WESTERN GAS RESOURCES INC - 10-K Annual Report

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

Delaware (State or other jurisdiction of incorporation or organization)		84-1127613 (I.R.S. Employer Identification No.)
12200 N. Pecos Street, Denver, Colorado (Address of principal executive offices)		80234-3439 (Zip Code)

No Changes
(Former name, former address and former fiscal year, if changed since last report)

Title of each class		Name of exchange on which registered
Common Stock, $0.10 par value		New York Stock Exchange
$2.28 Cumulative Preferred Stock, $0.10 par value		New York Stock Exchange
$2.625 Cumulative Convertible Preferred Stock, $0.10 par value		New York Stock Exchange

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

The aggregate market value of voting common stock held by non-affiliates of the registrant on March 1, 2002 was $1,096,204,862.

The number of shares outstanding of the only class of the registrant's common stock, as of March 1, 2002, was 32,703,009.

The 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 17, 2002.

Indicate by check mark if disclosure of delinquent filers 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

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.

Western explores for, develops and produces, gathers, processes and treats, transports and markets natural gas and natural gas liquids, NGLs. In our upstream operations, we explore for, develop and produce natural gas reserves primarily in the Rocky Mountain region. In our midstream operations, 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, Gulf Coast and West Texas regions of the United States.

Historically, we have derived over 95% of our revenues from the sale of gas and NGLs. Our revenues by type of operation are as follows (dollars in thousands):

During the last several years, in order to reduce our overall debt level and provide us with additional liquidity to fund our key growth projects and to invest in new growth opportunities, we have sold several non-strategic assets. During the three year period ending December 31, 2001, we sold our Katy, Giddings, MiVida, Black Lake and Arkoma facilities, our wholly-owned subsidiary in California and our wholly-owned subsidiary Pinnacle Gas Treating, Inc. In the aggregate, we have received $230.9 million in net sale proceeds which were used to reduce our outstanding debt. Primarily as a result of these sales, our total debt was reduced from $504.9 million at December 31, 1998 to $366.7 million at December 31, 2001. The sales of these facilities reduced operating and administrative costs and have allowed us to focus on our core areas in which we have substantial operations. We are thus better positioned to pursue projects including new gas development prospects, asset consolidations and acquisitions with future growth potential.

Maximizing the value of our existing core assets is the focal point of our business strategy. Our core assets are our midstream operations in west Texas and Oklahoma and our fully integrated upstream and midstream assets in the Powder River and Green River Basins in Wyoming. Our long-term business plan is to increase shareholder value by: (i) doubling proven reserves and equity production of natural gas over the course of the next three to five years; (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. In order to achieve this goal, we will focus on continued development of our leasehold positions in the Powder River Basin coal bed methane, CBM, development, in the Green River Basin and in the Sand Wash Basin. We have acquired drilling rights on approximately 827,000 net acres in these and other Rocky Mountain basins. At December 31, 2001, we had proved developed and undeveloped reserves of approximately 476 billion cubic feet equivalent, Bcfe, on a portion of this acreage position. In total this represents an increase of approximately 15% in our proved reserves from December 31, 2000. Reserve life remains at over 13 years. Our production in 2001 increased by 31% to 36.3 Bcfe and we replaced 275% of our 2001 production. All of our 2001 reserve and production growth was achieved organically through the drill bit. As of December 31, 2001, we estimated that there was a net total of 2.1 trillion cubic feet, Tcf, of probable and possible reserves associated with our undeveloped acreage in these areas. In the Powder River Basin, this potential lies in over 10,000 development locations in the Big George, Wyodak and related coals. In the Green River Basin, our reserve potential lies in the development of 80-acre and 40-acre locations on our leasehold on the Pinedale Anticline.

We are also actively seeking to add another core project which is focused on Rocky Mountain natural gas. We will utilize our expertise in the low-risk development of coal bed methane plays and in tight-gas sands to evaluate acquisitions of either additional leaseholds, proven and undeveloped reserves or companies with operations focused in this area. The addition of another core project will ideally result in additional investment opportunities in our midstream operations.

Meet or Exceed Throughput Projections in our Midstream Operations. To achieve this goal, we must continue to seek to increase natural gas throughput levels through new well connections and expansion of gathering systems and to increase our efficiency by modernization of equipment and the consolidation of existing facilities. We also seek new growth opportunities for gathering and processing through our development of new gas reserves.

Our midstream 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 and process natural gas produced on acreage dedicated to us by third parties 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 and processing at our facilities. At December 31, 2001, our estimated dedicated reserves totaled 3.2 Tcf. This includes third party reserves dedicated to our facilities, our proven reserves, but does not include our 2.1 Tcf of probable and possible reserves. In 2001, including the reserves developed by us and associated with our partnerships and excluding the reserves and production associated with the facilities sold during this period, we connected new reserves to our facilities to replace approximately 190% of throughput. In 2001, we spent approximately $85.4 million on additional well connections and compression and gathering system expansions including acquisitions. 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.

Replacing and upgrading field equipment allows us to minimize maintenance costs, fuel consumption and field operating costs. For example, during 2000 and 2001 we invested $28.0 million to replace older compression at our Midkiff/Benedum facility with new, fuel efficient equipment. This upgrade has resulted in lower maintenance costs, reduced emissions and a decrease in our fuel consumption thereby increasing the natural gas available for 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. For example, the formation of Rendezvous Gas Services, L.L.C. with Questar Gas Management Company in the fourth quarter of 2001 increases gas available for processing at our Granger gas processing facility in southwest Wyoming while reducing our capital investment requirements.

Optimize Annual Returns. To optimize our annual returns, we will focus our efforts in our primary operating areas of the Powder River and Green River Basins in Wyoming, the Anadarko Basin in Oklahoma and the Permian Basin in west Texas. We review the economic performance and growth opportunities 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 or is outside of our core operating areas, we explore various options, such as consolidation with other Western-owned or third-party-owned facilities, dismantlement, asset trades or sale. Additionally, we routinely evaluate our business for methods to reduce our operating and administrative costs, including the implementation of new software and data management applications. For example, beginning in 2000 and continuing throughout 2001, we replaced many of our dry flow wellhead meters with electronic flow meters. Electronic flow meters reduce costs and increase the accuracy of volumetric information by electronically transmitting data to our central offices rather than collecting and replacing paper charts in the field.

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," "anticipate," "estimate," or "continue" or the negative thereof or other variations thereon or comparable terminology. This Form 10-K contains forward-looking statements regarding the expansion of our gathering operations, our project development schedules, our budgeted capital expenditures, success of our drilling activities, our marketing plans and anticipated volumes through our facilities and from production activities that involve a number of risks and uncertainties, including the composition of gas to be treated and the drilling schedules and success of the producers with acreage dedicated to our facilities. 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 our projections in this Form 10-K. See further discussion in "Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 2—Summary of Significant Accounting Policies—Use of Estimates and Significant Risks."

Our principal offices are located at 12200 North Pecos Street, Denver, Colorado 80234-3439, and our telephone number is (303) 452-5603. Western Gas Resources, Inc. was incorporated in Delaware in 1989.

In 2002, we anticipate capital expenditures of approximately $139.8 million, primarily for growth and expansion projects in our Rocky Mountain upstream and midstream operations. The 2002 budget represents an approximate 15% decrease from the amount expended in 2001 due to an expectation of lower commodity prices. The Rocky Mountain region will utilize 82% or $115.0 million of the 2002 budget. We plan to invest approximately $74.8 million, or 54% of our total capital program, in the Powder River Basin CBM development. Approximately $51.0 million will be spent on our share of drilling over 900 gross wells and for production equipment and undeveloped acreage and $23.8 million for gathering lines and installation of additional compression.

Another key area for capital investment for us is the Greater Green River Basin. We expect to invest approximately $35.1 million, or 25% of the total 2002 capital expenditure program, in this area. We will spend approximately $12.5 million to participate in approximately 30 gross wells, substantially all of which are in the rapidly developing Pinedale Anticline area, and $22.6 million to expand gathering and compression services. The remaining $24.8 million of our 2002 capital spending program is expected to be spent as follows: $10.9 million for well connections and expansions in our other operating areas, $4.0 million for maintenance and upgrade projects at existing facilities, $7 million for capitalized interest and overhead and $2.9 million for administrative expenditures. Due to drilling and regulatory uncertainties that are beyond our control, we can make no assurance that our capital budget for 2002 will not change. We anticipate that funds for the 2002 capital budget will be provided primarily by internally generated cash flow.

A vital aspect of our long-term business plan is to double proven reserves and equity production of natural gas over the course of the next three to five years. In order to achieve this goal, we will focus on continued development of our leasehold positions in the Powder River coal bed methane development, in the Green River Basin and in the Sand Wash Basin. Each of our existing upstream projects are 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.

