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Western Gas Resources, Inc. Form 10-K 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 1-10389

WESTERN GAS 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 Exchange Act Rule 12(b)-2). Yes ý    No o

        The aggregate market value of voting common stock held by non-affiliates of the registrant on June 30, 2003 was $837,578,491.

        The number of shares outstanding of the only class of the registrant's common stock, as of March 3, 2004, was 34,182,837.

DOCUMENTS INCORPORATED BY REFERENCE

        Information required by Part III of this Report (Items 10, 11, 12 and 13) is incorporated by reference from the registrant's proxy statement to be filed pursuant to Regulation 14A with respect to the annual meeting of stockholders scheduled to be held on May 7, 2004.

Western Gas Resources, Inc.
Form 10-K
Table of Contents

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PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

        The terms Western, we, us and our as used in this Form 10-K refer to Western Gas Resources, Inc. and its subsidiaries as a consolidated entity, except where it is clear that these terms mean only Western Gas Resources, Inc.

General

        Western explores for, develops and produces, gathers, processes and treats, transports and markets natural gas and natural gas liquids, or NGLs. In our upstream operations, we explore for, develop and produce natural gas reserves primarily in the Rocky Mountain region. In our midstream operations, which are comprised of three segments, we design, construct, own and operate natural gas gathering, processing and treating facilities; we own and operate regulated transportation facilities; and we offer marketing services in order to provide our customers with a broad range of services from the wellhead to the sales delivery point. Our midstream operations are conducted in major gas-producing basins in the Rocky Mountain, Mid-Continent and West Texas regions of the United States.

        Our operations are conducted through the following four business segments:

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Upstream—We explore for, develop and produce natural gas reserves independently and to enhance and support our existing gathering and processing operations. We sell the natural gas that we produce to third parties. Our producing properties are primarily located in the Powder River and Green River Basins of Wyoming. Our strategy is to seek new gas prospects in the Rocky Mountain region by utilizing our expertise in coal bed methane and tight-gas sand development. The development of new gas prospects may provide additional opportunities for our other business segments.



•

Gathering, Processing and Treating—Our core operations are in well-established areas such as the Permian, Anadarko, Powder River, Greater Green River, and San Juan Basins. We connect natural gas from gas and oil wells to our gathering systems for delivery to our processing or treating plants. At our plants we process natural gas to extract NGLs and we treat natural gas in order to meet pipeline specifications. We provide these services to major oil and gas companies, to independent producers of various sizes and for our own production.



•

Transportation—In the Powder River Basin, we own one interstate pipeline and one intrastate pipeline which transport natural gas for producers and energy marketers under fee schedules regulated by state or federal agencies.



•

Marketing—We buy and sell natural gas and NGLs in the wholesale market in the United States and in Canada. Our gas marketing is an outgrowth of our gas processing and upstream activities and is directed towards selling gas produced at our plants or from our wells in an effort to ensure efficient operations and to maximize returns. We provide transportation, scheduling, peaking and other services to our customers. Our customers for these services include utilities, local distribution companies, industrial end-users and other energy marketers. We are also an active marketer of third-party natural gas throughout the United States.

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        Historically, we have derived over 97% of our revenues from the sale of gas and NGLs. Our revenues by type of operation are as follows (dollars in thousands):

Business Strategy

        Maximizing the value of our existing core assets and locating new growth projects in the Rocky Mountain region are the focal points of our business strategy. Our core assets are our fully integrated upstream and midstream properties in the Powder River and Greater Green River Basins in Wyoming and Colorado and our midstream operations in west Texas, Oklahoma, and New Mexico. Since 2001, our long-term business plan has been to increase stockholder value by: (i) doubling proven reserves and equity production of natural gas from the level at December 31, 2001 over a five year period; (ii) meeting or exceeding throughput projections in our midstream operations; and (iii) optimizing annual returns.

        Double Proven Natural Gas Reserves and Equity Production of Natural Gas from the level at December 31, 2001 over a five year period.     In order to achieve this goal, we will focus on continued development of our leasehold positions in the Powder River Basin coal bed methane play, or CBM, and development in the Greater Green River Basin, and actively seek to add other core natural gas development projects. Overall, we hold drilling rights on approximately 1,043,000 net acres in these and other Rocky Mountain basins. At December 31, 2003, we had proved developed and undeveloped reserves of approximately 685 billion cubic feet equivalent, or Bcfe, of which 42% are proved developed producing reserves. In total this represents an increase of approximately 44% in our proved developed and undeveloped reserves from December 31, 2001. During 2003 our production of natural gas as compared to 2002 increased by 10% to 52.6 Bcfe. In total this represents an increase of approximately 47% in our average equity production of natural gas from 2001 and we replaced 283% of our 2003 production, primarily from drilling and proved undeveloped locations resulting from drilling. In the Powder River Basin, our future growth lies in over 10,000 potential well locations in the Big George, Wyodak and related coals if the play is fully successful. In the Greater Green River Basin, our reserve potential is in the development of 40-acre and 20-acre locations on our leasehold on the Pinedale Anticline, which target sandstone reservoirs in the Lance and Mesa Verde formations.

        We are also actively seeking to add other core projects that are focused on Rocky Mountain natural gas. We will utilize our expertise in exploration and low-risk development of tight-gas sands and coal bed methane plays to evaluate acquisitions of additional leaseholds, proven and undeveloped reserves or companies with operations focused in this area. Toward this goal, we have acquired the drilling rights on approximately 340,000 net acres in northeast Colorado and southwest Nebraska.

        Meet or Exceed Throughput Projections in our Midstream Operations.     To achieve this goal, we must continue our efforts to add to natural gas throughput levels through new well connections, expansion or acquisition of gathering or processing systems and the consolidation of existing facilities. We also seek growth opportunities for gathering and processing through our development of new gas reserves. These operations provide us with steady throughput volumes and significant cash flow that we can in turn reinvest in new growth opportunities in either our upstream or midstream businesses. In 2003, the

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throughput volume at our gathering and processing facilities averaged 1.3 billion cubic feet, or Bcf, per day and operating income contributed by these facilities was $126.6 million.

        Our gathering and processing operations are located in some of the most actively drilled oil and gas producing basins in the United States. We enter into agreements under which we gather, process or treat natural gas produced primarily on acreage dedicated by third parties to us or produced by us. We contract for production from newly developed acreage in order to replace declines in existing reserves or increase reserves that are dedicated for gathering, processing or treating at our facilities. Although some of our plants have experienced natural declines in dedicated reserves, overall we have been successful in connecting additional reserves to more than offset these declines. At December 31, 2003, the estimated reserves connected to our midstream facilities totaled 3.8 trillion cubic feet, or Tcf. This includes estimated third-party reserves connected to our facilities, which are based upon our interpretation of publicly available well and production information and are not the result of audited reserve reports prepared for us, and our connected proven reserves in the Powder River and Green River Basins. During 2003, we spent approximately $54.7 million on additional well connections and compression and gathering system expansions.

        We will also evaluate investments in expansions or acquisitions of assets that complement and extend our core natural gas gathering, processing, treating and marketing businesses and new growth projects in the Rocky Mountain region. For example, in February 2003, we acquired several gathering systems in Wyoming, primarily located in the Green River Basin with smaller operations in the Powder River and Wind River Basins, for a total of $37.1 million. These systems are comprised of a total of 505 miles of gathering lines and, during December 2003, were gathering a total of 108 million cubic feet, or MMcf, per day.

        Optimize Annual Returns.     To optimize our annual returns, we will focus our efforts in our primary operating areas in the Powder River and Greater Green River Basins in Wyoming and Colorado, the Anadarko Basin in Oklahoma, the Permian Basin in west Texas, and the San Juan Basin in New Mexico. We review the economic performance and growth opportunities of each of our assets to ensure that a satisfactory rate of return is achievable. If an asset is not generating targeted returns or is outside our core operating areas, we explore various options, such as integration with other Western-owned facilities or consolidation with third-party-owned facilities, dismantlement, asset trades or sale. Consolidations and joint ventures allow us to increase the throughput of one facility while reducing the capital invested in, and the operating costs of, the consolidated assets. We routinely evaluate our business for methods to reduce our operating and administrative costs, including the implementation of automation and information technology.

        This section, as well as other sections in this Form 10-K, contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, which can be identified by the use of forward-looking terminology, such as "may," "intend," "will," "expect," "believe," "anticipate," "estimate," or "continue" or the negative thereof or other variations thereon or comparable terminology. This Form 10-K contains forward-looking statements regarding: our drilling schedules, success of our drilling activities, reserves and production volumes, our ability to obtain permits and our ability and associated costs to comply with governmental and environmental regulations, expansion of our gathering operations, the drilling success of the producers with acreage dedicated to our facilities, our gathering and transportation throughput, our budgeted capital expenditures, our marketing margins and volumes, our equity production subject to hedges, our liquidity, our future tax benefits and their projected use, our expected future cash flows and their impact on our impairment calculations, and the outcome of our ongoing litigation.

        In addition to the important factors referred to herein, numerous other factors affecting our business generally and in the markets for gas and NGLs in which we participate, could cause actual results to differ materially from the results contemplated by the forward-looking statements in this

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Form 10-K. See further discussion in Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations", "Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 2—Summary of Significant Accounting Policies—Use of Estimates and Significant Risks" and our other documents on file with the Securities and Exchange Commission, or SEC.

        Western Gas Resources, Inc. was incorporated in Delaware in 1989. Our principal offices are located at 1099 18th Street, Suite 1200, Denver, Colorado 80202. Our telephone number is (303) 452-5603.

        Our website address is http://www.westerngas.com. We make available free of charge through our website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC at http://www.sec.gov. Additionally, our Code of Business Conduct and Ethics, Code of Ethics for Senior Financial Management, Corporate Governance Guidelines, and the charters of our Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee are posted on our website and are available in print free of charge to any stockholder who requests them.

2004 Capital Budget

        In order to maintain a strong balance sheet, our general goal is to limit our capital expenditures, excluding acquisitions, in any single year to 110% of the projected cash flow generated by our operations for that year. In some years, however, we expect that we will exceed this limitation based on the growth opportunities available to us. In 2004, we anticipate capital expenditures of approximately $243.5 million. We expect that the Rocky Mountain region will utilize approximately 87% or $211.9 million of the 2004 budget. The 2004 capital budget is presented in the following table (dollars in thousands).

*

Includes $11.7 million for maintaining existing facilities.

        The majority of our capital expenditures are expected to be in the Powder River Basin CBM development and in the Greater Green River Basin. In the Powder River Basin CBM development, we plan to invest approximately $101.7 million, or 42% of our total capital program. Of this amount, approximately $70.1 million is planned to be spent on our share of drilling 800 gross wells and for production equipment and undeveloped acreage and $31.6 million for gathering lines and installation of additional compression units.

        In the Greater Green River Basin we expect to invest approximately $98.3 million, or 40% of the total 2004 capital expenditure program. We plan to spend approximately $57.6 million to participate in approximately 104 gross wells, 90 of which are in the rapidly developing Pinedale Anticline area, and $40.7 million to expand gathering and compression services.

        The remaining $43.5 million of our 2004 capital spending program is expected to be spent as follows: $32.7 million for well connections, expansions, exploration, maintenance and upgrade projects

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in our other operating areas, $7.8 million for capitalized interest and overhead and $3.0 million for administrative expenditures. Overall, we expect to spend $11.7 million on maintenance and upgrade projects for existing midstream facilities. Due to drilling, regulatory, commodity pricing and other uncertainties that are beyond our control, we can make no assurance that our capital budget for 2004 will not change.

Upstream Operations

        A vital aspect of our long-term business plan is to double proven reserves and equity production of natural gas from the level at December 31, 2001 over a five year period. In order to achieve this goal, we will focus on continued development of our leasehold positions in the Powder River CBM development and the Greater Green River Basin. Each of our existing upstream projects is fully integrated with our midstream operations. In other words, we provide the gathering, compression, processing, marketing or transportation services for both our own production and for third-party operators. Additionally, we are actively pursuing new exploration, development and producing property acquisition opportunities.

        Our principal upstream operations are summarized in the following table:

*

Represents net production sold.

        Powder River Basin Coal Bed Methane.     We continue to develop our Powder River Basin CBM reserves and expand the associated gathering system in northeast Wyoming. The Powder River Basin CBM area is currently one of the largest on-shore plays for the development of natural gas in the United States. Within this area, together with our co-developer, in 2003, we were the largest producer of natural gas. Additionally, Western is the largest gatherer of natural gas and, through our MIGC pipeline, we transport a significant volume of gas out of this basin.

        At December 31, 2003, we held the drilling rights on approximately 529,000 net acres in this basin, and as of December 31, 2003, we had established proven developed and undeveloped reserves totaling 326.0 Bcfe, net, on a portion of this acreage, 52% of which are proven and developed. This represented an overall 21% decrease in proven reserves as compared to December 31, 2002. In total, as a result of our drilling and proved undeveloped locations resulting from drilling, we added 78.8 Bcfe of proven reserves in this play in 2003. More than offsetting these additions was production of 43.7 Bcfe during the year and downward revisions of existing reserves of 123.2 Bcfe. The downward revisions were largely due to a change in methodology for calculating gas content and reserves in the Wyodak coals warranted by unexpected pressure declines in the mature development area and due to drainage by offset wells. We, as well as the State of Wyoming and the United States Department of Energy, have historically utilized gas content calculations based on adsorbed isotherm data for the Wyodak coals on the eastern side of the basin. This approach assumed that the coal was 100 percent gas saturated at a

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specific temperature and pressure. After in-depth analysis, we, in consultation with an independent engineering firm, concluded that the Wyodak is not fully saturated. It was then determined that desorbed gas content values, which is the volume of gas that is measured from a coal sample as it was depressured in a laboratory setting, more closely represents the actual gas content and reserves in the Wyodak coal in light of current field pressures.

