover, failure by the Company to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory and remedial obligations and the issuance of injunctions that restrict or prohibit the performance of operations. See "—Government Regulation of the Oil and Gas Industry—Environmental Matters."

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, and changes in the Company's contracts with these third parties could materially affect the Company's operations. The Company, through its subsidiaries, has entered into a series of firm transportation service agreements with Colorado Interstate Gas Company providing for the transportation of the Company's natural gas production from the Raton Basin to the Mid-Continent markets. See "—Customers and Markets—Gas Marketing and Transportation."

18

        In addition, federal, foreign, state, provincial and local 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 transport its 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 13 to the Consolidated Financial Statements.

The Company depends on key personnel and does not have employment agreements with its executive officers.

        The Company's success depends on the continued services of its executive officers and a limited number of other senior management and technical personnel, and the Company does not have employment agreements with these employees. The Company's key personnel include Mark S. Sexton, President and Chief Executive Officer, Dennis R. Carlton, Executive Vice President—Exploration and Chief Operating Officer, Kevin R. Collins, Executive Vice President—Finance, Chief Financial Officer, Treasurer and Secretary and J. Scott Zimmerman, Vice President—Operations and Engineering. Loss of the services of any of these people could result in financial losses and interruptions in operations.

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 transactions involving actual or potential changes in control, including transactions that otherwise could involve payment of a premium over prevailing market prices to shareholders for their common stock. These provisions, among other things, provide for a staggered board of directors and 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.

        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. 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's common stock has been volatile and is likely to continue to fluctuate. During 2002, the price of the common stock on the NYSE ranged from a low of $15.45 per share to a high of $23.50 per share (as adjusted to reflect the Company's two-for-one stock split on September 16, 2003). During 2003, the price ranged from a low of $20.65 to a high of $33.75 (as adjusted to reflect the Company's two-for-one stock split on September 16, 2003). The market price of Evergreen'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.

19

ITEM 2. PROPERTIES

        Evergreen's principal estimated proved reserves and producing properties are located in the Raton Basin in southern Colorado, substantially all of which are operated by the Company. Evergreen also has estimated proved reserves and producing properties in the Piceance Basin in western Colorado, the Uintah Basin in eastern Utah, and the Western Canada Sedimentary Basin. In addition, Evergreen holds undeveloped acreage in the Forest City Basin in eastern Kansas and in the Cook Inlet-Susitna Basin in Alaska. The following table sets forth the Company's estimated proved reserves and the associated pre-tax net present value of estimated proved reserves discounted at 10%.

(1)

Before future income taxes; assumes weighted average year-end spot price of $5.49 per Mcfe.

Raton Basin 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 79% of the total production from the Raton Basin and approximately 78% 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 Company is now successfully developing Raton formation coal seams and interbedded sandstones as well.

Development History

        Exploration for coal bed methane in the Raton Basin began 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 Colorado Interstate Gas Company completed the construction of the Picketwire Lateral.

        Since December 1991, the Company has acquired oil and gas leases covering approximately 385,000 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 138,000 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.

20

        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 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 comprise approximately 247,000 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.

        The Company produces methane from 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.

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.

21

        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.

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.

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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, 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 Colorado Interstate Gas Company pipelines. From January 1995 through December 2003, the Company sold an aggregate of approximately 167 Bcf of coal bed methane gas from the Raton Basin. Because of the importance of removing water from the coal seams to enhance gas production, the Company expects to continue

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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. Evergreen 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.

Piceance and Uintah Basin Operations

        Evergreen established its position in the Piceance and Uintah Basins through an acquisition in October 2003. Evergreen holds approximately 171,000 net acres in the agg