Powder River Basin Coal Bed Methane. We continue to develop our Powder River Basin coal bed gas reserves and the associated gathering system in northeast Wyoming. The Powder River Basin coal bed methane area is currently one of the largest on-shore plays for the development of natural gas in the United States. Within this area, in 2001, we continued to be the largest producer of natural gas (together with our partner), the largest gatherer of natural gas and the largest gas transporter out of this basin. At December 31, 2001, we held the drilling rights on approximately 527,000 net acres in this basin. As of December 31, 2001, we had established proven developed and undeveloped reserves totaling 393 Bcfe on a portion of this acreage. This represented a 12% increase in proved reserves as compared to December 31, 2000. As of December 31, 2001, we estimated that there was a net total of 1.9 Tcf of probable and possible reserves associated with our undeveloped acreage in this area. There can be no assurance, however, as to the ultimate recovery of these reserves.

We participated in the drilling of 819 gross coal bed methane wells in 2001 and plan to participate in over 900 gross wells in 2002. The average drilling and completion cost for our coal bed methane gas wells is approximately $90,000 per well with average reserves per successful well of approximately 250 to 320 million cubic feet, MMcf. Our average finding and development costs in this area are estimated to be approximately $0.42 per Mcf. As deeper wells are drilled to the Big George coal, reserves per well are expected to increase as will the average cost per well. It is expected that the deeper Big George wells will result in a higher rate of return. Our share of production from wells in which we own an interest has increased from an average of approximately 78 MMcf per day at December 31, 2000 to 107 MMcf per day at December 31, 2001, which met our year-end target. We currently anticipate production rates of 145 net MMcf per day (370 gross MMcf per day) from this area by the end of 2002. Within the Hoe Creek area of the Powder River Basin, approximately 150 gross wells have not responded to dewatering as expected and may not achieve our original estimate of production or reserves. All of the remaining areas under development in the Wyodak coal continue to produce at or above forecasted levels.

We are currently evaluating fourteen pilot development areas in the Big George. By the end of 2002, we expect to have drilled approximately 300 gross wells in these areas. Five of these pilot areas are currently in the de-watering phase. Several of these areas are in close proximity to four producing Big George areas, including our All Night Creek pilot. Production from these areas is increasing and in the first quarter of 2002, they were producing over 16 MMcf per day. As of February 20, 2002, our All Night Creek pilot was producing 6.4 gross MMcf per day of gas from 40 wells with an additional 43 wells in the de-watering stage. At December 31, 2001, we had proven reserves of 26 Bcfe in the Big George coal.

Future drilling on federal acreage will be delayed subject to completion of the Powder River Basin Oil & Gas Environmental Impact Statement. We anticipate the study to be completed in the third quarter of 2002. Our drilling plans for 2002 are not expected to be substantially impacted by this study due to our large inventory of non-federal drilling locations and the issuance of drilling permits by the Bureau of Land Management, BLM, for approximately 250 well locations to prevent drainage of federal acreage.

Additionally, the Wyoming Department of Environmental Quality, 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 wells on our acreage producing from the Wyodak formation drain into these areas. The Wyoming and Montana DEQ offices have reached agreement on procedures for discharging and monitoring water into the Powder River drainage areas, in which most of our Big George prospects are located. The Wyoming DEQ has begun to release permits on a limited basis to the Powder River drainage area, however only when it can be demonstrated that none of the discharge water will reach the Powder River itself. Discussions are in progress between the Wyoming and Montana DEQ offices to implement numeric standards for sodium absorption ratio, electro-conductivity and total dissolved solids. We can make no assurance that the conditions under which additional permits will be granted will not impact the level of our drilling or the timing of the associated production.

In addition to the revenues earned from the production of our coal bed methane gas, we also earn fees for gathering and transporting the natural gas. In December 2001, we were gathering 348 MMcf per day of our own production and of other third-party producers. Of that volume, approximately 140 MMcf per day was transported through our wholly-owned MIGC pipeline.

Our capital budget in the Powder River Basin coal bed development provides for expenditures of approximately $74.8 million during 2002. This capital budget includes approximately $51.0 million for drilling costs for our interest in over 900 wells, production equipment and undeveloped acreage and $23.8 million for gathering lines and installation of compression. We have entered into several operating leases for compression equipment. As of December 31, 2001, we had leased a total of 85 compression units. These leases have terms ranging from two to ten years with fair market purchase options available at various times during the lease. Depending upon future drilling success, we may need to make additional capital expenditures or leasing commitments to continue expansion in this basin. Due to drilling and regulatory uncertainties which are beyond our control, we can make no assurance that we will incur this level of capital expenditure. During 2001, capital expenditures in this area totaled $82.1 million.

In 1998, we joined with other industry participants to form Fort Union Gas Gathering, L.L.C., to construct a 106-mile long, 24-inch gathering pipeline and treater to gather and treat natural gas in the Powder River Basin in northeast Wyoming. We own a 13% equity interest in Fort Union and are the construction manager and field operator. The gathering header initially had a capacity of approximately 435 MMcf per day. The header 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 went into service in the third quarter of 1999. Construction of the gathering header and treating system was project financed by Fort Union and required a cash investment by us of approximately $900,000. In 1999, we entered into a ten year agreement for firm gathering services on 60 MMcf per day of capacity at $0.14 per Mcf on Fort Union. In the fourth quarter of 2000, Western and the other participants in Fort Union approved an expansion of the system. Construction of the 62-mile expansion was completed in the third quarter of 2001 and brought the system's capacity to 635 MMcf per day. The expansion costs totaled approximately $22.0 million and were project financed by Fort Union. In the fourth quarter of 2001, we invested approximately $500,000 as an equity contribution to Fort Union in conjunction with the project financing. Also in connection with the expansion, we increased our commitment for firm gathering services, effective December 2001, to a total of 83 MMcf per day of capacity at $0.14 per Mcf. All participants in Fort Union have guaranteed the project financing on a proportional basis resulting in our guarantee of $7.3 million of the debt of Fort Union. This guarantee is not reflected on our Consolidated Balance Sheet.

Green River Basin. Our assets in the Green River Basin of southwest Wyoming 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., our Red Desert facility and production in the Jonah Field and Pinedale Anticline areas. These facilities have a combined operational capacity of 327 MMcf per day and processed an average of 190 MMcf per day in 2001. Our capital budget in this area provides for expenditures of approximately $35.1 million during 2002. This capital budget includes approximately $12.5 million for drilling costs and production equipment and approximately $22.6 million related to the gathering systems, plant facilities and additional capital contributions to Rendezvous. 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 2001, we expended $27.2 million in this area which included the purchase of the remaining 50% interest in the Bird Canyon gathering system serving the Granger Complex.

In September 2001, we signed an agreement with Questar for the sale of a 50% interest in a segment of the Bird Canyon gathering system along with associated field compression for $5.2 million. This sale closed in October 2001. Both Questar and Western contributed our respective interests in the Bird Canyon system along with additional field compression and gathering dedications for gas produced along the Pinedale Anticline to Rendezvous. Each company owns a 50% interest in Rendezvous, and we serve as field operator of its systems. In the fourth quarter of 2001, Rendezvous began construction of additional gas gathering pipeline and compression facilities with a capacity to transport approximately 275 MMcf per day of gas production from the Pinedale Anticline. This gas will be delivered for blending or processing at either our Granger Complex or at a Questar processing facility. The total estimated construction cost of this expansion is $44.0 million, of which our share will be $22.0 million. Of this $22.0 million, approximately $18.3 million is expected to be spent in 2002 and is included in our capital expenditure budget.

At December 31, 2001, we owned approximately 245,000 gross oil and gas leasehold acres, or approximately 35,000 net acres, in the Jonah Field and Pinedale Anticline areas. During 2001, we participated in 37 gross wells, or 5 net wells, in these areas and experienced a success rate in excess of 95%. During 2002, we expect to participate in the drilling of over 30 gross wells, or approximately 4 net wells on the Pinedale Anticline. The expected drilling and completion costs per gross well are approximately $2.4 million to $3.5 million and the average well depth in this area approximates 13,000 feet. Our average finding and development costs are estimated to be $0.80 to $0.90 per Mcf. We had established proven developed and undeveloped reserves totaling 71 Bcfe at December 31, 2001. This represents a 29% increase as compared to December 31, 2000. As of December 31, 2001, we estimate a net total of 101 Bcf of probable and possible reserves associated with undeveloped acreage in this area. 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. We own approximately 199,000 gross oil and gas leasehold acres, or approximately 172,000 net acres, in this basin. In December 2001, we were producing an average of 2 MMcf per day from this acreage. At December 31, 2001, we had established proven developed and undeveloped reserves totaling 12 Bcfe on a portion of this acreage. This represented a 76% increase in proved reserves as compared to December 31, 2000. The majority of this acreage is in the exploration phase and will be evaluated in 2002 and subsequent years. Our capital budget in this area provides for expenditures of approximately $1.7 million during 2002 for our participation in the drilling of 2 gross wells, or 1 net well. The expected drilling and completion costs per gross well are approximately $835,000 to $1.0 million and the average well depth in this area approximates 7,500 feet. Our average finding and development costs are estimated to be $0.39 per Mcf. During 2001, capital expenditures in this area totaled $879,000 for our participation in the drilling of 2 gross wells, or 1 net well, in this area.