        The drilling operations in the Powder River Basin through December 31, 2003 have primarily focused on developing reserves in the Wyodak coal, which is located on the east side of the coal bed development. The drilling and completion cost for our CBM gas wells averaged approximately $136,000 per well during 2003, with average reserves per successful Wyodak well of approximately 213 MMcf. The majority of future development will be concentrated on developing the Big George and other coal seams. Much of the Big George coal seam is deeper and thicker than the Wyodak coal. We expect that as wells are drilled and developed in the Big George coal, the gas reserves and production per well and the average drilling and completion cost per well will increase.

        Proved reserves at December 31, 2003 included 85 Bcf from the Big George coal, primarily in the All Night Creek Unit. Our gross production from the Big George coal has continued to increase and in February 2004 was over 39 MMcfd from the All Night Creek Unit, Pleasantville and Kingsbury Unit development areas. Industry-wide Big George production was approximately 120 MMcfd as most recently reported by the State of Wyoming, representing an estimated 100 percent growth rate during the previous 12 months. In February 2004, we had 337 Big George wells that are dewatering and producing gas. An additional 148 Big George wells are dewatering and 283 Big George wells have been drilled and are in various stages of completion and hook-up in preparation for production.

        We currently plan to participate in the drilling of a total of 800 gross wells in 2004. Our share of production sold from CBM wells in which we own an interest averaged approximately 124 MMcfe per day in 2003. This represents an increase of 4% from the average daily production sold in 2002. We currently anticipate daily production to remain relatively constant through the end of 2004. We expect that the rate of production will be somewhat limited in 2004 by the number of federal permits issued in 2003 and dewatering times in the Big George coal.

        On April 30, 2003, the Bureau of Land Management, or BLM, issued the final Record of Decision, or ROD, for the Powder River Basin Oil & Gas Environmental Impact Statement, or EIS. The ROD requires additional surveys for plant and animal species, cultural surveys and noxious weed mitigation. We have filed permit applications for approval by the BLM under the terms of the new EIS, and although we have received federal permits for 201 wells since the issuance of the ROD and through February 15, 2004, we are unable to predict the rate at which permits will be granted in the future. Since the issuance of the final ROD, the BLM has been reviewing its permitting process in an effort to issue to industry a total of approximately 3,000 permits per year under the EIS.

        Additionally, the Wyoming Department of Environmental Quality, or DEQ, has revised some standards for surface water discharge that have allowed the issuance of most of the permits that apply to the Cheyenne and Belle Fourche drainage areas. The majority of our existing production is from wells draining into these areas. Most of our undeveloped prospects from the Big George formation are located in the Powder River drainage area. The Wyoming DEQ will require additional water management techniques, such as containment or treating, in these areas pursuant to the conditions described in the EIS referred to above. While we believe these additional requirements will add to the cost of development of this area, we do not believe they will have a significant impact on our results of operations, financial position or cash flows.

        In October 2003, we settled on-going litigation with our co-developer in this area. Under the terms of the settlement agreement, both our co-developer and we each operate the drilling and production on approximately one-half of the jointly owned leasehold in the CBM development of the Powder River Basin of Wyoming. We began operating our portion of the properties on November 1, 2003.

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        During 2003, we expended approximately $43.0 million in the Powder River Basin coal bed project for drilling costs, production equipment and lease acquisitions. Our 2004 capital budget for the Powder River Basin coal bed project is estimated at $70.1 million; however, due to regulatory uncertainties, which are beyond our control, we can make no assurance that we will incur this level of capital expenditure during 2004.

        Jonah/Pinedale Fields.     Our upstream assets in the Green River Basin of southwest Wyoming are located in the Jonah Field and Pinedale Anticline areas. During 2003, we participated in 53 gross wells, or five net wells, in these areas, at a cost of $19.0 million and experienced a success rate of 100%. Our capital budget for 2004 in the Jonah Field and Pinedale Anticline areas provides for expenditures of approximately $43.1 million for drilling costs and production equipment. During 2004, we expect to participate in the drilling of 90 gross wells, or approximately nine net wells, on the Pinedale Anticline. Due to drilling and regulatory uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure during 2004.

        In October 2003, the Wyoming Oil & Gas Commission approved two pilot drilling programs to increase density on a portion of Western's Pinedale Anticline leasehold to two wells per 40 acres. We expect that approximately 60 wells will be drilled by two of Western's partners during the next 12 to 24 months to test the increased density concept, which would effectively result in 20-acre spacing.

        The expected gross costs to drill a successful well in this area range from approximately $3.5 million to $5.0 million, depending on location of the well site and the depth of the well. Average well depths in this area range from approximately 13,000 feet to 14,200 feet, and average gross reserves per successful well approximate 6 to 10 Bcfe. During 2003, we produced and sold 7.7 Bcfe, net, from these areas. We had established proven developed and undeveloped reserves totaling 330 Bcfe, net, at December 31, 2003, of which 28% are proved developed producing reserves. This represents a 105% increase as compared to December 31, 2002. Results in 2003 reflected existing 40-acre downspacing and success in the deeper Mesa Verde sands in the Pinedale Anticline, which have added significant reserves. No proved reserves were attributed to 20-acre pilots at this time. There can be no assurance, however, as to the ultimate recovery of these reserves.

        Sand Wash Basin.     We continue to explore and develop our acreage position in the Sand Wash Basin in northwest Colorado, located in the Greater Green River Basin. During 2003, we produced 1.4 Bcfe from this acreage. At December 31, 2003, we had established proven developed and undeveloped reserves totaling 29 Bcfe on a portion of this acreage. This represents a 122% increase from the proved reserves at December 31, 2002, primarily as a result of the acquisition in the third quarter of 2003 of the stock of a private corporation for $12.9 million. In this acquisition, we acquired 11 Bcfe of proved reserves and approximately 11,000 net acres under lease.

        We now own approximately 148,000 net oil and gas leasehold acres in this basin. The majority of this acreage is in the exploration phase and will be evaluated in future years. In 2003, we drilled an exploratory well, which encountered mechanical difficulties prior to reaching the targeted reservoir. This well has been plugged and abandoned. In connection with this well, we recorded a dry hole expense of approximately $1.8 million. In 2003, approximately $15.5 million was spent in this area. Our 2004 capital budget in this area provides for expenditures of approximately $11.3 million for our participation in the drilling of eight gross and net development wells and one exploratory well. The expected drilling and completion costs per gross well are approximately $835,000 to $1.2 million and the average well depth in this area approximates 7,700 feet.

        Exploration.     We are also actively seeking to add additional upstream core projects that are focused on Rocky Mountain natural gas. We will utilize our expertise in exploration and low-risk development of tight-gas sands, coal bed methane and fractured shale plays to evaluate acquisitions of

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either additional leaseholds, proven and undeveloped reserves or companies with operations focused in the Rockies.

        Toward this goal, as of January 31, 2004, we have acquired the drilling rights on approximately 390,000 gross acres, or approximately 340,000 net acres, in the northeastern area of the Denver-Julesburg Basin in northeast Colorado and southwest Nebraska. In the fourth quarter of 2003, we drilled two test wells in this area to further evaluate its potential. These wells are completed and are being flow tested to evaluate the overall play. We also plan to drill at least 15 test wells in this area in 2004. We are targeting the Niobrara formation at a depth of approximately 2,500 feet. The drilling and completion costs per gross well are expected to approximate $200,000 with possible gross reserves of 300,000 to 500,000 Mcfe per well.

        In the fourth quarter of 2003, we also participated in two gross exploratory wells, or one net well, in the eastern Green River Basin. These wells also are waiting on completion. If these wells are successful, additional offset locations may be proposed.

        During 2003, our capital expenditures in the exploration area totaled $8.1 million. Our capital expenditure budget for 2004 in the exploration area totals $11.2 million, primarily for our participation in drilling activities, seismic surveys and leasehold acquisition.

        Production Information.     Revenues derived from our producing properties comprised approximately 7%, 6% and 4% of consolidated revenues for the years ended December 31, 2003, 2002 and 2001, respectively. The operating profit (revenues and equity earnings from equity investments less product purchases and operating expenses) derived from our producing properties comprised approximately 40%, 33% and 24% of consolidated operating profit for the years ended December 31, 2003, 2002 and 2001, respectively. We expect both the revenues and operating profit derived from our producing properties to continue to increase commensurately with our production growth.

        The following table provides a summary of our net annual production volumes:

(1)

Represents a small non-operating working interest in several wells in the Austin Chalk area.

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        The following table provides a summary of our proved developed and proved undeveloped net reserves as of the end of the last three years:

        The report for proved reserves in the Powder River Basin CBM gas and other Wyoming assets for 2003 was prepared by Netherland, Sewell & Associates, Inc, or NSAI. The reports for proved reserves in the Powder River Basin CBM gas and other Wyoming assets for 2002 and 2001 were audited by NSAI.

        Reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves, the projection of future rates of production and the timing of development expenditures. The accuracy of these estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserve estimates are imprecise and should be expected to change as additional information becomes available. Estimates of economically recoverable reserves and of future net cash flows prepared by different engineers or by the same engineers at different times may vary substantially. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. In addition, the estimates of future net revenues from our proved reserves and the present value of those reserves are based upon assumptions about production levels, prices and costs which may not be correct. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. Actual results may differ materially from the results estimated. Our estimates of reserves connected to our gathering and processing facilities are calculated by our reservoir engineering staff and are based on publicly available data. These estimates may be less reliable than the reserve estimates made for our own producing properties since the data available for estimates of our own producing properties also include our proprietary data.

Midstream Operations

        Our midstream operations consist of our gathering, processing, treating, marketing and transportation operations. An important element of our long-term business plan is to meet or exceed throughput projections in these areas and to optimize their profitability. To achieve this goal, we must continue our efforts to add to natural gas throughput levels through new well connections and through the expansion or acquisition of gathering or processing systems. We also seek to increase the efficiency of our operations by modernization of equipment and the consolidation of existing facilities.

Gas Gathering, Processing and Treating

        At December 31, 2003, we operated a variety of gathering, processing and treating facilities, or plant operations, with approximately 10,300 miles of gathering lines, as presented on the Principal Gathering and Processing Facilities Table set forth below. These facilities are primarily located in five states and have a combined throughput capacity of approximately 2.9 Bcf per day of natural gas. Our operations are located in some of the most actively drilled oil and gas producing basins in the United

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States. Five of our processing plants can further separate, or fractionate, the mixed NGL stream into ethane, propane, normal butane and natural gasoline to obtain a higher value for the NGLs, and three of our plants are capable of processing and treating natural gas containing hydrogen sulfide or other impurities that require removal prior to delivery to market pipelines. In addition to our integrated upstream and midstream operations in the Powder River and Green River Basins in Wyoming, our core assets include our plant operations located in west Texas, Oklahoma and New Mexico. We believe that our core assets have stable production rates, provide a significant operating cash flow and continue to provide us with strategic growth opportunities.

        We contract with producers to gather raw natural gas from individual wells located near our plants or gathering systems. Once we have executed a contract, we connect wells to gathering lines through which the natural gas is delivered to a processing plant or treating facility. At a processing plant, we compress the natural gas, extract raw NGLs and treat the remaining dry gas to meet pipeline quality specifications.

        We acquire dedicated acreage and natural gas supplies in an effort to maintain or increase throughput levels to offset natural production declines of connected wells. We obtain these natural gas supplies by connecting additional wells, purchasing existing systems from third parties and through internally developed projects or joint ventures. Historically, while individual plants have experienced declines in dedicated reserves, overall we have been successful in connecting additional reserves to more than offset the natural declines. However, the level of future drilling will depend upon, among other factors, the prices for gas and oil, the drilling budgets of third-party producers, energy and environmental policy and regulation of governmental agencies and the availability of foreign oil and gas, none of which is within our control. At December 31, 2003, the estimated reserves connected to our midstream facilities totaled approximately 3.8 Tcf. This includes estimated third-party reserves connected to our facilities, which are based upon our interpretation of publicly available well and production information and are not the result of audited reserve reports prepared for us, and our connected proven reserves in the Powder River and Green River Basins.

        Substantially all gas flowing through our gathering, processing and treating facilities is supplied under three types of contracts providing for the purchase, treating or processing of natural gas for periods ranging from one month to twenty years or in some cases for the life of the oil and gas lease. Approximately 79% of our plant facilities' gross margin, or revenues at the plant less product purchases, for the month of December 2003 was under percentage-of-proceeds agreements where we are typically responsible for the marketing of the gas and NGLs. Under these agreements, we pay producers a specified percentage of the net proceeds received from the sale of the gas and the NGLs.

        Approximately 14% of our plant facilities' gross margin for the month of December 2003 was under contracts that are primarily fee-based from which we receive a set fee for each Mcf of gas gathered and/or processed. This type of contract provides us with a steady revenue stream that is not dependent on commodity prices, except to the extent that low prices may cause a producer to delay drilling.

        Approximately 7% of our plant facilities' gross margin for the month of December 2003 was under contracts with "keepwhole" arrangements or wellhead purchase contracts. We retain the NGLs recovered by the processing facility and keep the producers whole by returning to the producers at the tailgate of the plant an amount of residue gas equal on a Btu basis to the natural gas received at the plant inlet. The "keepwhole" component of the contracts permits us to benefit when the value of the NGLs is greater as a liquid than as a portion of the residue gas stream. However, we are adversely affected when the value of the NGLs is lower as a liquid than as a portion of the residue gas stream.

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Midstream Operating Areas

        Powder River Basin.     Our midstream operations in the Powder River Basin are fully integrated with our upstream operations as we provide the gathering, compression and processing services for our own production. Additionally we provide the same types of services for third-parties. As of December 31, 2003, our assets in the Powder River Basin in northeast Wyoming were primarily comprised of our coal bed methane gathering system with a capacity of 525 MMcf per day, several gas processing facilities with a combined capacity of 146 MMcf per day, and our 13% equity interest in Fort Union Gas Gathering, L.L.C., or Fort Union.