Production Information. Revenues derived from our producing properties comprised approximately 3.2%, 2.7% and 1.6% of consolidated revenues for the years ended December 31, 2001, 2000 and 1999, respectively. The operating margin (revenues less product purchases and operating expenses) derived from our producing properties comprised approximately 23.8%, 26.5% and 15.4% of consolidated gross margin for the years ended December 31, 2001, 2000 and 1999, respectively. Primarily as a result of the increased investment in the Powder River coal bed methane, we expect both the revenues and operating margin derived from our producing properties to continue to increase.

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

We employ a total staff of ten full time reservoir and production engineers and geologists who complete annual reserve estimates of dedicated reserves behind each of our existing facilities. The reserve report for the Powder River coal bed methane gas and other Wyoming assets for 2001 has been audited by Netherland, Sewell & Associates, Inc.

Our reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved and probable 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. Our estimates of reserves dedicated 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 includes our proprietary data.

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 to seek to increase natural gas throughput levels through new well connections and expansion of gathering systems and increase our efficiency by modernization of equipment and the consolidation of existing facilities.

Overall, we operate a total of 18 gathering, processing and treating facilities, or plant operations, with approximately 9,200 miles of gathering lines. These facilities are located in six states and have a combined throughput capacity of 2.3 billion cubic feet, 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 States. In 2001, we gathered an average of 1.4 Bcf per day of natural gas, produced natural gas for delivery to markets of 1.1 Bcf per day and produced 1.8 Mgal per day of NGLs. 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 and Oklahoma. 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. See further discussion in "Upstream Operations—Powder River Basin Coal Bed Methane and—Green River Basin."

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. Six 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 which require removal prior to transportation. At a treating facility, we treat dry gas, which does not contain liquids that we can economically extract, by removing hydrogen sulfide or carbon dioxide 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. 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 certain individual plants have experienced declines in dedicated reserves, we have been successful in connecting additional reserves to more than offset the natural declines. From 1996 through 1999, there was a reduction in drilling activity, primarily in basins that produce oil and casinghead gas, due to low commodity prices. In 2000 and continuing throughout 2001, gas and oil prices increased significantly and resulted in additional drilling behind our systems. Overall, 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 are within our control. At December 31, 2001, our estimated dedicated reserves totaled 3.2 Tcf. This includes third party reserves dedicated to our facilities, our proven reserves, but does not include our 2.1 Tcf of probable and possible reserves. In 2001, including the reserves developed by us and associated with our partnerships and excluding the reserves and production associated with the facilities sold during this period, we connected new reserves to our facilities to replace approximately 190% of throughput.

Substantially all gas flowing through our gathering, processing and treating facilities is supplied under three types of long-term contracts providing for the purchase, treating or processing of natural gas for periods ranging from five to twenty years. Approximately 57% of our plant facilities' gross margins, or revenues at the plants less product purchases, for the month of December 2001 resulted from percentage-of-proceeds agreements in which we are typically responsible for the marketing of the gas and NGLs. We pay producers a specified percentage of the net proceeds received from the sale of the gas and the NGLs. This type of contract allows us and the producers to share proportionally in price changes.

Approximately 27% of our plant facilities' gross margins for the month of December 2001 resulted from 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. The proportion of fee-based contracts is expected to increase as the volumes from the Powder River Basin coal bed methane development increase. See further discussion in "—Upstream Operations."

Approximately 16% of our plant facilities' gross margins for the month of December 2001 resulted from contracts that combine gathering, compression or processing fees with "keepwhole" arrangements or wellhead purchases. Typically, we charge producers a gathering and compression fee based upon volume. In addition, we retain a predetermined percentage of 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.

West Texas. Our primary assets in west Texas are the Midkiff/Benedum complex and the Gomez treating facility. These facilities process gas produced in the Permian basin, have a combined operational capacity of 445 MMcf per day and processed an average of 246 MMcf per day in 2001. In 2001, these facilities produced 188 MMcf per day of natural gas for delivery to sales markets and produced 888 MGal per day of NGLs. Our capital budget in this area provides for expenditures of approximately $6.1 million during 2002. This capital budget includes approximately $4.2 million for additions to the gathering systems and plant facilities and approximately $1.9 million for replacing and upgrading field and plant equipment. During 2001, we expended $27.4 million in this area.

In order to remain competitive with other plant operators in the gathering, processing and treating business, it is very important to be a low-cost, efficient operator. During 2000 and 2001, we have replaced older compressors at our Midkiff/Benedum complex with new, fuel efficient equipment. This upgrade has resulted in lower maintenance costs, reduced emissions and a decrease in our fuel consumption thereby increasing the natural gas available for sale. During 2001, we invested $17.9 million on this project and our 2002 capital budget includes an additional $700,000 to complete the upgrade.

Oklahoma. Our primary assets in Oklahoma are the Chaney Dell and Westana systems. These facilities process gas produced in the Anadarko Basin and have a combined operational capacity of 175 MMcf per day. In 2001, these facilities processed an average of 137 MMcf per day, produced 117 MMcf per day of natural gas for delivery to sales markets and produced 239 MGal per day of NGLs. In 2001, we completed an extension of the Westana gathering system providing for an additional 30 MMcf per day of capacity. Our capital budget in this area provides for expenditures of approximately $8.4 million during 2002. This capital budget includes approximately $6.8 million for additions to the gathering systems and plant facilities and approximately $1.6 million for replacing and upgrading field and plant equipment. During 2001, we expended $16.3 million in this area.

Principal Facilities. The following tables provide information concerning our principal facilities at December 31, 2001. We also own and operate several smaller treating, processing and transportation facilities located in the same areas as our other facilities.

A description of the significant midstream acquisitions and dispositions since January 1, 1997, other than the Powder River Basin coal bed methane development and southwest Wyoming which were previously discussed, are:

Bethel Treating Facility. In 1996 and 1997, the Pinnacle Reef exploration area was rapidly developing into a very active lease acquisition and exploratory drilling area using 3-D seismic technology to identify prospects. The initial discoveries indicated a very large potential gas development. Based on our receipt of large acreage dedications in this area, we, through our wholly-owned subsidiary Pinnacle Gas Treating, Inc., constructed the Bethel treating facility for a total cost of approximately $102.8 million with a throughput capacity of 300 MMcf per day. In 1998, the production rates from the wells drilled in this field and the recoverable reserves from these properties were far less than the producers originally expected.

In the fourth quarter of 1998, because of uncertainties related to the pace and success of third-party drilling programs, declines in volumes produced at several wells and other conditions outside our control, we determined that an evaluation of the Bethel treating facility, in accordance with accounting standards, was necessary. We compared the net book value of the assets to the discounted expected future cash flows of the facility and determined that the results of this comparison required a pre-tax, non-cash impairment charge of $77.8 million.

In December 2000, we signed an agreement with Anadarko Petroleum Corporation for the sale of all the outstanding stock of our wholly-owned subsidiary, 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 pre-tax gain for financial reporting purposes of $12.1 million in the first quarter of 2001.

Arkoma. In August 2000, 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 2000, 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 2000, we sold all of 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. The pipeline was acquired through the exercise of an option by us in a transaction which closed simultaneously with the sale of WGR-California. We recognized a pre-tax gain on the sale of approximately $5.4 million in the first quarter of 2000.

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 2000. This transaction resulted in an approximate pre-tax loss of $7.3 million, which was recognized in the fourth quarter of 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 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. To meet the needs of our marketing operations, we continue to contract for storage capacity at the Katy facility and in other locations. At the time of the sale, we entered into a long-term agreement with the purchaser for approximately 3 Bcf of storage capacity at market rates. This contract expires in March 2002.

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 the second quarter of 1999.

Edgewood. In two transactions which closed in October 1998 we sold our Edgewood gathering system, including our undivided interest in the producing properties associated with this facility, and our 50% interest in the Redman Smackover Joint Venture. The combined sales price was $55.8 million. We recognized a pre-tax gain of approximately $1.6 million during the fourth quarter of 1998.

Perkins. In November 1997, we entered into an agreement to sell our Perkins facility. In March 1998, we completed the sale of this facility, with an effective date of January 1, 1998. The sales price was $22.0 million and resulted in a pre-tax gain of approximately $14.9 million.

Other. 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.

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. Historically, our gas marketing was an outgrowth of our gas processing activities and was directed towards selling gas processed at our plants to ensure their efficient operation. As the natural gas industry became deregulated and offered more opportunity, we began to increase our third-party gas marketing. For the year ended December 31, 2001, our total gas sales volumes averaged 2.0 BcfD. Third-party sales, firm transportation capacity on market 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. We sell gas under agreements with varying terms and conditions in order to match seasonal and other changes in demand. The duration of our sales contracts range from one day to eight years with an average tenure of 17 months. In addition to our offices in Denver and Houston, we have a marketing office in Calgary, Alberta. The Calgary office also provides us with information regarding market conditions in Canada which affect the gas markets in the United States. During the year ended December 31, 2001, we sold gas to approximately 260 end-users, pipelines, LDCs and other customers. One customer accounted for approximately 5% of our consolidated revenues from the sale of gas, or 4% of total consolidated revenue, for the year ended December 31, 2001. This customer is a wholly-owned subsidiary of a major integrated oil company.

Our 2002 gas marketing plan emphasizes growth through our asset base and storage and transportation capacities which we control. In general, we do not expect to increase our third-party sales volumes in 2002 significantly from levels achieved in 2001. We continually monitor and review the credit exposure to our marketing counterparties. On December 2, 2001, Enron Corp. and many of its affiliates and subsidiaries filed a petition for bankruptcy protection under Chapter 11 of the Bankruptcy code in the Southern District of New York. At the time of Enron's filing, our exposure to them totaled approximately $2.7 million. This amount includes the net exposure from physical gas transactions of $100,000, which is comprised of physical gas sales of $8.4 million and physical gas purchases of $8.3 million. We have in place a netting agreement with Enron for the purchase and sale of physical gas. Although similar netting agreements have been upheld by bankruptcy courts in the past, we can provide no assurance that our agreement will not be challenged or as to the outcome of any challenge. The remaining $2.6 million of net exposure is under a Master Swap Agreement related to derivative transactions. As a result, we incurred an additional charge to income of $2.7 million in 2001.

We continue to view access to storage capacity as a significant element of our marketing strategy. 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, 2001, we had contracts in place for approximately 17.3 Bcf of storage capacity at various third-party facilities. The fees associated with these contracts during 2002 will average $0.30 per Mcf of annual capacity, and the associated contract periods range from three months to three years, with an average tenure of one and one-half years. Several of these long-term storage contracts require an annual renewal. At December 31, 2001, we held gas in storage and in imbalances of approximately 16.9 Bcf at an average cost of $2.39 per Mcf compared to 10.9 Bcf at an average cost of $3.88 per Mcf at December 31, 2000 under these storage contracts. These positions will be substantially liquidated within the first quarter of 2002. Under mark-to-market accounting, the profit to be earned on these transactions was recorded in the month of origination. See further discussion in "Midstream Operations—Gas Gathering, Processing and Treating—Katy" and "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

We also continue to view access to firm transportation as a significant element of our marketing 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, 2001, we had contracts for approximately 628 MMcf per day of firm transportation. This amount represents our total contracted amount on each individual pipeline. In many cases it is necessary to utilize sequential pipelines to deliver gas into a specific sales market. For example, to transport 100 MMcf per day of gas produced in the Powder River to the Mid-Continent utilizes a total of 300 MMcf per day of firm capacity on four separate pipelines. The fixed fees associated with these contracts during 2002 will average approximately $0.13 per Mcf per day, and the associated contract periods range from three months to fifteen years. In addition, some contracts contain provisions requiring us to pay the fees associated with these contracts whether or not the transportation is used. We have also entered into 168 MMcf per day of firm transportation precedent agreements for transportation on pipeline expansions which are not completed. These expansions are anticipated to be completed in 2002. When the expansions are completed, we will enter into firm transportation agreements. See further discussion in "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

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, Gulf Coast 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, 2001, NGL sales averaged 2,350 MGal per day.

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. Over the last several years, the petrochemical industry has increased its use of NGLs as a major feedstock and is projected to continue to increase such usage. Further, consumers use propane for home heating, transportation and for agricultural applications. Price, seasonality and the economy primarily affect the demand for NGLs.

We decreased sales to third parties by approximately 730 MGal per day for the year ended December 31, 2001 compared to 2000. In general, we do not anticipate that sales to third parties in 2002 will vary significantly from those experienced in 2001.

From time to time, we lease NGL storage space at major trading locations in order to store products for resale during periods when prices are favorable and to facilitate the distribution of products. At December 31, 2001, we also held NGLs in storage of 5,665 MGal, consisting primarily of propane and normal butane, at an average cost of $0.33 per gallon compared to 6,229 MGal at an average cost of $0.49 per gallon at December 31, 2000 at various third-party storage facilities. These inventory positions will be substantially liquidated within the first quarter of 2002. Under mark-to-market accounting, the profit to be earned on these transactions was recorded in the month of origination.

During the year ended December 31, 2001, we sold NGLs to 113 customers. These customers are end-users, fractionators, chemical companies and other customers. Three customers accounted for approximately 37% of our consolidated revenues from the sale of NGLs, or 5% of total consolidated revenue, for the year ended December 31, 2001. These customers are all large integrated energy companies. We also derive revenues from contractual marketing fees charged to some producers for NGL marketing services. For the year ended December 31, 2001, these fees were less than 1% of our consolidated revenues.

We own and operate MIGC, an interstate pipeline located in the Powder River Basin in Wyoming, and MGTC, an intrastate pipeline located in northeast Wyoming. MIGC charges a 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 2001, MIGC operated at capacity and transported an average of 193 MMcf per day. It is anticipated that MIGC will continue at capacity for the next several years. See further discussion in "Midstream Operations—Gas Gathering, Processing and Treating" and for a further discussion of the revenues, operating profits and attributable assets of this business segment, see "Item 8-Financial Statements and Supplementary Data." MGTC provides transportation and gas sales to the Wyoming cities of Gillette, Moorcroft and Wright 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, the FERC has proposed to limit the use of affiliates' employees in the operation of regulated entities. We can make no assurances as to the ultimate regulations passed by the FERC or the effects such regulations may have on the operating costs of MIGC.

The construction and operation of our gathering systems, plants and other facilities used for the gathering, processing, treating or transportation 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 an environmental manager, a safety manager, five environmental engineers, four safety specialists and three regulatory compliance specialists to monitor environmental and safety compliance at our facilities. Prior to consummating any major acquisition, our environmental engineers perform audits on the facilities to be acquired. In addition, on an ongoing basis, the 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. We believe that the costs for compliance with current environmental laws and regulations have not had and will not have a material effect on our financial position or results of operations.

The Texas Natural Resource Conservation Commission, which has authority to regulate, among other things, stationary air emissions sources, has created a committee to make recommendations to the Commission 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, we are replacing all of our "grand-fathered" compressors in Texas and we completed this project in March of 2002. Other "grand-fathered" sources are subject to increasing emissions fees beginning in 2002. We do not believe that such increases will have a material effect on our financial position or results of operations.

We anticipate that it is reasonably likely that the trend in environmental legislation and regulation will continue to be towards stricter standards. We are unaware of future environmental standards that are reasonably likely to be adopted that will have a material effect on our financial position or results of operations, but we cannot rule out that possibility.

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 $1.3 million for the year ended December 31, 2001, including approximately $509,000 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 effect on our financial position or results of operations.

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 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. In recent years, we have experienced narrowing margins related to third-party sales due to the increasing availability of pricing information in the natural gas industry. 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.

Our purchase and sale of natural gas 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 which can 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 Federal Energy Regulatory Commission, or 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 certain 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 certain 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 provide open access gas gathering and to establish rates, terms and conditions of services which a gas gatherer provides. In addition, state legislatures and regulators in other states, including Wyoming, in which we gather gas are also contemplating additional regulation of gas gathering. 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 or results of operations. 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.

At December 31, 2001, we employed approximately 639 full-time employees, of which 376 are employed at field locations. Due to cost reduction programs and asset divestitures, the total number of employees has declined by 231 since December 31, 1998. None of our employees are union members. We consider relations with employees to be excellent.

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

There were no matters submitted to a vote of security holders during the quarter ended December 31, 2001.

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

As of March 1, 2002, there were 32,703,009 shares of Common Stock outstanding held by 226 holders of record. The Common Stock is traded on the New York Stock Exchange 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.

	HIGH		LOW
2001
Fourth Quarter	$	35³/4	$	26¹/8
Third Quarter		33¹/2		24³/4
Second Quarter		43¹/2		31⁵/8
First Quarter		33³/4		25³/8
2000
Fourth Quarter	$	34³/4	$	21⁷/8
Third Quarter		27¹/4		18¹/8
Second Quarter		23¹/2		15¹/2
First Quarter		17⁷/8		10⁷/8

We paid annual dividends on our Common Stock aggregating $0.20 per share during the years ended December 31, 2001 and 2000. We have declared a dividend of $0.05 per share of Common Stock for the quarter ending March 31, 2002 to holders of record as of March 29, 2002. 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 certain covenants in our financing facilities, the most restrictive of which 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 subordinated note 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, 2001, availability under this covenant was approximately $41.1 million.

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 2001. The data for the three years ended December 31, 2001, 2000 and 1999 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, 1998 and 1997 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."