        We averaged 416 MMcf per day of CBM gathering volumes, including third-party gas, during the fourth quarter of 2003. Of that volume, approximately 106 MMcf per day was transported through our MIGC pipeline. As part of our settlement of on-going litigation with our co-developer in this area, we amended our long-term gathering contract for gas produced by our co-developer to significantly increase the area of dedication, to extend the term of the contract, and to modify the fee schedule. While this does not immediately increase our gathering volumes, we believe that we are well positioned for future growth opportunities.

        We are the construction manager and field operator of the Fort Union gathering system and header. The Fort Union system delivers coal bed methane gas to a treating facility near Glenrock, Wyoming and accesses interstate pipelines serving gas markets in the Rocky Mountain and Midwest regions of the United States. The gathering pipeline has a capacity of 635 MMcf per day. We have a long-term gathering agreement with Fort Union for 83 MMcf per day of this capacity at $0.14 per Mcf.

        We spent approximately $10.3 million in the Powder River Basin for midstream activities during 2003. Our capital budget in the Powder River Basin for midstream activities provides for expenditures of approximately $31.6 million during 2004. Depending upon our future drilling success, we may need to make additional capital expenditures or leasing commitments to continue expansion in this basin. Due to drilling, regulatory, commodity pricing and other uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure during 2004.

        Green River Basin.     Our midstream operations in the Green River Basin of southwest Wyoming are also fully integrated with our upstream operations in this area. Our midstream assets in this basin are comprised of the Granger and Lincoln Road facilities, or collectively the Granger complex, our 50% equity interest in Rendezvous Gas Services, L.L.C., or Rendezvous, our Red Desert facility and our Table Rock, Wamsutter and Desert Springs gathering systems. These facilities have a combined gathering capacity of 682 MMcf per day, and in the year ended December 31, 2003, these facilities averaged throughput of 554 MMcf per day. Additionally, these systems have a combined processing capacity of 257 MMcf per day and in the year ended December 31, 2003, processed an average of 214 MMcf per day.

        During 2003, we spent approximately $67.7 million in capital expenditures for midstream activities in this basin, including $37.1 million for the acquisition of several gathering systems. Our 2004 capital budget for midstream activities in this basin provides for expenditures of approximately $40.7 million. This capital budget includes approximately $39.7 million for gathering lines and installation of compression to expand the capacity of our Granger Complex, our Wamsutter gathering system and our Red Desert facility, and $1.0 million for additional contributions to Rendezvous for the expansion of its systems. Due to drilling, commodity pricing and regulatory uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure during 2004.

        In 2001, we, together with an unrelated third-party, formed Rendezvous. Rendezvous gathers gas along the Pinedale Anticline for blending or processing at either our Granger Complex or at the third-party owned and operated Blacks Fork processing facility. Each company owns a 50% interest in Rendezvous, and we serve as field operator of its systems. An expansion of Rendezvous was completed

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in December 2003 bringing its capacity to approximately 275 MMcf per day and in the year ended December 31, 2003 gathered an average of 221 MMcf per day. The cost of this expansion is expected to approximate $32.0 million gross, of which our share will be approximately $16.0 million. As part of Rendezvous' expansion process, in March 2004 we shall be implementing an upgrade of our 100 MMcf per day refrigeration unit at our Granger plant at a cost of $2.8 million.

        West Texas.     Our primary assets in west Texas are the Midkiff/Benedum complex and the Gomez and Mitchell Puckett treating facilities. These facilities process gas produced by third-parties in the Permian Basin, have a combined operational capacity of 565 MMcf per day and processed an average of 291 MMcf per day in the year ended December 31, 2003. Also for this period, these facilities produced an average of 212 MMcf per day of natural gas for delivery to sales markets and produced an average of 802 MGal per day of NGLs. In 2003, our capital expenditures in this area totaled approximately $7.1 million. Our capital budget in this area provides for expenditures of approximately $5.1 million during 2004. This budget includes approximately $2.7 million for additions to the gathering systems and plant facilities and approximately $2.4 million for replacing and upgrading field and plant equipment.

        Oklahoma.     Our primary assets in Oklahoma are the Chaney Dell and Westana systems. These facilities gather and process gas produced by third-parties in the Anadarko Basin and have a combined operational capacity of 175 MMcf per day. During the year ended December 31, 2003, these facilities gathered an average of 165 MMcf per day, produced an average of 142 MMcf per day of natural gas for delivery to sales markets and produced an average of 311 MGal per day of NGLs. During 2003, our capital expenditures in this area totaled $18.2 million. Our capital budget in this area provides for expenditures of approximately $14.2 million during 2004. This budget includes approximately $11.5 million for additions to the gathering systems and plant facilities and approximately $2.7 million for replacing and upgrading field and plant equipment.

        San Juan.     Our assets in the San Juan Basin of New Mexico are the San Juan River processing facility and the Four Corners Gathering system. These facilities gather and process gas produced by third parties in the San Juan and Paradox Basins and has a combined operational capacity of 75 MMcf per day. In 2003, these facilities gathered and processed an average of 32 MMcf per day, produced an average of 25 MMcf per day of natural gas for delivery to sales markets and produced 61 MGal per day of NGLs. During 2003, our capital expenditures in this area totaled $1.0 million. Our capital budget in this area provides for expenditures of approximately $1.1 million during 2004. This budget includes approximately $900,000 for additions to the gathering systems and plant facilities and approximately $200,000 for replacing and upgrading field and plant equipment.

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        Principal Gathering and Processing Facilities Table.     The following table provides information concerning our principal gathering, processing and treating facilities at December 31, 2003.

(1)

Our interest in all facilities is 100% except for Midkiff/Benedum (73%); Newcastle (50%); Fort Union gathering system (13%) and Rendezvous (50%). We operate all facilities, and all data include our interests and the interests of other joint interest owners and producers of gas volumes dedicated to the facility. Unless otherwise indicated, all facilities shown in the table are gathering, processing or treating facilities.

(2)

Gas gathering system miles are as of December 31, 2003.

(3)

Gas throughput capacity is as of December 31, 2003 and represents capacity in accordance with design specifications unless other constraints exist, including permitting or field compression limits.

(4)

Aggregate wellhead natural gas volumes collected by a gathering system.

(5)

Volumes of gas and NGLs are allocated to a facility when a well is connected to that facility; volumes exclude NGLs fractionated for third-parties.

(6)

Sour gas facility (capable of processing or treating gas containing hydrogen sulfide and/or carbon dioxide).

(7)

Processing facility that includes fractionation (capable of fractionating raw NGLs into end-use products).

(8)

NGL production includes conversion of third-party feedstock to iso-butane.

(9)

Lincoln Road is operated on an intermittent basis to process excess gas from the Granger system.

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(10)

These facilities were acquired on February 1, 2003.

        We routinely review the economic performance of each of our operating facilities to ensure that a satisfactory rate of return is achieved. If an operating facility is not generating targeted returns we will explore various options, such as consolidation with other Western-owned or third-party-owned facilities, dismantlement, asset trades or sale. A description of the significant midstream acquisitions and dispositions since January 1, 1999, involving assets other than those, which were previously discussed, are:

        Acquisition and Disposition of Various Wyoming Gathering Systems.     Effective February 1, 2003, we acquired several gathering systems in Wyoming, primarily located in the Green River Basin with smaller operations in the Powder River and Wind River Basins, for a total of $37.1 million. Several of the systems located in the Powder River and Wind River basins did not integrate directly into our existing systems, and accordingly we sold these systems in the third and fourth quarters of 2003.

        Toca Processing Facility.     In 2002, we sold our Toca processing facility in Louisiana. The sale price was $32.2 million, and resulted in a pre-tax loss of approximately $230,000. The sale included a natural gas processing plant with a capacity of 160 million cubic feet per day and a fractionator that could separate 14,200 barrels per day of mixed natural gas liquids into propane, normal butane, iso-butane and natural gasoline. The sale also included NGL storage as well as truck, rail and barge loading facilities, which support the complex.

        Bethel Treating Facility.     In December 2000, we signed an agreement for the sale of all the outstanding stock of our wholly owned subsidiary, Pinnacle Gas Treating, Inc., or Pinnacle, for $38.0 million. The only asset of this subsidiary was a 300 MMcf per day treating facility and 86 miles of associated gathering assets located in east Texas. The sale closed in January 2001 and resulted in a net pre-tax gain for financial reporting purposes of $12.1 million in the first quarter of 2001.

        Arkoma.     In August 2001, we sold our Arkoma Gathering System in Oklahoma for gross proceeds of $10.5 million. This sale resulted in a pre-tax gain of $3.9 million.

        Westana.     In February 2001, we acquired the remaining 50% interest in the Westana Gathering Company for a net purchase price of $9.8 million.

        Western Gas Resources-California, Inc.     In January 2001, we sold all the outstanding stock of our wholly owned subsidiary, Western Gas Resources-California, Inc., or WGR-California, for $14.9 million. The only asset of this subsidiary was a 162-mile pipeline in the Sacramento Basin of California. WGR-California acquired the pipeline through the exercise of a purchase option in a transaction that closed immediately prior to the sale by us of WGR-California. We recognized a pre-tax gain on the sale of approximately $5.4 million in 2001.

        Black Lake.     In December 1999, we signed an agreement for the sale of our Black Lake facility and related reserves for gross proceeds of $7.8 million. This sale closed in January 2001. This transaction resulted in an approximate pre-tax loss of $7.3 million, which was recognized in 1999.

        MiVida.     In June 1999, we sold our MiVida treating facility for gross proceeds of $12.0 million. This transaction resulted in an approximate pre-tax gain of $1.2 million.

        Katy.     In April 1999 we sold all the outstanding common stock of our wholly owned subsidiary, Western Gas Resources Storage, Inc., for gross proceeds of $100.0 million. This transaction resulted in an approximate pre-tax loss of $17.7 million in 1999. The only asset of this subsidiary was the Katy storage facility. We also sold 5.1 Bcf of stored gas in the Katy facility for total sales proceeds of $11.7 million, which approximated our cost of the inventory.

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        Giddings.     In April 1999, we sold our Giddings facility for gross proceeds of $36.0 million, which resulted in an approximate pre-tax loss of $6.6 million in 1999.

Transportation

        We own and operate MIGC, Inc., an interstate pipeline located in the Powder River Basin in Wyoming, and MGTC, Inc., an intrastate pipeline located in northeast Wyoming. MIGC charges a Federal Energy Regulatory Commission, or FERC, approved tariff and is connected to pipelines owned by Colorado Interstate Gas Company, Williston Basin Interstate Pipeline Company, Kinder Morgan Interstate Pipeline Co., Wyoming Interstate Company, Ltd. and MGTC. During the year ended December 31, 2003, MIGC transported an average of 159 MMcf per day. It is anticipated that MIGC will continue to operate around that level in 2004 as well. MIGC earns fees on a monthly basis from firm capacity contracts under which the shipper pays for transport capacity whether or not the capacity is used and from interruptible contracts where a fee is charged based upon volumes received into the pipeline. Contracts for firm capacity on MIGC range in duration from one month to five years and the fees charged averaged $0.33 per Mcf in 2003. MGTC provides transportation and gas sales to various cities in Wyoming at rates that are subject to the approval of the Wyoming Public Service Commission.

        The FERC has implemented changes over the past several years to restrict transactions between regulated pipelines and affiliated companies. In addition, in November 2003, the FERC issued a notice of rulemaking limiting the use of affiliates' employees in the operation of regulated entities. We submitted a plan of compliance with the notice in February 2004 and will be in compliance with the notice by June 1, 2004. In accordance with this plan, we will add several employees to both MIGC and MGTC.

        The following table provides information concerning our principal transportation assets at December 31, 2003.

(1)

Our interest in both facilities is 100%, and we operate both facilities.

(2)

Transportation miles and pipeline capacity are as of December 31, 2003. Pipeline capacity represents certificated capacity at the Powder River junction only and does not include interruptible capacity or capacity at other delivery points.

(3)

Aggregate volumes transported by a pipeline.

(4)

MIGC is an interstate pipeline located in Wyoming and is regulated by the FERC.

(5)

MGTC is a public utility located in Wyoming and is regulated by the Wyoming Public Service Commission.

Marketing

        Gas.     We market gas produced at our wells and our plants and purchased from third-parties to end-users, local distribution companies, or LDCs, pipelines and other marketing companies throughout the United States and Canada. In addition to our offices in Denver, we have marketing offices in Houston, Texas and Calgary, Alberta. Third-party sales, firm transportation capacity on interstate

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pipelines and our gas storage positions, combined with the stable supply of gas from our facilities and production, enable us to respond quickly to changing market conditions and to take advantage of seasonal price variations and peak demand periods.

        One of the primary goals of our gas marketing operations continues to be the preservation and enhancement of the value received for our equity volumes of natural gas. This goal is achieved through the use of hedges on the production of our equity natural gas and through the use of firm transportation capacity. Historically, the gas produced in the Rocky Mountain region has traded at a substantial discount to the Mid-Continent and west coast areas as a result of limited pipeline capacity from the region. During 2003, additional pipeline capacity out of the Rocky Mountain region went into service. This pipeline expansion contributed to a reduction in the price difference between the Rocky Mountain region and Mid-Continent market center. We expect this additional pipeline capacity to continue to have an ongoing impact on the price differences between the Rocky Mountain and Mid-Continent regions.

        For the year ended December 31, 2003, our total gas sales volumes averaged 1.4 Bcf per day, of which 485 MMcf per day was produced at our plants or from our producing properties. This volume of sales is an approximate 31% decrease as compared to 2002. In general, we reduced our sales volume due to price volatility and credit concerns with many counterparties in the energy industry. The marketing of products purchased from third-parties typically results in low profit margins relative to the sales price. We sell gas under agreements with varying terms and conditions in order to match seasonal and other changes in demand. As of December 31, 2003, the weighted average duration of our sales contracts was 14 months.

        Revenues for sales of product are recognized at the time the gas is delivered to the customer and are sensitive to changes in the market prices of the underlying commodities. Gains and losses on any accompanying financial transactions are recorded net. Additionally, for our marketing activities, we utilize mark-to-market accounting. Under mark-to-market accounting, the expected margin to be realized over the term of the transaction is recorded in the month of origination. To the extent that a transaction is not fully hedged or there is any hedge ineffectiveness, additional gains or losses associated with the transaction may be reported in future periods. During the year ended December 31, 2003, we sold gas to approximately 266 end-users, pipelines, LDCs and other customers. No single customer accounted for more than approximately 6% of our consolidated revenues from the sale of gas, or 5% of total consolidated revenue, for the year ended December 31, 2003.

        Price Reporting to Gas Trade Publications.     In the third quarter of 2003,we learned that several employees in our marketing department furnished inaccurate information regarding natural gas transactions to energy publications, which compile and report energy index prices. We discovered the inaccuracies during a review of our marketing activities, which is being conducted in response to a subpoena issued by the Commodity Futures Trading Commission, or CFTC. These employees have identified inaccuracies associated with reporting of natural gas transactions primarily related to points in Texas. Our review of this and other regions is continuing as we respond to the CFTC subpoena. We have discontinued the practice of reporting pricing information to the industry publications. See further discussion in "Note 8—Commitments and Contingencies" to the Consolidated Financial Statements.

        NGLs.     We market NGLs, or ethane, propane, iso-butane, normal butane, natural gasoline and condensate, produced at our plants and purchased from third-parties, in the Rocky Mountain, Mid-Continent and Southwestern regions of the United States. A majority of our production of NGLs moves to the Gulf Coast area, which is the largest NGL market in the United States. Through the development of end-use markets and distribution capabilities, we seek to ensure that products from our plants move on a reliable basis, avoiding curtailment of production. For the year ended December 31, 2003, NGL sales averaged 1,635 MGal per day, of which 1,355 MGal per day was produced at our plants.

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        Consumers of NGLs are primarily the petrochemical industry, the petroleum refining industry and the retail and industrial fuel markets. As an example, the petrochemical industry uses ethane, propane, normal butane and natural gasoline as feedstocks in the production of ethylene, which is used in the production of various plastics products. Further, consumers use propane for home heating, transportation and agricultural applications. Price, seasonality and the economy primarily affect the demand for NGLs.

        We sell NGLs under agreements with varying terms and conditions in order to match seasonal and other changes in demand. At December 31, 2003, the terms of our sales contracts range from one month to three years. The marketing of products purchased from third-parties typically results in low profit margins relative to the sales price. As in the case of natural gas, we continually monitor and review the credit exposure to our NGL marketing counterparties.

        During the year ended December 31, 2003, we sold NGLs to 85 customers including end-users, fractionators, chemical companies and others. Two customers accounted for approximately 49% of our consolidated revenues from the sale of NGLs, or 6% of total consolidated revenue, for the year ended December 31, 2003. One of these customers is a large integrated energy company and the other is a large petrochemical company. We also derive revenues from contractual marketing fees charged to some producers for NGL marketing services. For the year ended December 31, 2003, these fees were less than 1% of our consolidated revenues.

        Revenues for sales of NGLs are recognized at the time the NGLs are delivered to the customer and are sensitive to changes in the market prices of the underlying commodities. Gains and losses on any accompanying financial transactions are recorded net. Additionally, for our marketing activities we utilize mark-to-market accounting. As discussed above, under mark-to-market accounting, the expected margin to be realized over the term of the transaction is recorded in the month of origination. To the extent that a transaction is not fully hedged or there is any hedge ineffectiveness, additional gains or losses associated with the transaction may be reported in future periods.

Environmental

        The construction and operation of our gathering systems, plants and other facilities used for the gathering, processing, treating or transporting of gas and NGLs are subject to federal, state and local environmental laws and regulations, including those that can impose obligations to clean up hazardous substances at our facilities or at facilities to which we send wastes for disposal. In most instances, the applicable regulatory requirements relate to water and air pollution control or waste management. We employ specialists in environmental engineering, safety and regulatory compliance to monitor environmental and safety compliance at our facilities. In addition, the environmental engineers and safety specialists perform in-house audits of our existing facilities to ensure on-going compliance. We believe that we are in substantial compliance with applicable material environmental laws and regulations. Environmental regulation can increase the cost of planning, designing, constructing and operating our facilities. The costs for compliance with current environmental laws and regulations have not had and, we believe, will not have a material adverse effect on our financial position or results of operations.

        Prior to consummating any major acquisition, our environmental engineers perform audits on the facilities to be acquired. In conducting this audit on the gathering systems acquired in February 2003, we identified many well sites that include underground sump tanks, pits, or tinhorns that are not properly permitted according to Wyoming Oil and Gas Conservation Commission, or WYOGCC, regulations. We have reported these violations to WYOGCC and have provided our remediation plan to them. All of the underground facilities that were out of compliance have been removed and in addition, all but three of the sites have been completely remediated. These remaining three sites are currently under going remediation according to the plan approved by the WYOGCC. The seller of

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these assets established a $1.5 million escrow account to cover the costs of remediation. To date, actual expenditures have been less than $1.0 million, and we believe that total remediation costs will be less than the escrow amount.

        The Texas Council on Environmental Quality, which has authority to regulate, among other things, stationary air emissions sources, has created a committee to make recommendations to it regarding a voluntary emissions reduction plan for the permitting of existing "grand-fathered" air emissions sources within Texas. A "grand-fathered" air emissions source is one that does not need a state-operating permit because it was constructed prior to 1971. We operate a number of these sources within Texas, including portions of our Midkiff/Benedum, Gomez and Mitchell Puckett systems. In connection with a modernization program, which was completed in March 2003, we replaced the majority of our "grand-fathered" equipment in Texas. We believe that the potential cost of complying with these regulations for our remaining "grand-fathered" equipment will not have material effect on our results of operations or financial position.

        We anticipate that the trend in environmental legislation and regulation will continue to be toward stricter standards. Federal regulations regarding spill prevention and containment have recently been modified to establish a lower threshold of storage capacity of petroleum and petroleum by-products at a site for which a spill prevention plan is required. We are evaluating all our assets for compliance with this regulation and estimate that approximately 100 existing sites will need to be modified to meet the new requirements. We currently estimate our costs for compliance to be approximately $1.2 million. The new spill prevention plans must be in place for covered assets by August 2004. All modifications called for in those plans must be in place by February 2005.

        We are in the process of voluntarily cleaning up substances at several of the facilities that we operate. Our expenditures for environmental evaluation and remediation at existing facilities have not been significant in relation to our results of operations and totaled approximately $4.0 million for the year ended December 31, 2003, including approximately $763,000 in air emissions fees to the states in which we operate. Although we anticipate that such environmental expenses per facility will increase over time, we do not believe that such increases will have a material adverse effect on our financial position or results of operations.

Competition

        We compete with other companies in the gathering, processing, treating and marketing businesses both for supplies of natural gas and for customers for our natural gas and NGLs, and in exploration and production for the acquisition of leaseholds and other assets. Competition for natural gas supplies is primarily based on the efficiency and reliability of our services, the availability of transportation and the ability to obtain a satisfactory price for natural gas and NGLs. Our competitors for obtaining additional gas supplies, for gathering and processing gas and for marketing gas and NGLs include national and local gas gatherers and processors, brokers, marketers and distributors of various sizes and experience. The majority of these competitors have greater financial resources than do we. For customers that have the capability of using alternative fuels, such as oil and coal, we also compete for their business based on the price and availability of such alternative fuels. Our competitors for obtaining leaseholds include major and large independent oil companies as well as smaller independent oil companies and brokers. Competition for oil field services, including drilling rigs, could affect future drilling plans and costs. Competition for sales customers is primarily based upon reliability and price of deliverable natural gas and NGLs. Suppliers in our gas marketing transactions may request additional financial security such as letters of credit that are not required of some of our competitors.

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Regulation

        Our purchase and sale of natural gas and NGLs and the fees we receive for gathering and processing have generally not been subject to regulation. However, some aspects of our business are subject to federal, state and local laws and regulations that have a significant impact upon our overall operations.

        As a producer, processor and marketer of natural gas, we depend on the transportation and storage services offered by various interstate and intrastate pipeline companies for the delivery and sale of our own gas supplies as well as those we process and/or market for others. Both the interstate pipelines' performance of transportation and storage services, and the rates charged for such services, are subject to the jurisdiction of the FERC, under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. At times, other system users can pre-empt the availability of interstate transportation and storage services necessary to enable us to make deliveries and/or sales of gas in accordance with FERC-approved methods for allocating the system capacity of open access pipelines. Moreover, the rates the pipelines charge for such services are often subject to negotiation between shippers and the pipelines within FERC-established parameters and will periodically vary depending upon individual system usage and other factors. An inability to obtain transportation and/or storage services at competitive rates can hinder our processing and marketing operations and/or adversely affect our sales margins.

        Generally, neither the FERC nor any state agency regulates gathering and processing prices. The Oklahoma Corporation Commission, or the OCC, has limited authority in some circumstances, after the filing of a complaint by a producer, to compel a gas gatherer to provide open access gathering and to set aside unduly discriminatory gathering fees. The Oklahoma state legislature is considering legislation that would expand the authority of the OCC to compel a gas gatherer to publish rates, terms and conditions of its service and under some circumstances, to justify those charges. We do not believe that any of the proposed legislation of which we are aware is likely to have a material adverse effect on our financial position, results of operations or cash flows. However, we cannot predict what additional legislation or regulations the states may adopt regarding gas gathering.

        The construction of additional gathering, processing and treating facilities and the development of natural gas reserves require permits from several federal, state and local agencies. In the past we have been successful in receiving all permits necessary to conduct our operations. There can be no assurance, however, that permits in the future will be obtainable or issued timely or that the terms of any permits will be compatible with our business plans.

Employees

        At December 31, 2003, we employed 655 full-time employees, of which 385 were employed at field locations. None of our employees is a union member. We consider relations with employees to be excellent.

ITEM 3. LEGAL PROCEEDINGS

        Reference is made to Note 8 of our Consolidated Financial Statements in Item 8 of this Form 10-K.

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

        There were no matters submitted to a vote of security holders during the quarter ended December 31, 2003.

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PART II

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

        As of March 3, 2004, there were 34,182,837 shares of common stock outstanding held by 197 holders of record. The common stock is traded on the New York Stock Exchange, or NYSE, under the symbol "WGR". The following table sets forth quarterly high and low sales prices as reported by the NYSE Composite Tape for the quarterly periods indicated.

        We paid annual dividends on our common stock aggregating $0.20 per share during the years ended December 31, 2003 and 2002. We have declared a dividend of $0.05 per share of common stock for the quarter ending March 31, 2004 to holders of record as of that date. Declarations of dividends on our common stock are within the discretion of the board of directors. In addition, our ability to pay dividends on our common stock is restricted by covenants in our financing facilities, the most restrictive of which is in our subordinated note indenture, and that covenant prohibits declaring or paying dividends that exceed, in the aggregate, the sum of $20 million plus 50% of our consolidated net operating income (as defined in the indenture) earned after July 1, 1999 (or minus 100% if a net loss) plus the aggregate net cash proceeds received after July 1, 1999 from the sale of any stock. At December 31, 2003, availability under this covenant was approximately $76.8 million.

Equity Compensation Plan Information

        The following table summarizes our equity compensation plans under which securities may be issued as of December 31, 2003. The only types of equity compensation plans that we have are plans that authorize the granting of options to purchase shares of our common stock.

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        A description of the equity compensation plans that were not approved by the security holders is as follows.

        1999 Non-Employee Directors Stock Option Plan.     Effective March 1999, our board of directors adopted a stock option plan that authorized the granting of options to purchase 15,000 shares of our common stock to non-employee directors. During 1999, the board approved grants of options covering a total of 15,000 shares of our common stock to several board members. The exercise price of the stock underlying each option was the average closing price for the ten days prior to the grant. Under this plan, options covering up to 33¹/3% of the underlying shares are exercisable on each anniversary from the date of grant and the director must exercise the option within five years of the date each option vests. This plan terminates on the earlier of March 12, 2009 or the date on which all options granted under the plan have been exercised in full.

        Chief Executive Officer and President's Plan.     Pursuant to the employment agreement, dated October 15, 2001, and the stock option agreement, dated as of November 1, 2001, between us and Peter A. Dea, our CEO and President, we granted non-qualified stock options to Mr. Dea for the purchase of 300,000 shares of our common stock. The exercise price of the options was equal to $5.00 below the closing price per share on the effective date of his employment agreement. The stock options are subject to the conditions of the agreements and vest equally over four years and must be exercised within five years of the date on which they vest. The difference between the closing price on the effective date and the exercise price is being amortized over four years as compensation expense. This option plan will terminate on the earlier of October 15, 2010 or the date on which all options granted under the plan have been exercised in full.

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ITEM 6.    SELECTED FINANCIAL DATA

        The following table sets forth selected consolidated historical financial and operating data for Western. Certain prior year amounts have been reclassified to conform to the presentation used in 2003. The data for the three years ended December 31, 2003, 2002 and 2001 should be read in conjunction with our Consolidated Financial Statements and the Notes thereto included elsewhere in this Form 10-K. The selected consolidated financial data for the years ended December 31, 2000 and 1999 are derived from our audited historical Consolidated Financial Statements. See also Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations."

(a)

Excludes selling and administrative, interest, expense, income tax expenses, expenses for the impairment of property and equipment, (gains) or losses on sales of assets, and any charges for the early extinguishment of debt. See further discussion in notes (b) and (c).

(b)

Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of," or SFAS No. 121, required that an impairment loss be recognized when the carrying amount of an asset exceeds its fair market value or the expected future undiscounted net cash flows. In accordance with SFAS No. 121, we recognized a pre-tax, non-cash loss on the impairment of property and equipment of $1.2 million, or $0.7 million after-tax, for the year ended December 31, 1999.

(c)

We recognized an after-tax loss on the adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations".