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, 2001, 2000 and 1999. Certain prior year amounts have been reclassified to conform to the presentation used in 2001. 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.

Year ended December 31, 2001 compared to year ended December 31, 2000
(000s, except per share amounts and operating data)

Net income increased $39.5 million for the year December 31, 2001 compared to 2000. The increase in net income was primarily attributable to higher gas prices in 2001 compared to the prior year, increased production from the Powder River Basin coal bed methane development, and improved results from our marketing segment.

Revenues from the sale of gas increased $220.2 million to $2,844.6 million in the year ended December 31, 2001 compared to 2000. This increase was primarily due to an improvement in product prices and to a lesser extent from an increase in sales of natural gas purchased from third parties. Average gas prices realized by us increased $0.07 per Mcf to $3.97 per Mcf in the year ended December 31, 2001 compared to 2000. Included in the realized gas price were approximately $9.3 million of gains recognized in the year ended December 31, 2001 related to futures positions on equity gas volumes. We have entered into additional futures positions for the majority of our equity gas for 2002. See further discussion in "Item 7A. Quantitative and Qualitative Disclosure About Market Risk". Average gas sales volumes increased 125 MMcf per day to 1,960 MMcf per day in the year ended December 31, 2001 compared to 2000. This increase in sales volume was primarily due to an increase in the sale of third-party product.

Revenues from the sale of NGLs decreased approximately $166.9 million in the year ended December 31, 2001 compared to 2000. This decrease was due to a reduction in sales volume and a decrease in product prices. Average NGL prices realized by us decreased $0.03 per gallon to $0.49 per gallon in the year ended December 31, 2001 compared to 2000. Included in the realized NGL price were approximately $2.1 million of gains recognized in the year ended December 31, 2001 related to futures positions on equity NGL volumes. We have entered into additional futures positions for a portion of our equity NGL production for 2002. See further discussion in "Item 7A. Quantitative and Qualitative Disclosure About Market Risk". Average NGL sales volumes decreased 735 MGal per day to 2,350 MGal per day in the year ended December 31, 2001 compared to 2000. This decrease was primarily due to an intentional reduction in the sale of third-party product as these types of sales were generating minimal margins. Also contributing to the reduction in overall sales volume was a decrease in the sale of product produced at our facilities as we did not recover ethane for a portion of 2001 due to low ethane prices.

Product purchases increased by $1.4 million in the year ended December 31, 2001 compared to 2000. Overall, combined product purchases as a percentage of sales of all products decreased to approximately 91% in the year ended December 31, 2001 from 93% in 2000. The decrease in the product purchase percentage resulted from improved marketing margins and the intentional reduction in the sale of third-party NGL products.

Marketing margins on residue gas averaged $0.06 per Mcf in 2001. This represented a significant increase as compared to the $0.02 per Mcf marketing margin realized during 2000. The increase in margin for the year ended December 31, 2001 primarily resulted from volatility in gas prices, gains realized on our firm transportation capacity and from the mark-to-market of transactions utilizing a portion of this firm transportation capacity primarily during 2002 and the mark-to-market of storage transactions for the winter season ending in March 2002. Under mark-to-market accounting, which we adopted on January 1, 2001, the margin to be realized over the term of the transaction is recorded in the month of origination. Of the total margin earned in the marketing segment of $47.6 million, approximately $19.9 million resulted from the portion of sales transactions beyond 2001 including the marking to market at December 31, 2001 of our derivative positions as required by SFAS No. 133. This margin is included in the financial statement caption Non-cash change in fair value of derivatives.

Marketing margins on NGLs averaged approximately $0.005 per gallon in the year ended December 31, 2001. This represents a decrease as compared to the margin realized during 2000 of $0.007 per gallon. This decrease has resulted in our decision to intentionally reduce the sale of third-party NGL products. There is no assurance that these market conditions for our gas and NGL products and related margins will continue in the future, that we will be in a similar position to benefit from them or that we will continue to originate the same amount of transactions in future quarters.

On December 2, 2001, Enron Corp. and many of its affiliates and subsidiaries filed a petition for bankruptcy protection under Chapter 11 of the Bankruptcy code in the Southern District of New York. At the time of Enron's filing, our exposure to them totaled approximately $2.7 million. This amount includes the net exposure from physical gas transactions of $100,000, which is comprised of physical gas sales of $8.4 million and physical gas purchases of $8.3 million. We have in place a netting agreement with Enron for the purchase and sale of physical gas. Although similar netting agreements have been upheld by bankruptcy courts in the past, we can provide no assurance that our agreement will not be challenged or the outcome of any challenge. The remaining $2.6 million of net exposure is under a Master Swap Agreement related to derivative transactions. As a result, we incurred an additional charge to income of $2.7 million in 2001. This exposure to Enron is not included in the calculation of the marketing margins and is primarily reported in Selling and administrative expenses.

Plant operating expense increased $5.6 million in 2001 compared to 2000. This increase was primarily due to additional leased compression in the Powder River Basin coal bed development and higher fuel costs at our plant facilities.

Oil and gas exploration and production expenses increased by $8.0 million in 2001 as compared to 2000. The increase in the period is primarily as a result of our overall increasing operations in the Powder River Basin coal bed methane development.

Depreciation, depletion and amortization increased by $6.2 million for the year ended December 31, 2001 as compared to 2000, primarily as a result of our increasing operations in the Powder River Basin coal bed methane development.

Extraordinary charge for early extinguishment of debt decreased for the year ending December 31, 2001 as compared to 2000 as a result of an after-tax charge of $1.7 million incurred in third quarter of 2000. In September 2000, we prepaid $27.0 million of outstanding indebtedness originally due to be paid in November 2005, with funds available under our Revolving Credit Facility. In connection with this prepayment, we paid a pre-tax make-whole payment of approximately $2.0 million and expensed capitalized fees of approximately $752,000.

Preferred Stock Redemption. On November 12, 2001, we issued a notice of redemption for approximately 800,000 shares of our $2.28 cumulative preferred stock at its liquidation preference. This totaled $20.6 million including accrued and unpaid dividends. The redemption date was December 10, 2001 and was funded with amounts available under our Revolving Credit Facility. The pro rata capitalized offering costs of $900,000 associated with the redeemed preferred stock were reflected as a special dividend to preferred shareholders in 2001 and, accordingly, reduced earnings available to common shareholders by approximately $0.03 per common share.

Bethel Treating Facility. In December 2000, we signed an agreement with Anadarko Petroleum Corporation for the sale of all the outstanding stock of our wholly-owned subsidiary, 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 an approximate pre-tax gain for financial reporting purposes of $12.1 million in the first quarter of 2001.

Arkoma. In August 2000, 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.

Western Gas Resources-California, Inc. In January 2000, we sold all the outstanding stock of our wholly-owned subsidiary, WGR-California, for $14.9 million. The only asset of this subsidiary was a 162-mile pipeline in the Sacramento Basin of California. The pipeline was acquired through the exercise of an option by us in a transaction which closed simultaneously with the sale of WGR-California. We recognized a pre-tax gain on the sale of approximately $5.4 million in the first quarter of 2000.

The proceeds from these sales were used to reduce borrowings outstanding on the Revolving Credit Facility.

Westana. In February 2000, we acquired the remaining 50% interest in the Westana Gathering Company for a net purchase price of $9.8 million. The results from our ownership through February 2000 of a 50% equity interest in the Westana Gathering Company are reflected in revenues in Other on the Consolidated Statement of Operations. Beginning in March 2000, the results of these operations are fully consolidated and are included in Revenues and Costs and expenses. Additionally, in March 2000, our investment in the Westana Gathering Company was reclassified from Other assets to Property and equipment.

Granger Complex. In May 2001, we acquired the remaining 50% interest in a portion of the Bird Canyon gathering system serving the Granger Complex for a net purchase price of $5.9 million in cash and the settlement of previously disclosed litigation. In September 2001, we signed an agreement with Questar Gas Management Company for the sale of a 50% interest in a segment of the Bird Canyon gathering system along with associated field compression for $5.2 million. This sale closed in October 2001. These assets were reclassified on the Consolidated Balance Sheet to Assets held for sale at September 30, 2001 and a $400,000 pre-tax loss on the excess of the net book value over the sales price of these assets was recognized in the third quarter of 2001.

Also in October 2001, both Questar and Western contributed our respective interests in the Bird Canyon system along with additional field compression and gathering dedications for gas produced along the Pinedale Anticline to a newly formed joint venture named Rendezvous Gas Services, L.L.C. Each company owns a 50% interest in Rendezvous, and we will serve as field operator of its systems. In the fourth quarter of 2001, Rendezvous began construction of additional gas gathering pipeline and compression facilities with a capacity to transport approximately 275 MMcf per day of gas production from the Pinedale Anticline. The first phase of this expansion is expected to be complete in March 2002. This gas will be delivered for blending or processing at either our Granger Complex or at a Questar processing facility. The total estimated construction cost of this expansion is $44.0 million, of which our share will be $22.0 million. Of this $22.0 million, approximately $18.3 million is expected to be spent in 2002 and is included in our capital expenditure budget. Our 50% interest in Rendezvous is accounted for under the equity method.