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

        The following discussion and analysis relates to factors that have affected our consolidated financial condition and results of operations for the three years ended December 31, 2003, 2002 and 2001. Certain prior year amounts have been reclassified to conform to the presentation used in 2003. Reference should also be made to our Consolidated Financial Statements and related Notes thereto and the Selected Financial Data included elsewhere in this Form 10-K.

Company Overview

        Business Strategy—Maximizing the value of our existing core assets is the focal point of our business strategy. Our core assets are our fully integrated upstream and midstream assets in the Powder River and Greater Green River Basins in Wyoming and Colorado and our midstream operations in west Texas, Oklahoma and New Mexico. Our long-term business plan is to increase stockholder value by: (i) doubling proven reserves and equity production of natural gas from the levels achieved in 2001 over a five year period; (ii) meeting or exceeding throughput projections in our midstream operations; and (iii) optimizing annual returns.

        Industry and Company Overview—In North America, our industry has experienced several consecutive years of declining natural gas production. Most of the major gas producing areas, such as the Gulf of Mexico, are mature and are in production decline. We are concentrating our efforts in the Rocky Mountain gas producing basins where there are estimated to be large quantities of undeveloped gas. The U.S. government largely retains the mineral rights to these undeveloped reserves; accordingly, the development and production of these reserves require permits from several governmental agencies including the BLM. We are well positioned for future production growth with a large inventory of undeveloped drilling locations in the Powder River and Greater Green River Basins to meet the growing demand for clean burning natural gas. In addition, our experience and technical expertise position us to acquire new opportunities to develop natural gas in the Rocky Mountain region. Our challenges will be to accomplish these goals with the difficulties encountered by the industry in obtaining the necessary permits from the BLM. We believe that our technical expertise in developing environmentally responsible solutions to the problems encountered in the development of gas reserves will be a competitive advantage in overcoming these challenges.

        Our operations are conducted through the following four business segments:

        Upstream—We explore for, develop and produce natural gas reserves independently and to enhance and support our existing gathering and processing operations. Our producing properties are primarily located in the Powder River and Green River Basins of Wyoming. These plays are low-risk, long-lived development projects. These provide us with the opportunity to steadily increase our production volume at low operating and finding and development costs. In 2003 our production grew 10% compared to 2002 levels and far exceeded the industry average for 2002 of a three percent decline in production. Our 2003 production level represented a 47% increase towards meeting our goal of doubling our equity production of natural gas. Also benefiting us in 2003 were higher prices received for natural gas. As a result operating income in this segment increased by 53% to $113.5 million in the year ended December 31, 2003 compared to 2002. At December 31, 2003, we had a total of 685 Bcfe of proved natural gas reserves in our various operating areas. Our business strategy is to double our proven reserves from those in place at December 31, 2001 by the end of 2006. At December 31, 2003, we are 44% toward meeting this goal of doubling proved reserves.

        We are also actively seeking to add additional upstream core projects that are focused on Rocky Mountain natural gas. We will utilize our expertise in exploration and low-risk development of tight-gas sands, coal bed methane and fractured shale plays to evaluate acquisitions of either additional

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leaseholds, proven and undeveloped reserves or companies with operations focused in the Rockies. Toward this goal, we have acquired the drilling rights on approximately 340,000 net acres, in the northeastern area of the Denver-Julesburg Basin in northeast Colorado and southwest Nebraska.

        Gathering, Processing and Treating—Our core operations are in well-established areas such as the Permian, Anadarko, Powder River, Greater Green River, and San Juan Basins. We connect natural gas from gas and oil wells to our gathering systems for delivery to our processing or treating plants under long-term contracts. At our plants we process natural gas to extract NGLs and we treat natural gas in order to meet pipeline specifications. We provide these services to major oil and gas companies, to independent producers of various sizes and for our own production. We believe that our low cost of operations, our high on-line time, and our safety records are key elements in our ability to compete effectively and provide service to our customers. Our expertise in gathering, processing and treating operations can enhance the economics of developing new upstream projects.

        This segment of our operations has provided a stream of operating profit that is available for reinvestment into other projects or other segments of our business. In 2003, we realized operating profit from this segment of $126.6 million, which is a 35% increase from 2002. This segment benefited from significantly higher product prices in 2003 compared 2002 and from increased drilling activity by third-party producers behind our facilities. Overall throughput in our facilities during 2003 increased 13% from 2002 and averaged a total of 1.3 Bcf per day.

        Transportation—In the Powder River Basin, we own one interstate pipeline, MIGC, and one intrastate pipeline, MGTC, which transport natural gas for producers and energy marketers under fee schedules regulated by state or federal agencies. In 2003, we realized operating profit from this segment of $11.6 million, which is a 29% decrease from 2002. The decrease in profit in this segment is due to lower interruptible transportation volume in 2003 as more gas was transported out the basin through other pipelines.

        Marketing—Our gas marketing segment is an outgrowth of our gas processing and upstream activities. One of the primary goals of our gas marketing operations is the preservation and enhancement of the value received for our equity volumes of natural gas. This goal is achieved through the use of hedges on the production of our equity natural gas and NGLs and through the use of firm transportation capacity. We also buy and sell natural gas and NGLs in the wholesale market in the United States and in Canada. These third-party sales, our firm transportation capacity on interstate pipelines and our gas storage positions, combined with the stable supply of gas from our facilities and production, enable us to respond quickly to changing market conditions and to take advantage of seasonal price variations and peak demand periods. In order to protect the profitability of this segment, we continually monitor and review credit exposure to our marketing counterparties. During 2003, we experienced no uncollectible accounts.

        In 2003, we realized operating profit from this segment of $31.4 million, which is a 14% decrease from 2002. The decrease in operating profit is primarily due to lower profitability on transactions associated with our firm transportation capacity from the Rocky Mountain region to the Mid-Continent. Our firm transportation allows us to purchase gas in the Rocky Mountain region for resale in the higher priced Mid-Continent markets. New transportation capacity added in 2003 out of the Rocky Mountain region has resulted in a decrease in the difference between the prices for natural gas received in this region compared to the prices received in the Mid-Continent marketing area.

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Results of Operations
Year ended December 31, 2003 compared to year ended December 31, 2002
(000s, except per share amounts and operating data)

        Net income increased $33.6 million for the year ended December 31, 2003 compared to 2002. The increase in net income was primarily attributable to a significant increase in gas and NGL prices in 2003 compared to last year. This increase in prices was supplemented by increased equity production from the Powder River Basin CBM project and the Green River Basin. Partially offsetting the increase in net income in the year ended December 31, 2003 was a $6.7 million after-tax loss from the cumulative effect of a change in accounting principle from the adoption of SFAS No. 143 "Accounting for Asset Retirement Obligations" on January 1, 2003.

        Revenues from the sale of gas increased $344.3 million to $2,463.0 million for the year ended December 31, 2003 compared to 2002. This increase was primarily due to an increase in product prices, which more than offset a decrease in sales volume in 2003. Average gas prices realized by us increased $2.02 per Mcf to $4.94 per Mcf for the year ended December 31, 2003 compared to 2002. Included in the calculation of the realized gas price were approximately $23.9 million of losses recognized in the year ended December 31, 2003 related to futures positions on equity gas volumes. We have entered into additional futures positions for approximately half of our equity gas for 2004. See further discussion in "Item 3. Quantitative and Qualitative Disclosures About Market Risk." Average gas sales volumes decreased 626 MMcf per day to 1,362 MMcf per day for the year ended December 31, 2003 compared to 2002. This decrease was due to a reduction in third party sales volume resulting from the increase in product prices and an intentional effort to reduce related credit exposure.

        Revenues from the sale of NGLs increased approximately $36.6 million to $346.1 million for the year ended December 31, 2003 compared to 2002. This increase is primarily due to a significant increase in product prices, which was partially offset by a reduction in third-party sales volumes. Average NGL prices realized by us increased $0.16 per gallon to $0.58 per gallon for the year ended December 31, 2003 compared to 2002. Included in the calculation of the realized NGL price were approximately $11.4 million of losses recognized in the year ended December 31, 2003 related to futures positions on equity NGL volumes. We have entered into additional futures positions for approximately half of our equity NGL production for 2004. See further discussion in "Item 3. Quantitative and Qualitative Disclosures About Market Risk." Average NGL sales volumes decreased 375 MGal per day to 1,635 MGal per day for the year ended December 31, 2003 compared to 2002.

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        Product purchases increased by $299.3 million for the year ended December 31, 2003 compared to 2002 as a result of the significant increase in commodity prices. Overall, combined product purchases as a percentage of sales of all products remained relatively constant at approximately 89% for both 2003 and 2002.

        Plant and transportation operating expense increased by $6.8 million for the year ended December 31, 2003 compared to 2002. The increase was primarily due to increased throughput at our facilities, the acquisition of several gathering systems in the first quarter of 2003 and additional leased compression in the Powder River Basin coal bed development. Also contributing to this increase were the fees paid to other companies, primarily Rendezvous, for gas gathering services. Rendezvous is a 50%-owned entity that delivers gas to our Granger Complex. Rendezvous is accounted for under the equity method, and our share of its gathering revenues is reflected in Earnings from equity investments.

        Oil and gas exploration and production expenses increased by $18.2 million for the year ended December 31, 2003 compared to 2002. In our operating areas, the significant increase in residue gas prices in 2003 resulted in substantially higher severance tax expenses. Overall, lease-operating expense, or LOE, for the year ended December 31, 2003 increased by approximately $0.04 per Mcfe compared to 2002 and averaged $0.46 per Mcfe. The increase in lease-operating expense per Mcfe is primarily due to unsuccessful well expenses of $1.8 million in 2003.

        Depreciation, depletion and amortization decreased by $3.1 million for the year ended December 31, 2003 as compared to 2002. This decrease was the result of revisions to the operating lives, and salvage values, of our operating assets partially offset by increased production in the Powder River Basin and additional depreciation in 2003 from new projects. The revisions to the operating lives and salvage values of our operating assets were the result of analysis performed in connection with the adoption of SFAS No. 143 on January 1, 2003 and were treated as a revision of an estimate and are accounted for on a prospective basis.

        Selling and administrative expenses increased by approximately $4.6 million in the year ended December 31, 2003 as compared to 2002. This increase was the result of higher compensation expenses due to an increased employee count in 2003 resulting from our growing exploration and production operations, and a modification in 2003 to our incentive compensation plan to pay this compensation on a current basis as opposed to a vesting schedule used in prior years. Also contributing to the increase were higher professional fees resulting from litigation concluded in 2003 and our ongoing research associated with the CFTC investigation of our price reporting to trade publications. Partially offsetting these increases were fewer charges for doubtful accounts in 2003 as compared to 2002.

        In 2003, in order to properly align our hedged volumes of natural gas to our forecasted equity production, we discontinued hedge treatment on financial instruments for 10 MMcf per day of natural gas and 50,000 Barrels per month of ethane. As a result, a pre-tax loss of $2.8 million was reclassified into earnings from Accumulated other comprehensive income.

Cash Flow Information

        Cash flows from operating activities increased by $117.6 million in 2003 compared to 2002. This increase was primarily due to an increase in net income in 2003 compared to the prior year and the timing of cash receipts and payables.

        Cash flows used in investing activities increased by $91.3 million in 2003 compared to 2002. This increase was primarily due to a higher level of capital expenditures.

        Cash flows used in financing activities increased by $4.8 million in 2003 compared to 2002. This increase was due to increased cash flows from operating activities, which was used to reduce our long-term debt.

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Other Information

        Acquisition and Disposition of Gathering Systems.     Effective February 1, 2003, we acquired several gathering systems in Wyoming, primarily located in the Green River Basin with smaller operations in the Powder River and Wind River Basins, for a total of $37.1 million. Several of the systems located in the Powder River and Wind River did not integrate directly into our existing systems, and accordingly these systems were sold. During the year ended December 31, 2003, the income, if any, generated by the assets sold was immaterial for separate presentation as a discontinued operation.

        Acquisition of Sand Wash Properties.     In August 2003, through the acquisition of the stock of a private corporation for $12.9 million, we acquired additional reserves, production and acreage in this area. The assets of this private entity consisted primarily of the remaining interests in various Sand Wash properties that we operate. This acquisition included approximately 11 billion cubic feet equivalent, or Bcfe, of proved reserves, 2.1 MMcfe per day of production and approximately 11,000 net acres under lease.

Segment Information

        Gas Gathering, Processing and Treating.     The Gas Gathering, Processing and Treating segment realized segment-operating profit of $126.6 million for the year ended December 31, 2003 as compared to $93.6 million in 2002. The increase in operating profit in this segment in 2003 is primarily due to higher commodity prices, increased gathering volumes and the acquisition of several gathering systems in February 2003.

        Exploration and Production.     The Exploration and Production segment realized segment-operating profit of $113.5 million for the year ended December 31, 2003 compared to $74.1 million in 2002. The increase in operating profit in this segment in 2003 was primarily due to substantially higher natural gas prices and production volume growth from the Powder River Basin CBM area and the Pinedale Anticline.

        Marketing.     The Marketing segment realized segment-operating profit of $31.4 million for the year ended December 31, 2003 compared to $36.4 million in 2002.

        The decrease in the marketing margin is primarily due to transactions associated with our firm transportation capacity from the Rocky Mountain region to the Mid-Continent. Our firm transportation allows us to purchase gas in the Rocky Mountain region for resale in the higher priced Mid-Continent markets. In the second quarter of 2003, additional transportation capacity out of the Rocky Mountain region became operational, which reduced the price difference between the two regions. We expect that the reduced margins will continue in future periods. There is no assurance that the margins we realized on the sale of gas in 2003 will continue in the future, or that we will continue to originate the same amount of transactions in future years.

        Transportation.     The Transportation segment realized segment-operating profit of $11.6 million for the year ended December 31, 2003 compared to $16.3 million in 2002. The transportation segment includes the results from the MIGC and MGTC pipelines in the Powder River Basin. The decrease in profit in this segment is due to lower interruptible transportation volume in 2003 as more gas was transported out the basin through other pipelines.

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Year ended December 31, 2002 compared to year ended December 31, 2001
(000s, except per share amounts and operating data)

        Net income decreased $45.0 million for the year ended December 31, 2002 compared to 2001. The decrease in net income was primarily attributable to significantly lower gas and NGL prices in this period as compared to the prior year and lower margins per unit earned on our sales of natural gas. These decreases more than offset increased production from the Powder River Basin CBM development.

        Revenues from the sale of gas decreased $747.6 million to $2.1 billion for the year ended December 31, 2002 compared to 2001. This decrease was primarily due to a decline in product prices, which more than offset an increase in sales volume in the year ended December 31, 2002. Average gas prices realized by us decreased $1.05 per Mcf to $2.92 per Mcf in the year ended December 31, 2002 compared to 2001. Included in the realized gas price were approximately $28.1 million of gains recognized in the year ended December 31, 2002 related to futures positions on equity gas volumes. Average gas sales volumes increased minimally to 1,988 MMcf per day in the year ended December 31, 2002 compared to 2001.

        Revenues from the sale of NGLs decreased approximately $114.6 million to $309.5 million in the year ended December 31, 2002 compared to 2001. This decrease was due to a reduction in product prices and to a reduction in sales volume. Average NGL prices realized by us decreased $0.07 per gallon to $0.42 per gallon in the year ended December 31, 2002 compared to 2001. Included in the realized NGL price were approximately $8.2 million of losses recognized in the year ended December 31, 2002 related to futures positions on equity NGL volumes. Average NGL sales volumes decreased 337 MGal per day to 2,010 MGal per day in the year ended December 31, 2002 compared to 2001.

        Product purchases decreased by $829.8 million for the year ended December 31, 2002 compared to 2001 primarily as a result of the decrease in commodity prices. Overall, combined product purchases as a percentage of sales of all products decreased to 89% for the year ended December 31, 2002 from 91% for 2001. The decrease in the product purchase percentage for the year ended December 31, 2002 versus 2001 resulted from a decrease in product prices and an increase of sale of our production from the Powder River Basin development.

        In the year ended December 31, 2002, we expensed a total of $1.6 million for doubtful accounts, primarily due to the bankruptcy filing of a large mid-western co-op during the year. This compared to

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an expense of $2.7 million for doubtful accounts in 2001. These charges are not included in the calculation of the marketing margins and are reported in Selling and administrative expenses.

        Plant and transportation operating expense increased by $6.0 million in the year ended December 31, 2002 compared to 2001. This increase was primarily due to additional leased compression, repair and maintenance and labor costs in the Powder River Basin coal bed development and higher property tax expenses at our plant facilities.

        Oil and gas exploration and production expenses increased by $6.5 million in the year ended December 31, 2002 as compared to 2001. In our operating areas, the significant reduction in residue gas prices in the 2002 periods resulted in substantially lower severance tax expenses. These reductions were substantially offset by increased lease operating expenses, or LOE, in the Powder River Basin coal bed development. Overall, LOE averaged $0.42 per Mcf in the year ended December 31, 2002. LOE in the Powder River Basin coal bed development averaged $0.45 per Mcf in the year ended December 31, 2002. This represented increases of $0.06 per Mcf and $0.03 per Mcf from the comparable periods in 2001, respectively. The increases were substantially due to higher utility charges, increased use of leased generators, increased labor charges and prior period adjustments for operating supplies, utilities and technical supervision billed to us by the well operator. The increased LOE in 2002 were substantially offset by lower severance taxes resulting from the significant reduction in residue gas prices in 2002 as compared to 2001.

        Selling and administrative expenses increased by $1.6 million in the year ended December 31, 2002 as compared to 2001, due to higher health insurance costs and higher compensation expenses.

        Depreciation, depletion and amortization increased by $12.8 million in the year ended December 31, 2002 as compared to 2001 primarily as a result of our increasing operations in the Powder River Basin CBM development.

        The provision for income taxes increased to a 37.3% effective rate for the year ended December 31, 2002 from 37.1% in 2001. This change is due to increased sales of third-party product in states with higher corporate tax rates and in Canada.

Cash Flow Information

        Cash flows from operating activities decreased by $22.1 million in the year ended December 31, 2002 compared to 2001. This reduction was primarily due to a decrease in net income in 2002 compared to the prior year and the timing of cash receipts and payables.

        Cash flows used in investing activities decreased by $25.9 million in the year ended December 31, 2002 compared to 2001. This decrease was primarily due to a reduction in capital expenditures.

        Cash flows used in financing activities increased by $3.6 million in the year ended December 31, 2002 compared to 2001. This increase was due to the application of the proceeds received in the sale of our Toca Processing facility in 2002 to reduce the amounts outstanding under our Revolving Credit Facility.

Other Information

        Toca Processing Facility.     In June 2002, we entered into an agreement for the sale of our Toca processing facility in Louisiana. This sale closed in September 2002. The sale price was $32.2 million, subject to accounting adjustments, and resulted in a pre-tax loss of approximately 230,000. The purchase price included a natural gas processing plant with a capacity of 160 million cubic feet per day and a fractionator that can separate 14,200 barrels per day of mixed natural gas liquids into propane, normal butane, iso-butane and natural gasoline. The sale also includes NGL storage as well as truck, rail and barge loading facilities, which support the complex. During the year ended December 31, 2002,

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this facility generated net after-tax earnings of approximately $683,000, or $.02 per share of common stock, respectively. Approximately $15.0 million of the proceeds received from this asset sale were initially used to reduce amounts outstanding on our Revolving Credit Facility. At December 31, 2002, the remaining amount of $17.2 million was on deposit with a trustee in anticipation of the completion of a like-kind exchange transaction and was reflected on the Consolidated Balance Sheet under the caption Other current assets. These funds, along with additional amounts drawn on our Revolving Credit Facility, were used in a February 2003 acquisition of several gathering systems.

        Bethel Treating Facility.     In December 2000, we signed an agreement for the sale of all the outstanding stock of our wholly owned subsidiary, Pinnacle Gas Treating, Inc., or Pinnacle, for $38.0 million. The only asset of this subsidiary was a 300 MMcf per day treating facility and 86 miles of associated gathering assets located in east Texas. The sale closed in January 2001 and resulted in a net pre-tax gain for financial reporting purposes of $12.1 million in the first quarter of 2001.

Segment Information

        Gas Gathering, Processing and Treating.     The Gas Gathering, Processing and Treating segment realized segment-operating profit of $93.6 million for the year ended December 31, 2002 as compared to $134.3 million in 2001. The decrease in operating profit in this segment in 2002 is primarily due to lower commodity prices, partially offset by gains in equity hedges.

        Exploration and Production.     The Exploration and Production segment realized segment-operating profit of $74.1 million for the year ended December 31, 2002 compared to $64.2 million in 2001. The increase in operating profit in this segment in 2002 was primarily due to production volume growth from the Powder River Basin CBM area and the Pinedale Anticline, substantially offset by lower commodity prices.

        Marketing.     The Marketing segment realized segment-operating profit of $36.4 million for the year ended December 31, 2002 compared to $47.4 million in 2001. The margins earned from the sale of third-party natural gas averaged $0.04 and $0.06 per Mcf in the years ended December 31, 2002 and 2001, respectively. The decrease in margin for 2002 compared to 2001 primarily resulted from reduced margins associated with the mark-to-market of forward transactions in the current year versus the prior year. This reduction in margin is primarily the result of our electing hedge accounting on several of our transactions in 2002 utilizing our firm transportation capacity and fewer long-dated transactions utilizing our transportation capacity in place at the end of 2002 compared to 2001. Under hedge accounting, the margin to be realized on a transaction is recorded in the month the transportation capacity is used, and under mark-to-market accounting, the anticipated margin on a transaction to be realized over the term of the transaction is recorded in the month of origination.

        Transportation.     The Transportation segment realized segment-operating profit of $16.3 million for the year ended December 31, 2002 compared to $16.3 million in 2001. The transportation segment includes the results from the MIGC and MGTC pipelines in the Powder River Basin.

Critical Accounting Estimates

        The application of accounting policies is an important process that has developed as our business activities have evolved and as accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an interpretation and implementation of existing rules, and the use of judgment, to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical. For further details on our accounting policies, and the estimates, assumptions and judgments we use in applying these

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policies and a discussion of new accounting rules, see Note 2 of the Notes to Consolidated Financial Statements.

        Use of Estimates.     The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the amounts reported for assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the amounts reported for revenues and expenses during the reporting period. These estimates are evaluated on an ongoing basis, utilizing historical experience, consultation with experts and other methods considered reasonable in the particular circumstances. However, actual results may differ significantly from the estimates used. Any effects on our business, financial position or results of operations resulting from revisions to these estimates will be recorded in the period in which the facts that necessitate a revision become known. Although there are a number of areas where we use estimates, what we believe to be the most significant ones are discussed below.

        Property and Equipment.     Depreciation on our property and equipment is provided using the straight-line method based on the estimated useful life of each facility, which ranges from three to 35 years. Useful lives are determined based on the shorter of our estimate of the life of the equipment or our estimate of the reserves serviced by the equipment. Among other factors, the estimates consider our experience with similar assets and technical analysis of the reserves. The cost of acquired gas purchase contracts is amortized using the straight-line method or units of production. If the actual lives of the equipment or the reserves serviced by the equipment were less than we originally estimated, we may be required to record a loss upon retirement of a specific asset.

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        Oil and Gas Reserves, Properties and Equipment.     We follow the successful efforts method of accounting for oil and gas exploration and production activities. Producing properties and related equipment are depleted and depreciated by the units-of-production method based on estimated proved reserves. The units of production method is sensitive to the determination of proved reserves. To the extent the reserves are modified, the depletion determined under the units of production method will be increased or decreased on a prospective basis.

        Our reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves, the projection of future rates of production and the timing of development expenditures. The accuracy of these estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserve estimates are imprecise and should be expected to change as additional information becomes available. Estimates of economically recoverable reserves and of future net cash flows prepared by different engineers or by the same engineers at different times may vary substantially. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. In addition, the estimates of future net revenues from our proved reserves and the present value of those reserves are based upon certain assumptions about production levels, prices and costs, which may not be correct. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. Actual results may differ materially from the results estimated.

        Asset Retirement Obligations.     We use significant judgment in estimating our future liability for asset retirement. We evaluate each asset and in some cases individual components of assets to determine and estimate the future cost and timing of retiring those assets. The estimate of the future cost is then discounted back to the present and recorded as a liability. This liability will vary based upon the probability, timing and the extent of remediation necessary to reclaim those facilities, the discount factor used in those determinations and the projected costs of the remediation. We evaluate these estimates on an ongoing basis and modify our assumptions as appropriate.

        Impairment of Long-Lived Assets.     If changes in the expected performance of an asset occur, or if overall economic conditions warrant, we will review our assets to determine their economic viability.

        In accordance with SFAS No. 144 "Accounting for the Impairment or Disposal of Long Lived Assets", assets are to be evaluated at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets. Accordingly, our review is completed at the plant facility, the related group of plant facilities or the oil and gas producing field or producing coal seam level. In order to determine whether an impairment exists, we compare the net book value of the asset to the estimated fair market value or the undiscounted expected future net cash flows, determined by applying future prices estimated by management over the shorter of the lives of the facilities or the associated reserves. If an impairment exists, write-downs of assets are based upon expected future net cash flows discounted using an interest rate commensurate with the risk associated with the underlying asset. This analysis is sensitive to, among other things; management's expectation of commodity prices, operating costs, drilling plans, production rates and the evaluation in determining asset groupings for which cash flows are largely independent of the cash flows of other assets.

        In the fourth quarter of 2003, we conducted a review of our oil and gas producing properties, which included an evaluation of the geologic formations and production history for these properties. This review indicated that the cash flows from individual wells in our operating areas were not largely independent of the cash flows of other wells producing in the same field or coal seam. As a result of this review, we redefined the asset groupings to a field wide analysis for impairment for the Jonah, Pinedale and Sand Wash Basins and to a grouping of all wells drilled into related coal seams for the Powder River Basin. These asset groupings were used to determine if any impairment was necessary for

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the year ended December 31, 2003 and it was determined that none of these asset groups were impaired. In addition, while we did not recognize any impairment of our producing properties in the years ended December 31, 2002 or 2001 under the asset groupings utilized in those years, a reevaluation of those years using our new asset groups also did not result in an impairment of our producing properties.

        Identification of Derivatives and Mark to Market Valuations.     The determination of which contractual instruments meet the definition of a derivative under accounting rules is subject to differing interpretations as is the valuation of those derivatives. Management uses its judgment to analyze all contracts to determine whether or not they qualify as derivatives and to determine their value. A specific area in which management's judgment is required includes identifying contracts meeting the criteria for exclusions from derivatives treatment, market liquidity, and market valuation. This analysis is sensitive to commodity prices, outside market factors and management's intent upon entering into these contracts.

        Recently Issued Accounting Pronouncements.     We continually monitor and revise our accounting policies as new rules are issued. At this time, there are several new accounting pronouncements that have recently been issued, but not yet adopted, which will have an impact on our accounting when these rules become effective in 2004. The following pronouncements have been issued but not yet adopted.

        SFAS No. 141 and SFAS No. 142.     SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Intangible Assets" were issued in June 2001 and became effective for us on July 1, 2001 and January 1, 2002. SFAS No. 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. SFAS No. 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. One interpretation being considered relative to these standards is that oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds should be classified separately from oil and gas properties, as intangible assets on the Consolidated Balance Sheet. In addition, the disclosures required by SFAS No. 141 and No. 142 relative to intangibles would be included in the Notes to Consolidated Financial Statements. Historically, we have included these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves as part of the Oil and gas properties and equipment, even after SFAS No. 141 and No. 142 became effective.

        This interpretation of SFAS No. 141 and No. 142 described above would only affect the Consolidated Balance Sheet classification of oil and gas leaseholds. Our results of operations and cash flows would not be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with accounting rules for oil and gas companies provided in SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies".