Year ended December 31, 2000 compared to year ended December 31, 1999
(000s, except per share amounts and operating data)

Net income increased $73.2 million for the year ended December 31, 2000 compared to 1999. The increase in net income was primarily attributable to significantly higher gas and NGL prices in 2000 compared to the prior year, increased production from the Powder River Basin coal bed methane development, improved marketing margins, an after-tax gain of $3.3 million recognized on the sale of the stock of our wholly-owned subsidiary, Western Gas Resources-California, in the first quarter of 2000 and an after-tax gain of $2.4 million recognized on the sale of the Arkoma gathering system in the third quarter of 2000. These increases were partially offset by after-tax losses on hedging activities on our equity gas and NGLs of $24.6 million and an after-tax extraordinary charge of $1.7 million for the early extinguishment of long-term debt, also in the third quarter of 2000. The results for the year ended December 31, 1999 were negatively affected by a combined after-tax loss of $21.6 million from the sale of the Giddings, Katy, MiVida and Black Lake facilities and related severance charges, settlement of ongoing litigation and an after-tax extraordinary charge of $1.1 million for the early extinguishment of long-term debt.

Revenues from the sale of gas increased $1,123.3 million to $2,624.4 million for the year ended December 31, 2000 compared to 1999. This increase was due to an improvement in product prices in 2000 which more than offset a reduction in sales volume. Average gas prices realized by us increased $1.73 per Mcf to $3.90 per Mcf for the year ended December 31, 2000 compared to 1999. Average gas sales volumes decreased 65 MMcf per day to 1,835 MMcf per day for the year ended December 31, 2000 compared to 1999. This decrease was due to a reduction in the sale of gas purchased from third parties resulting from the sale in 1999 of our Katy gas storage facility, which more than offset an increase in volumes available from our coal bed methane production.

Revenues from the sale of NGLs increased approximately $244.1 million for the year ended December 31, 2000 compared to 1999. This increase is due to an improvement in product prices and an increase in sales volume. Average NGL prices realized by us increased $0.19 per gallon to $0.52 per gallon for the year ended December 31, 2000 compared to 1999.

Average NGL sales volumes increased 200 MGal per day to 3,085 MGal per day for the year ended December 31, 2000 compared to 1999. This increase in NGL volume is due to an increase in the sale of NGLs purchased from third parties.

Product purchases increased by $1,269.7 million for the year ended December 31, 2000 compared to 1999 primarily due to an increase in commodity prices and an increase in NGLs purchased from third parties. Overall, combined product purchases as a percentage of sales of all products remained the same at 93% for the year ended December 31, 2000 and in 1999.

Marketing margins on residue gas averaged $0.017 per Mcf in 2000. This represents a significant increase as compared to the margins realized during 1999 of $0.011 per Mcf. The margins realized in 2000 were reflective of the volatile market conditions and our ability to benefit from these conditions through our transportation arrangements. Marketing margins on NGLs averaged $0.007 per gallon for the year ended December 31, 2000 compared to approximately $0.004 per gallon in 1999. There is no assurance, however, that these market conditions for our gas and NGL products and related margins will continue in the future or that we will be in a similar position to benefit from them. In addition, during 2000, we reserved a total of $1.6 million for doubtful accounts. This reserve is not included in the calculation of the marketing margins and is reported in Selling and administrative expenses.

Oil and gas exploration and production expenses increased $10.3 million for the year ended December 31, 2000 compared to 1999. These increases are due to increased production taxes and lease operating expenses resulting from our increased drilling and production activities in the Powder River coal bed methane development.

Selling and administrative expenses increased $5.4 million for the year ended December 31, 2000 compared to 1999. These increases are due to higher insurance costs, increased compensation and severance costs, increased accruals for doubtful accounts and compensation recorded for re-priced stock options.

Depreciation, depletion and amortization increased by $6.9 million for the year ended December 31, 2000 compared to 1999 primarily as a result of our increasing operations in the Powder River Basin coal bed methane development and our acquisition of the remaining 50% of the Westana Gathering Company in the first quarter of 2000. These increases more than offset reductions in depreciation from the sales of our Giddings, Katy, MiVida and Black Lake facilities in 1999.

In 2000, we realized a net pre-tax gain of $9.4 million on the sale of our California subsidiary and our Arkoma gathering system. In 1999, we realized a net pre-tax loss of $29.8 million on the sales of our Giddings, Katy, MiVida and Black Lake facilities.

Extraordinary charge for early extinguishment of debt increased by a net after-tax charge of $600,000 for the year ended December 31, 2000 compared to 1999. In 2000, we prepaid $27.0 million of outstanding indebtedness to insurance companies, originally due to be paid in November 2005, with funds available under our Revolving Credit Facility. In connection with this prepayment, we incurred approximately $2.8 million for pre-tax yield maintenance and other charges. This compares to the prepayment in 1999 of $84.0 million of indebtedness to various insurance companies. In connection with the 1999 prepayments, we incurred approximately $1.8 million for pre-tax yield maintenance and other charges.

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation 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. Our critical accounting policies are discussed below. For further details on our accounting policies, and the estimates, assumptions and judgments we use in applying these policies and a discussion of new accounting rules, see Note 2 of the Notes to Consolidated Financial Statements.

Property and Equipment. Our property and equipment is recorded at the lower of cost, including capitalized interest, or estimated realizable value. Interest incurred during the construction period of new projects is capitalized and amortized over the life of the associated assets.

Depreciation on these assets 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 the life of the equipment or the reserves serviced by the equipment. The cost of acquired gas purchase contracts is amortized using the straight-line method or units of production.

Oil and Gas Properties and Equipment. We follow the successful efforts method of accounting for oil and gas exploration and production activities. Acquisition costs, development costs and successful exploration costs are capitalized when incurred. Exploratory dry hole costs, lease rentals and geological and geophysical costs are charged to expense as incurred. Upon surrender of undeveloped properties, the original cost is charged against income. Producing properties and related equipment are depleted and depreciated by the units-of-production method based on estimated proved reserves.

Impairment of Long-Lived Assets. We review our assets at the plant facility and oil and gas producing property levels. 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 reserves supporting the facilities. 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.

Use of Estimates and Significant Risks. 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. The reported amounts of our assets and liabilities, revenues and expenses and associated disclosures with respect to contingent assets and obligations are necessarily affected by these estimates. 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.

We are subject to a number of risks inherent in the industry in which we operate, primarily fluctuating prices, success of our drilling programs and other gas supply. Our financial condition and results of operations will depend significantly upon the prices we receive for gas and NGLs. These prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In addition, we must continually connect new wells to our gathering systems in order to maintain or increase throughput levels to offset natural declines in dedicated volumes. The number of new wells drilled will depend upon, among other factors, prices for gas and oil, the drilling budgets of third-party producers, the energy policy of the federal government and the availability of foreign oil and gas, none of which are within our control.

Recently Issued Accounting Pronouncements. We continually monitor and revise our accounting policies as developments occur. At this time, there are several new accounting pronouncements that have recently been issued, but not yet adopted, which may impact our accounting when these rules become effective in 2002 and 2003.

The construction and operation of our gathering systems, plants and other facilities used for the gathering, processing, treating or transportation 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 five environmental engineers, four safety specialists and three regulatory compliance specialists to monitor environmental and safety compliance at our facilities. Prior to consummating any major acquisition, our environmental engineers perform audits on the facilities to be acquired. In addition, on an ongoing basis, the 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. We believe that the costs for compliance with current environmental laws and regulations have not had and will not have a material effect on our financial position or results of operations.

The Texas Natural Resource Conservation Commission, which has authority to regulate, among other things, stationary air emissions sources, has created a committee to make recommendations to the Commission 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, we are replacing all of our "grand-fathered" compressors in Texas and completed this project in March of 2002. Other "grand-fathered" sources are subject to increasing emissions fees beginning in 2002. We do not believe that such increases will have a material effect on our financial position or results of operations.

We anticipate that it is reasonably likely that the trend in environmental legislation and regulation will continue to be toward stricter standards. We are unaware of future environmental standards that are reasonably likely to be adopted that will have a material effect on our financial position or results of operations, but we cannot rule out that possibility.

In October 2001, Mr. Peter A. Dea was appointed President, Chief Executive Officer and Director effective November 1, 2001. Mr. Dea was most recently the Chairman of the Board and CEO of Barrett Resources Corporation. He had been employed with Barrett since 1994 in various executive positions, including Executive Vice President-Exploration. Prior to joining Barrett, Mr. Dea served as President of Nautilus Oil and Gas Company from 1992 to 1993. By amendment to our bylaws, the board of directors has been expanded from nine members to ten to allow for Mr. Dea's appointment to the board. Mr. Lanny Outlaw, our former Chief Executive Officer and President, retired on October 31, 2001. Mr. Outlaw intends to serve the remainder of his term on the board of directors, which expires in May 2003.