        At December 31, 2003, we had undeveloped leaseholds of $55.9 million that would be classified on the Consolidated Balance Sheet as "intangible undeveloped leaseholds" and developed leaseholds of $31.7 million that would be classified as "intangible developed leaseholds" if the interpretation currently being considered was applied. We will continue to classify our oil and gas mineral rights held under lease and other contractual rights representing the right to extract such reserves as tangible oil and gas properties until further guidance is provided.

        FIN 46.     In January 2003, the FASB issued Interpretation No. 46, or "FIN 46", "Consolidation of Variable Interest Entities." FIN 46 provides guidance on how to identify a variable interest entity, or VIE, and determine when the assets, liabilities, and results of operations of a VIE need to be included

35

in a company's consolidated financial statements. FIN 46 also requires additional disclosures by primary beneficiaries and other significant variable interest holders in a VIE. The provisions of FIN 46 are effective immediately for all VIEs created after January 31, 2003. For VIEs created before February 1, 2003, the provisions of FIN 46, as amended, must be adopted at the beginning of the first quarter of 2004. We did not create any VIEs after January 31, 2003 and we are continuing to evaluate the impact of FIN 46 on any VIEs created prior to that date and will adopt this pronouncement as required.

Liquidity and Capital Resources

        Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our financing facilities and proceeds from offerings of debt and equity securities. In the past, these sources have been sufficient to meet our needs and finance the growth of our business. We can give no assurance that the historical sources of liquidity and capital resources will be available for future development and acquisition projects, and we may be required to seek additional or alternative financing sources. Product prices, hedges of equity production, sales of inventory, the volumes of natural gas processed by our facilities, the volume of natural gas produced from our producing properties, the margin on third-party product purchased for resale, as well as the timely collection of our receivables are all expected to have significant influences on our future net cash provided by operating activities. Additionally, our future growth will be dependent upon obtaining additions to dedicated plant reserves, acquisitions, new project development, marketing results, efficient operation of our facilities and our ability to obtain financing at favorable terms.

        During the past several years, we have been successful in developing additional reserves of natural gas and increasing our equity natural gas production. However, the overall level of drilling and production associated with our producing properties will depend upon, among other factors, the price for gas, availability of transportation capacity to market centers, the energy and environmental policy and regulation by governmental agencies, and the issuance of drilling and water disposal permits, none of which is entirely within our control. Any reduction in the levels of exploration, development and production by us or a significant reduction in natural gas prices could have a material adverse effect on our financial condition, results of operations and cash flows.

        Although some of our plants have experienced natural declines in dedicated reserves, overall we have been successful in connecting additional reserves to more than offset these declines. However, the overall level of drilling associated with our plant facilities will depend upon, among other factors, the prices for oil and gas, the drilling budgets of third-party producers, availability of transportation capacity to market centers, the energy and environmental policy and regulation by governmental agencies, the pace at which drilling permits are received, and the availability of foreign oil and gas, none of which is within our control. There is no assurance that we will continue to be successful in replacing the dedicated reserves processed at our facilities. Any prolonged reduction in prices for natural gas and NGLs may depress the levels of exploration, development and production by third-parties. Lower levels of these activities could result in a corresponding decline in the demand for our gathering, processing and treating services. A reduction in any of these activities could have a material adverse effect on our financial condition, results of operations and cash flows.

        We believe that the amounts available to be borrowed under the revolving credit facility, together with net cash provided by operating activities, will provide us with sufficient funds to connect new reserves, maintain our existing facilities and complete our current capital expenditure program. Depending on the timing and the amount of our future projects, we may be required to seek additional sources of capital. Our ability to secure such capital is restricted by our financing facilities, although we may request additional borrowing capacity from our lenders, seek waivers from our lenders to permit us to borrow funds from third-parties, seek replacement financing facilities from other lenders, use stock as a currency for acquisitions, sell existing assets or may use a combination of alternatives. While

36

we believe that we would be able to secure additional financing, if required, we can provide no assurance that we will be able to do so or as to the terms of any additional financing.

        During 2003, we entered into an amended and restated revolving credit facility and utilized a portion of that facility to fund $43.3 million in scheduled payments on the master shelf agreement discussed below. We believe that cash provided by operating activities and amounts available under the revolving credit facility will be sufficient to meet scheduled principal repayments during 2004 of $35.0 million under the master shelf agreement and our projected preferred stock dividend requirements during 2004.

        We have effective shelf registration statements filed with the SEC for an aggregate of $200 million of debt securities and preferred stock, along with the shares of common stock, if any, into which those securities are convertible, and $62 million of debt securities, preferred stock or common stock. These shelf registrations allow us to access the debt and equity markets.

        Preferred Stock Redemption.     During the fourth quarter of 2003, we issued two notices of redemption for a total of 1,500,000 shares of our $2.625 cumulative convertible preferred stock. The holders of these shares had the right to convert them into shares of our common stock in lieu of receiving the redemption price in cash. In total, we issued an additional 1,840,333 shares of common stock and paid $1.9 million in cash proceeds to complete these redemptions. After completing these redemptions, we have a total of 1,252,943 shares of our $2.625 cumulative convertible preferred stock outstanding and, assuming no further redemption, we would anticipate paying in 2004 a total of $3.3 million in preferred dividends.

        Sources and Uses of Funds.     Our sources and uses of funds for the year ended December 31, 2003 are summarized as follows (dollars in thousands):

        Capital Investment Program.     We currently anticipate capital expenditures in 2004 of approximately $243.5 million. The 2004 capital budget is a 20% increase over the amount expended in 2003. This increase is the result of an expected increase in drilling activity in each of our upstream areas and additional drilling activity by third party producers whose acreage is dedicated to our midstream facilities. Overall, capital expenditures in the Powder River Basin CBM development and in southwest Wyoming operations represent 42% and 40%, respectively, of the total 2004 budget. Due to drilling and regulatory uncertainties that are beyond our control, we can make no assurance that our capital

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budget for 2004 will not change. This budget may be increased to provide for acquisitions if approved by our board of directors.

        The 2004 capital budget and our capital expenditures during the year ended December 31, 2003, which totaled approximately $203.1 million, are presented in the following table (dollars in thousands).

*

Includes $14.4 million and $11.7 million in 2004 and 2003, respectively, for maintaining existing facilities.

Contractual Commitments and Obligations

        Contractual Cash Obligations.     A summary of our contractual cash obligations as of December 31, 2003 is as follows (dollars in thousands):

        Guarantee of Fort Union Project Financing.     We own a 13% equity interest in Fort Union Gas Gathering, L.L.C., or Fort Union, and are the construction manager and field operator. Fort Union gathers and treats natural gas in the Powder River Basin in northeast Wyoming. Initial construction and any expansions of the gathering header and treating system have been project financed by Fort Union. This debt is amortizing on an annual basis and is scheduled to be fully paid in 2009. All participants in Fort Union have guaranteed Fort Union's payment of the project financing on a proportional basis, resulting in our guarantee of $5.5 million of the debt of Fort Union at December 31, 2003. Our requirement to fund under this guarantee would be reduced by the value of assets held by Fort Union. This guarantee is not reflected on our Consolidated Balance Sheet.

        Operating Leases.     In the ordinary course of our business operations, we enter into operating leases for office space, office equipment, communication equipment and transportation equipment. In addition, we have entered into operating leases for compression equipment. Payments made on these

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leases are a component of operating expenses and are reflected on the Consolidated Statement of Operations and, as operating leases, are not reflected on our Consolidated Balance Sheet. These leases have terms ranging from one month to ten years with return or fair market purchase options available at various times during the lease. If we were to exercise the purchase options on all the leased equipment, these purchase options would require the capital expenditure of approximately $37.0 million between 2007 and 2012.

        Firm Transportation Capacity and Gathering Agreements.     Access to firm transportation is also a significant element of our business strategy. Firm transportation ensures that our equity production has access to downstream markets and allows us to capture incremental profit when pricing differentials between physical locations occur. As of December 31, 2003, we had contracts for approximately 610 MMcf per day of firm transportation. This amount represents our total contracted amount on many individual pipelines. In many cases it is necessary to utilize sequential pipelines to deliver gas into a specific sales market. In total, we have the capacity to transport 172 MMcf per day of gas from the Rocky Mountain area to the Mid-Continent. This utilizes a total of approximately 376 MMcf per day of firm capacity on three separate pipelines. The total rate under these long-term contracts to transport this gas to the Mid-Continent from the southern Powder River Basin approximates $0.35 per Mcf. Our remaining firm capacity consists of 99 MMcf per day to markets within the Rocky Mountains and 135 MMcf per day contracted in various other markets throughout the country. In addition, we hold 83 MMcf per day of firm gathering capacity on the Fort Union gathering line. These agreements are not reflected on our Consolidated Balance Sheet.

        A portion of this firm transportation capacity was contracted for use in our Marketing operations. For example, our Marketing segment purchases gas in the Rocky Mountain region, transports this gas utilizing its 56 MMcf per day of our firm transportation capacity to the Mid-Continent, and resells the gas to various markets. During the year ended December 31, 2003, these types of transactions have been profitable as the price difference, or basis, between the Rocky Mountain and Mid-Continent regions has exceeded the cost of transportation. The fixed fees associated with our existing contracts for firm transportation capacity during 2004 will average approximately $0.16 per Mcf per day. The associated contract periods range from one month to fourteen years. Under firm transportation contracts, we are required to pay the fees associated with these contracts whether or not the transportation is used.

        Firm Storage Capacity Agreements.     We customarily store gas in underground storage facilities to ensure an adequate supply for long-term sales contracts and to capture seasonal price differentials. As of December 31, 2003, we had contracts in place for approximately 16.3 Bcf of storage capacity at various third-party facilities. Of the total storage capacity under contract, approximately 7.7 Bcf is under contract to our Canadian subsidiary, WGR Canada, Inc., and Western guarantees the subsidiary's performance under these contracts. This subsidiary is wholly owned by us and fully consolidated in our financial statements.

        The fees associated with these contracts in 2004 will average $0.53 per Mcf of annual capacity. The associated contract periods at December 31, 2003 have an average term of twenty-nine months. At December 31, 2003, we held gas in our contracted storage facilities and in imbalances of approximately 12.7 Bcf at an average cost of $4.64 per Mcf compared to 15.1 Bcf at an average cost of $2.72 per Mcf at December 31, 2002. These positions are for storage withdrawals within the next twelve months. At the time we place product into storage, we contract for the sale of that product, physically or financially, and do not speculate on the future value of the product. These agreements for storage capacity are not reflected on our Consolidated Balance Sheet.

        From time to time, we lease NGL storage space at major trading locations to facilitate the distribution of products. At December 31, 2003, we held NGLs in storage at various third-party facilities of 2,989 MGal, consisting primarily of propane and ethane, at an average cost of $0.30 per

39

gallon compared to 2,755 MGal at an average cost of $0.25 per gallon at December 31, 2002. These agreements for storage capacity are not reflected on our Consolidated Balance Sheet.

Long-term Debt

        Revolving Credit Facility.     At December 31, 2003, $94.0 million was outstanding under our existing four-year, $300 million revolving credit facility. This facility matures in April 2007. Loans made under this facility are secured by a pledge of the capital stock of our significant subsidiaries. These subsidiaries also guarantee the borrowings under the facility. The facility contains a provision that requires us to secure loans under the facility with 75% of our oil and gas reserves. This provision would only be triggered in the event of a reduction to a debt rating on the revolving credit facility of Ba3 or lower by Moody's Investors Service, Inc., or Moody's, or the reduction to a debt rating on the revolving credit facility of BB- or lower by Standard & Poor's Rating Services, a division of The McGraw-Hill Companies, Inc., or S&P. This facility has been rated Ba1 by Moody's and BB+ by S&P.

        The borrowings under the credit facility bear interest at Eurodollar rates or a base rate, as requested by us, plus an applicable percentage based on our debt to capitalization ratio. The base rate is the agent's published prime rate. We also pay a quarterly facility fee ranging between 0.30% and 0.50%, depending on our debt to capitalization ratio. This fee is paid on the total commitment. At December 31, 2003, the interest rate payable on borrowings under this facility was approximately 2.9%.

        Under the credit facility, we are subject to a number of covenants, including: maintaining a total debt to capitalization ratio of not more than 55%; maintaining a senior debt to capitalization ratio of not more than 40%; and maintaining a ratio of EBITDA, as defined in the credit facility, to interest and dividends on preferred stock over the last four quarters in excess of 3.25 to 1.0, increasing to 3.75 to 1.0 at March 31, 2004 and to 4.25 to 1.0 at March 31, 2005.

        The credit facility ranks equally with borrowings under our master shelf agreement with The Prudential Insurance Company.

        Master Shelf Agreement.     Amounts outstanding under the master shelf agreement with The Prudential Insurance Company of America at December 31, 2003 are as indicated in the following table (dollars in thousands):

        Our borrowings under the master shelf agreement are secured by a pledge of the capital stock of our significant subsidiaries, some of which have also provided a guaranty of payments we owe under the facility. The master shelf requires us to secure loans under the facility with 75% of our oil and gas reserves. This provision would only be triggered in the event of a reduction to the debt rating on the revolving credit facility of Ba3 or lower by Moody's or the reduction to the debt rating on the revolving credit facility of BB- or lower by S&P.

        Under our master shelf agreement, we are subject to a number of covenants, including: maintaining a minimum tangible net worth equal to the sum of $300 million plus 50% of consolidated net earnings earned from January 1, 1999 plus 75% of the net proceeds of any equity offerings after January 1, 1999; maintaining a total debt to capitalization ratio of not more than 55% and a senior debt to capitalization ratio of not more than 40%; maintaining a quarterly test of EBITDA, as defined

40

in the master shelf agreement, to interest for the last four quarters in excess of 3.25 to 1.0, increasing to 3.75 to 1.0 at March 31, 2004 and to 4.25 to 1.0 at March 31, 2005; and maintaining a ratio of senior debt to EBITDA of no greater than 4.0 to 1.0.

        In the fourth quarter of 2003, we utilized funds available under the revolving credit facility to fund $33.3 million in scheduled payments under the master shelf agreement, and in 2004 we will make scheduled payments totaling $35.0 million on this facility. We intend to fund these repayments with funds available under the revolving credit facility.

        Senior Subordinated Notes.     In 1999, we sold $155.0 million of senior subordinated notes in a private placement with a final maturity of 2009 due in a single payment which were subsequently exchanged for registered publicly tradable notes under the same terms and conditions. The subordinated notes bear interest at 10% per annum and were priced at 99.225% to yield 10.125%. These notes contain covenants, which include limitations on debt incurrence, restricted payments, liens and sales of assets. The subordinated notes are unsecured and are guaranteed on a subordinated basis by our material subsidiaries. We incurred approximately $5.0 million in offering commissions and expenses, which were capitalized and are being amortized over the term of the notes. The senior subordinated notes are callable at our option, in whole or in part, at 105% of par value beginning in June 2004 and are callable at decreasing premiums thereafter. Our ability to call these notes may be restricted by the covenants under our other debt facilities.

        Covenant Compliance.     We were in compliance with all covenants in our debt agreements at December 31, 2003.

Environmental

        The construction and operation of our gathering systems, plants and other facilities used for the gathering, processing, treating or transporting of gas and NGLs are subject to federal, state and local environmental laws and regulations, including those that can impose obligations to clean up hazardous substances at our facilities or at facilities to which we send wastes for disposal. In most instances, the applicable regulatory requirements relate to water and air pollution control or waste management. We employ specialists in environmental engineering, safety and regulatory compliance to monitor environmental and safety compliance at our facilities. In addition, on an ongoing basis, our environmental engineers perform environmental assessments of our existing facilities. We believe that we are in substantial compliance with applicable material environmental laws and regulations. Environmental regulation can increase the cost of planning, designing, constructing and operating our facilities. The costs for compliance with current environmental laws and regulations have not had and, we believe, will not have a material adverse effect on our financial position or results of operations.

        Prior to consummating any major acquisition, our environmental engineers perform audits on the facilities to be acquired. In conducting this audit on the gathering systems we acquired in February 2003, we identified many well sites that include underground sump tanks, pits, or tinhorns that are not properly permitted according to Wyoming Oil and Gas Conservation Commission, or WYOGCC, regulations. We have reported these violations to WYOGCC and have provided our remediation plan to them. All of the underground facilities that were out of compliance have been removed and in addition, all but three of the sites have been completely remediated. These remaining three sites are currently under going remediation according to the plan approved by the WYOGCC. The seller of these assets established a $1.5 million escrow account to cover the costs of remediation. To date, actual expenditures have been less than $1.0 million, and we believe that total remediation costs will be less than the escrow amount.

        The Texas Council on Environmental Quality, which has authority to regulate, among other things, stationary air emissions sources, has created a committee to make recommendations to it regarding a voluntary emissions reduction plan for the permitting of existing "grand-fathered" air emissions sources

41

within Texas. A "grand-fathered" air emissions source is one that does not need a state-operating permit because it was constructed prior to 1971. We operate a number of these sources within Texas, including portions of our Midkiff/Benedum, Gomez and Mitchell Puckett systems. In connection with a modernization program, which was completed in March 2003, we replaced the majority of our "grand-fathered" equipment in Texas. We believe that the potential cost of complying with these regulations for our remaining "grand-fathered" equipment will not have a material adverse effect on our results of operations or financial position.

        We anticipate that the trend in environmental legislation and regulation will continue to be toward stricter standards. Federal regulations regarding spill prevention and containment have recently been modified to establish a lower threshold of storage capacity of petroleum and petroleum by-products at a site for which a spill prevention plan is required. We are evaluating all of our assets for compliance with this regulation and estimate that approximately 100 existing sites will need to be modified to meet the new requirements. We currently estimate our costs for compliance to be approximately $1.2 million. The new spill prevention plans must be in place for covered assets by August 2004. All modifications called for by those plans must be in place by February 2005.

        We are in the process of voluntarily cleaning up substances at certain facilities that we operate. Our expenditures for environmental evaluation and remediation at existing facilities have not been significant in relation to our results of operations and totaled approximately $4.0 million for the year ended December 31, 2003, including approximately $736,000 in air emissions fees to the states in which we operate. Although we anticipate that such environmental expenses per facility will increase over time, we do not believe that such increases will have a material adverse effect on our financial position or results of operations.

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        Our commodity price risk management program has two primary objectives. The first goal is to preserve and enhance the value of our equity volumes of gas and NGLs with regard to the impact of commodity price movements on cash flow and net income in relation to those anticipated by our operating budget. The second goal is to manage price risk related to our marketing activities to protect profit margins. This risk relates to fixed price purchase and sale commitments, the value of storage inventories and exposure to physical market price volatility.

        We utilize a combination of fixed price forward contracts, exchange-traded futures and options, as well as fixed index swaps, basis swaps and options traded in the over-the-counter, or OTC, market to accomplish these goals. These instruments allow us to preserve value and protect margins because corresponding losses or gains in the value of the financial instruments offset gains or losses in the physical market.

        We also use financial instruments to reduce basis risk. Basis is the difference in price between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations.

        We enter into futures transactions on the New York Mercantile Exchange, or NYMEX, and through OTC swaps and options with various counterparties, consisting primarily of investment banks, financial institutions and other natural gas companies. We conduct credit reviews of all of our OTC counterparties and have agreements with many of these parties that contain collateral requirements. We generally use standardized swap agreements that allow for offset of positive and negative OTC exposures. OTC exposure is marked-to-market daily for the credit review process. Our exposure to OTC credit risk is reduced by our ability to require a margin deposit from our counterparties based

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upon the mark-to-market value of their net exposure. We are also subject to margin deposit requirements under these same agreements and under margin deposit requirements for our NYMEX transactions. At December 31, 2003, we had $5.7 million of margin deposits outstanding.

        We continually monitor and review the credit exposure to our marketing counterparties. In order to minimize our credit exposures, we have utilized existing netting agreements to reduce our net credit exposure, established new netting agreements with additional customers, terminated several long-term marketing obligations, negotiated accelerated payment terms with several customers, and reduced the amount of credit which we make available to various customers. Although netting agreements similar to those that we utilize have been upheld by bankruptcy courts in the past, if any of these customers with whom we have netting agreements were to file for bankruptcy, we can provide no assurance that our agreements will not be challenged or as to the outcome of any challenge.

        The use of financial instruments may expose us to the risk of financial loss in some circumstances, including instances when (i) our equity volumes are less than expected, (ii) our customers fail to purchase or deliver the contracted quantities of natural gas or NGLs, or (iii) our OTC counterparties fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in these prices.

        Risk Policy and Control.     We control the extent of risk management and marketing activities through policies and procedures that involve the senior level of management. On a daily basis, our marketing activities are audited and monitored by our independent risk oversight department, or IRO. This department reports to the Chief Financial Officer, thereby providing a separation of duties from the marketing department. Additionally, the IRO reports monthly to the Risk Management Committee, or RMC. This committee is comprised of corporate managers and officers and is responsible for developing the policies and guidelines that control the management and measurement of risk. The RMC is also responsible for setting risk limits including value-at-risk and dollar stop loss limits. Our board of directors approves the risk limit parameters and risk management policy.

        Hedge Positions.     As of January 31, 2004, we have hedged approximately 49% of our projected 2004 equity natural gas volumes and approximately 55% of our estimated equity production of crude oil, condensate, and NGLs. All of these contracts are designated and accounted for as cash flow hedges. As such, gains and losses related to the effective portions of the changes in the fair value of the derivatives are recorded in Accumulated other comprehensive income, a component of Stockholders' equity. Realized gains or losses on these cash flow hedges are recognized in the Consolidated Statement of Operations through Product purchases when the hedged transactions occur.

        To qualify as cash flow hedges, the hedge instruments must be designated as cash flow hedges and changes in their fair value must be highly correlated with changes in the price of the forecasted transaction being hedged so that our exposure to the risk of commodity price changes is reduced. To meet this requirement, we hedge the price of the commodity and, if applicable, the basis between that derivative's contract delivery location and the cash market location used for the actual sale of the product. This structure attains a high level of effectiveness, insuring that a change in the price of the forecasted transaction will result in an equal and opposite change in the cash price of the hedged commodity. We utilize crude oil as a surrogate hedge for natural gasoline, butane and condensate. Our hedges are tested for effectiveness at inception and on a quarterly basis thereafter. We use regression analysis based on a five-year period of time for this test. Based on the results of the regression analysis, these hedges are expected to continue to be "highly effective" under SFAS No. 133 in the future. Gains or losses from the ineffective portions of changes in the fair value of cash flow hedges are recognized currently in earnings through Price risk management activities. During the year ended December 31, 2003, we recognized a loss of $110,000 from the ineffective portions of our hedges.

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        Outstanding Equity Hedge Positions and the Associated Basis for 2004.     The following table details our hedge positions as of January 31, 2004. In order to determine the hedged price to the particular operating region, deduct the basis differential from the NYMEX price. The prices for NGLs do not include the cost of the hedges of approximately $1.2 million. There is no associated cost for the natural gas hedges.

        Account balances related to equity and transportation hedging transactions at December 31, 2003 were $1.7 million in Current assets from price risk management activities, $5.2 million in Current Liabilities from price risk management activities, ($1.3) million in Deferred income taxes payable, net, and a $2.3 million after-tax unrealized loss in Accumulated other comprehensive income, a component of Stockholders' Equity. Based on prices as of December 31, 2003, approximately $2.3 million of losses in Accumulated other comprehensive income will be reclassified to earnings in 2004.

        Value at Risk.     We measure market risk in our natural gas and liquid marketing portfolios using value-at-risk, or VaR. We define VaR as a measure of the maximum expected loss over a given horizon under normal market conditions. VaR does not explicitly indicate potential realized losses. VaR does, however, implicitly indicate a firm's potential realized loss if market conditions were to remain constant or if the portfolio is liquidated within the specified time period. Our calculations are derived from Financial Engineering Association's VaR Works using the variance/co-variance method. We assume a one-day holding period with a 95% confidence level. There is a 95% (19 out of 20 business days) chance that the portfolio loss will be less than a specified amount if the entire portfolio were liquidated the next day. As of December 31, 2003, our VaR position for natural gas and NGL marketing portfolios was $385,000 and the average for all of 2003 was $496,000. This figure includes the risk related to our entire marketing portfolio of natural gas and NGL financial instruments and the related underlying physical transactions. We also measure market risk by sensitivity valuations. As of

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December 31, 2003, an increase in natural gas prices of $1.00 per MMbtu would lead to an increase in the fair value of our marketing portfolio of $135,000 and an increase in crude oil prices of $5.00 per barrel would lead to an increase in the fair value of our marketing portfolio of $600,000. To the extent that a transaction is not fully hedged or there is any hedge ineffectiveness, additional gains or losses associated with the transaction may be reported in future periods.

        Summary of Derivative Positions.     A summary of the change in our derivative position from December 31, 2002 to December 31, 2003 is as follows (dollars in thousands):

        A summary of our outstanding derivative positions at December 31, 2003 is as follows (dollars in thousands):

(1)

Other actively quoted prices are derived from broker quotations, trade publications, and industry indices.

(2)

Other valuation methods are the Black-Scholes option-pricing model utilizing prices and volatility obtained from broker quotations, trade publications, and industry indices.

        Foreign Currency Derivative Market Risk.     As a normal part of our business, we enter into physical gas transactions which are payable in Canadian dollars. We enter into forward purchases and sales of Canadian dollars from time to time to fix the cost of our future Canadian dollar denominated natural gas purchase, sale, storage, and transportation obligations. This is done to protect marketing margins from adverse changes in the U.S. and Canadian dollar exchange rate between the time the commitment for the payment obligation is made and the actual payment date of such obligation. As of December 31, 2003, the net notional value of such contracts was approximately $24.3 million in Canadian dollars, which approximates fair market value.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

        Western Gas Resources, Inc.'s Consolidated Financial Statements as of December 31, 2003 and 2002 and for each of the three years in the period ended December 31, 2003:

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REPORT OF MANAGEMENT

        The financial statements and other financial information included in this Annual Report on Form 10-K are the responsibility of Management. The financial statements have been prepared in conformity with generally accepted accounting principles appropriate in the circumstances and include amounts that are based on Management's informed judgments and estimates.

        Management relies on the Company's system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that transactions are properly recorded and executed in accordance with Management's authorization. The concept of reasonable assurance is based on the recognition that there are inherent limitations in all systems of internal accounting control and that the cost of such systems should not exceed the benefits to be derived. The internal accounting controls, including internal audit, in place during the periods presented are considered adequate to provide such assurance.

        PricewaterhouseCoopers LLP, independent auditors, audits the Company's financial statements. Their report states that they have conducted their audit in accordance with generally accepted auditing standards. Those standards require that the independent auditors consider internal control in planning and performing their audit, and to determine the nature, timing and extent of tests to be performed.

        Oversight of Management's financial reporting and internal accounting control responsibilities is exercised by the board of directors, through an Audit Committee that consists solely of outside directors. The Audit Committee meets periodically with financial management, internal auditors and the independent auditors to review how each is carrying out its responsibilities and to discuss matters concerning auditing, internal accounting control and financial reporting. The independent auditors and the Company's internal audit department have free access to meet with the Audit Committee without Management present.

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REPORT OF INDEPENDENT AUDITORS

To the Board of Directors and
Stockholders of Western Gas Resources, Inc.

        In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Western Gas Resources, Inc. and its subsidiaries at December 31, 2003 and 2002, and the results of their cash flows and their operations for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. 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 of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        As discussed in Note 4 to the financial statements, the Company changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001. As discussed in Note 1 to the financial statements, the Company changed its method of accounting for asset retirement obligations effective January 1, 2003 and its method of testing long-lived assets for impairment.

PricewaterhouseCoopers LLP

Denver, Colorado
March 9, 2004

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