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 or for our other liquidity needs, and we may be required to seek alternative financing sources. Product prices, 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, or general downturns in the national economy, as well as the timely collection of our receivables will all affect future net cash provided by operating activities. Additionally, our future growth will be dependent upon obtaining additions to dedicated plant reserves, developing our existing leaseholds, acquisitions, new project development, marketing, efficient operation of our facilities and our ability to obtain financing at favorable terms.

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, complete our current capital expenditure program including contributions to joint ventures, make any scheduled debt principal and interest payments and to pay common and preferred dividends. 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 a combination of alternatives. While 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. We also believe that cash provided by operating activities and amounts available under the Revolving Credit Facility will be sufficient to meet our debt service and preferred stock dividend requirements for 2002.

During the past several years some of our plants have experienced declines in dedicated reserves. However, overall we have been successful in connecting additional reserves to more than offset the natural declines. Higher gas prices, improved technology, e.g. 3-D seismic and horizontal drilling, and increased pipeline capacity from the Rocky Mountain region have stimulated drilling in many of our operating areas. The overall level of drilling will depend upon, among other factors, the prices for oil and gas, the drilling budgets of third-party producers, energy and environmental policy and regulation by governmental agencies and the availability of foreign oil and gas, none of which are within our control. There is no assurance that we will continue to be successful in replacing the dedicated reserves processed at our facilities.

We have effective shelf registration statements filed with the Securities and Exchange Commission 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.

Our sources and uses of funds for the year ended December 31, 2001 are summarized as follows (dollars in thousands):

Sources of funds:
	Borrowings under Revolving Credit Facility		$	569,630
	Proceeds from the dispositions of property and equipment			38,094
	Net cash provided by operating activities			153,267
	Proceeds from exercise of common stock options			5,191

		Total sources of funds	$	766,182

Uses of funds:
	Payments related to long-term debt (including debt issue costs)		$	(561,760	)
	Capital expenditures (including contributions to joint ventures)			(163,977	)
	Preferred dividends paid			(10,341	)
	Common dividends paid			(6,505	)
	Re-purchase and redemption of $2.28 Cumulative Perpetual Preferred Stock			(20,720	)
	Contribution to equity investments			(5,774	)

		Total uses of funds	$	(769,077	)

Inventories and Storage Capacity. An additional source of liquidity available to us is our inventories of gas and NGLs in storage facilities. We continue to view access to storage capacity as a significant element of our marketing strategy. 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, 2001, we had contracts in place for approximately 17.3 Bcf of storage capacity at various third-party facilities. The fees associated with these contracts during 2002 will average $0.30 per Mcf of annual capacity, and the associated contract periods range from three months to three years, with an average tenure of one and one-half years. Several of these long-term storage contracts require an annual renewal. At December 31, 2001, we held gas in storage and in imbalances of approximately 16.9 Bcf at an average cost of $2.39 per Mcf compared to 10.9 Bcf at an average cost of $3.88 per Mcf at December 31, 2000 under these storage contracts. These positions will be substantially liquidated within the first quarter of 2002. Under mark-to-market accounting, the profit to be earned on these transactions was recorded in the month of origination.

At December 31, 2001, we also held NGLs in storage of 5,665 MGal, consisting primarily of propane and normal butane, at an average cost of $0.33 per gallon compared to 6,229 MGal at an average cost of $0.49 per gallon at December 31, 2000 at various third-party storage facilities. These inventory positions will be substantially liquidated within the first quarter of 2002.

Firm Transportation Capacity. We also continue to view access to firm transportation as a significant element of our marketing 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, 2001, we had contracts for approximately 608 MMcf per day of firm transportation. This amount represents our total contracted amount on each individual pipeline. In many cases it is necessary to utilize sequential pipelines to deliver gas into a specific sales market. For example, to transport 100 Mmcf per day of gas produced in the Powder River to the Mid-Continent utilizes a total of 628 MMcf per day of firm capacity on four separate pipelines. The fixed fees associated with these contracts during 2002 will average approximately $0.13 per Mcf per day, and the associated contract periods range from three months to fifteen years. In addition, some contracts contain provisions requiring us to pay the fees associated with these contracts whether or not the transportation is used. We have also entered into 168 MMcf per day of firm transportation precedent agreements for transportation on pipeline expansions which are not completed. These expansions are anticipated to be completed in 2002. When the expansions are completed, we will enter into firm transportation agreements.

Operating Leases. Primarily to support our growing development in the Powder River coal bed development, we have entered into several operating leases for compression equipment. Payments made on these leases are a component of operating expenses and are reflected on the Consolidated Statement of Operations. As of December 31, 2001, we had leased a total of 85 compression units. These leases have terms ranging from two to ten years with fair market purchase options available at various times during the lease.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 2001 is as follows (dollars in thousands):

Preferred Stock Repurchase and Redemption. In 2001, we purchased in open market transactions a total of 5,100 shares of our $2.28 cumulative preferred stock for a total cost, including broker commissions, of approximately $129,000, or an average of $25.29 per share of preferred stock. During 2000, we purchased in open market transactions a total of 39,190 shares of this preferred stock for a total cost, including broker commissions, of approximately $1.0 million, or an average of $25.52 per share of preferred stock. All of these shares will be retired in 2002. On November 12, 2001, we issued a notice of redemption for approximately 800,000 shares of our $2.28 cumulative preferred stock at its liquidation preference. This totaled $20.6 million including accrued and unpaid dividends. The redemption date was December 10, 2001 and was funded with amounts available under our Revolving Credit Facility. The pro rata capitalized offering costs of $900,000 associated with the redeemed preferred stock were reflected as a special dividend to preferred shareholders in 2001 and accordingly reduced earnings available to common shareholders by approximately $0.03 per common share. These transactions will reduce our preferred dividend requirements in future years.

Capital Investment Program. Capital expenditures related to existing operations totaled approximately $164.4 million during 2001, consisting of the following: (i) approximately $93.0 million related to gathering, processing and pipeline assets, including $7.0 million for maintaining existing facilities; (ii) approximately $69.0 million related to exploration and production activities; and (iii) approximately $2.4 million for miscellaneous items. Overall, capital expenditures in the Powder River Basin coal bed methane development and in Green River Basin in southwest Wyoming operations represented 50% and 17%, respectively, of the total 2001 capital expenditures.

We expect capital expenditures related to existing operations to be approximately $139.8 million during 2002. The 2002 budget represents an approximate 15% decrease from the amount expended in 2001 due to an expectation of lower commodity prices. The 2002 capital budget consists of the following: (i) approximately $69.3 million related to gathering, processing, treating and transportation assets, including $6.4 million for maintaining existing facilities; (ii) approximately $67.6 million related to exploration and production and lease acquisition activities; and (iii) approximately $2.9 million for miscellaneous items. Overall, capital expenditures in the Powder River Basin coal bed methane development and in southwest Wyoming operations represent 54% and 25%, respectively, of the total 2002 budget. Due to drilling and regulatory uncertainties that are beyond our control, we can make no assurance that our capital budget for 2002 will not change. We anticipate that funds for the 2002 capital budget will be provided primarily by internally generated cash flow. This budget may be increased to provide for acquisitions if approved by our board of directors.

Revolving Credit Facility. The Revolving Credit Facility is with a syndicate of banks and provides for a maximum borrowing commitment of $250 million consisting of an $83 million 364-day Revolving Credit Facility, or Tranche A, and a $167 million Revolving Credit Facility, or Tranche B, which matures on April 30, 2004. At December 31, 2001, $95.0 million was outstanding under this facility. The Revolving Credit Facility bears interest at certain spreads over the Eurodollar rate, or the greater of the Federal Funds rate or the agent bank's prime rate. We have the option to determine which rate will be used. We also pay a facility fee on the commitment. The interest rate spreads and facility fee are adjusted based on our debt to capitalization ratio and range from .75% to 2.00%. At December 31, 2001, the interest rate payable on the borrowings under this facility was 3.0%. We are required to maintain a total debt to capitalization ratio of not more than 55%, and a senior debt to capitalization ratio of not more than 40% at December 31, 2001 and of not more than 35% thereafter. The agreement also requires a quarterly test of the ratio of EBITDA (excluding some non-recurring items) for the last four quarters, to interest and dividends on preferred stock for the same period. The ratio must exceed 2.5 to 1.0 through September 30, 2002 and increases to 3.25 to 1.0 at December 31, 2002. This facility also limits our ability to enter into operating and sale leaseback transactions. This facility is guaranteed by, and secured via, a pledge of the stock of all of our material subsidiaries.

Master Shelf Agreement. In December 1991, we entered into a Master Shelf Agreement with The Prudential Insurance Company of America. Amounts outstanding under the Master Shelf Agreement at December 31, 2001 are as indicated in the following table (dollars in thousands):

Under our agreement with Prudential, we are required to maintain a current ratio, as defined therein, of at least .9 to 1.0, 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, a total debt to capitalization ratio of not more than 60% at December 31, 2001 and of not more than 55% thereafter and a senior debt to capitalization ratio of not more than 40% through March 2002 and not more than 35% thereafter. This agreement also requires an EBITDA to interest ratio of not less than 3.50 to 1.0 increasing to a ratio of not less than 3.75 to 1.0 by March 31, 2002 and an EBITDA to interest on senior debt ratio of not less than 5.25 to 1.0 increasing to a ratio of not less than 5.50 to 1.0 by March 31, 2002. EBITDA in these calculations excludes certain non-recurring items. In addition, this agreement contains a calculation limiting dividends. Under this limitation, approximately $70.0 million was available to be paid at December 31, 2001. This facility also limits our ability to enter into operating and sale leaseback transactions. We are currently paying an annual fee of 0.50% on the amounts outstanding on the Master Shelf Agreement. This fee will continue until we receive an implied investment grade rating on our senior secured debt from Moody's Investors Service or Standard & Poor's. Borrowings under the Master Shelf Agreement are guaranteed by, and secured via, a pledge of the stock of all of our material subsidiaries.

In October 2001, we made scheduled principal repayments to Prudential totaling $33.3 million. In October 2002, we will make a required principal repayment of $8.3 million 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 tradeable notes under the same terms and conditions. The Senior Subordinated Notes bear interest at 10% per annum and were priced at 99.225% to yield 10.125%. These notes contain maintenance covenants which include limitations on debt incurrence, restricted payments, liens and sales of assets. Under the calculation limiting restricted payments, including common dividends, approximately $41.1 million was available at December 31, 2001. The Senior Subordinated Notes are unsecured and are guaranteed on a subordinated basis by some of our subsidiaries. We incurred approximately $5.0 million in offering commissions and expenses which have been capitalized and are being amortized over the term of the notes.

Covenant Compliance. We were in compliance with all covenants in our debt agreements at December 31, 2001. Taking into account all the covenants contained in these agreements, we had approximately $122 million of available borrowing capacity at December 31, 2001.

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, net income and earnings per share in relation to those anticipated by our operating budget. The second goal is to manage price risk related to our gas, crude oil and NGL 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 use futures, swaps and options to reduce price risk and 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 the Kansas City Board of Trade and through OTC swaps and options with various counter parties, consisting primarily of financial institutions and other natural gas companies. We conduct our standard credit review of OTC counter parties 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 exposures. OTC exposure is marked-to-market daily for the credit review process. Our OTC credit risk exposure is partially limited by our ability to require a margin deposit from our major counter parties based upon the mark-to-market value of their net exposure. We are subject to margin deposit requirements under these same agreements. In addition, we are subject to similar margin deposit requirements for our NYMEX counter parties related to our net exposures.

The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (i) 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 counter parties 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.

Hedge Positions. For 2002, we have hedged approximately 58% of our projected equity natural gas volumes and approximately 59% of our estimated equity production of crude oil, condensate, and NGLs. 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. Any gains or losses on these cash flow hedges are recognized in the Consolidated Statement of Operations through Product purchases when the hedged transactions occur. Gains or losses from the ineffective portions of changes in the fair value of cash flow hedges are recognized currently in earnings through Non-cash change in the fair value of derivatives and were immaterial in the year ended 2001.

To qualify as cash flow hedges, the hedge instruments must be designated as cash flow hedges and changes in their fair value must correlate 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 both the price of the commodity and 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.

The table below details our hedged position as of December 31, 2001. The prices are NYMEX-equivalent and do not include the transaction cost of the hedges. We do not have any hedges in place beyond 2002.


	1^st Half of 2002	2^nd Half of 2002
Natural gas	80,000 MMbtu per day with an average minimum of price of $3.81 per MMbtu and an average maximum price of $5.87 per MMbtu.
Crude, Condensate, Natural Gasoline and Butanes	75,000 Barrels per month Fixed price of $20.20 per barrel 55,000 Barrels per month Fixed price of $21.15 per barrel	75,000 Barrels per month Fixed price of $20.20 per Barrel with right to participate in price increases above $22.50 per barrel 55,000 Barrels per month Floor at $20.00 per barrel
Propane	75,000 Barrels per month Fixed price of $0.32 per gallon	120,000 Barrels per month Floor at $0.32 per gallon
Ethane	50,000 Barrels per month Fixed price of $0.21 per gallon 20,000 Barrels per month Sold at $0.21 per gallon	50,000 Barrels per month Floor at $0.21 per gallon 20,000 Barrels per month Sold at $0.21 per gallon with right to participate in price increases above $0.25 per gallon

Natural Gas Derivative Market Risk. As of December 31, 2001, we held a notional quantity of approximately 439 Bcf of natural gas futures, swaps and options extending from January 2002 to October 2006 with a weighted average duration of approximately six months. This was comprised of approximately 199 Bcf of long positions and 240 Bcf of short positions in these instruments. As of December 31, 2000, we held a notional quantity of approximately 291 Bcf of natural gas futures, swaps and options extending from January 2001 to December 2002 with a weighted average duration of approximately 4.4 months. This was comprised of approximately 116 Bcf of long positions and 175 Bcf of short positions in these instruments.

We use a Value-at-Risk (VaR) model designed by J.P. Morgan as one measure of market risk for our natural gas portfolio. The VaR calculated by this model represents the maximum change in market value over the holding period at the specified statistical confidence interval. The VaR model is generally based upon J.P. Morgan's RiskMetrics (TM) methodology using historical price data to derive estimates of volatility and correlation for estimating the contribution of tenure and location risk. The VaR model assumes a one day holding period and uses a 95% confidence level.

As of December 31, 2001, the calculated VaR of our entire natural gas portfolio of futures, swaps and options was approximately $537,000. This figure includes the risk related to our entire portfolio of natural gas financial instruments and does not include the related underlying physical transactions.

Crude Oil and NGL Derivative Market Risk. As of December 31, 2001, we held a notional quantity of approximately 131,124 MGal of NGL futures, swaps and options extending from January 2002 to December 2002 with a weighted average duration of approximately six months. This was comprised of approximately 61,824 MGal of long positions and 69,300 MGal of short positions in these instruments. As of December 31, 2000, we held a notional quantity of approximately 156,240 MGal of NGL futures, swaps and options extending from January 2001 to December 2002 with a weighted average duration of approximately six months. This was comprised of approximately 156,240 MGal of long positions in these instruments.

As of December 31, 2001, we did not hold any NGL futures, swaps or options for settlement beyond 2002. As of December 31, 2001, the estimated fair value of the aforementioned crude oil and NGL options held by us was approximately $229,000.

Summary of Derivative Positions. A summary of the change in our derivative position from December 31, 2000 to December 31, 2001 is as follows (dollars in thousands):

Fair value of contracts outstanding at December 31, 2000		—
Adoption of SFAS No. 133 on January 1, 2001	$	(35,476	)
Increase in value due to change in price		48,814
Increase in value due to new contracts entered into during the year		71,858
Gains realized during the year from existing and new contracts		(35,785	)
Changes in fair value attributable to changes in valuation techniques		—

Fair value of contracts outstanding at December 31, 2001	$	49,411

A summary of our outstanding derivative positions at December 31, 2001 is as follows (dollars in thousands):

	Fair Value of Contracts at December 31, 2001
Source of Fair Value	Total Fair Value		Maturing In 2002		Maturing In 2003-2004	Maturing In 2005-2006		Maturing Thereafter
Exchange published prices	$	11,050		$	11,315	$	(265	)		—		—
Other actively quoted prices(1)		9,875			8,392		1,581		$	(98	)	—
Other valuation methods(2)		28,486			28,486		—			—		—

Total fair value	$	49,411		$	48,193	$	1,316		$	(98	)	—

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, 2001, the net notional value of such contracts was approximately $12.7 million in Canadian dollars, which approximates its fair market value.

Accounting for Derivative Instruments and Hedging Activities. In June 1998, the Financial Accounting Standards Board, the FASB, issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), effective for fiscal years beginning after June 15, 2000. Under SFAS No. 133, which was subsequently amended by SFAS No. 138, we are required to recognize the change in the market value of all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income depending upon the nature of the underlying transaction. Also on January 1, 2001, we adopted mark-to-market accounting for the remainder of our marketing activities which, for various reasons, are not designated or qualified as hedges under SFAS 133. Upon the adoption of SFAS No. 133 and mark-to-market accounting on January 1, 2001, the impact was a decrease in a component of stockholders' equity through Accumulated other comprehensive income of $22.5 million, an increase to Current assets of $52.6 million, an increase to Current liabilities of $86.9 million, an increase to Other long-term liabilities of $1.1 million and a decrease in Deferred income taxes payable of $12.9 million.

Of the $22.5 million decrease to Accumulated other comprehensive income resulting from the January 1, 2001 adoption of SFAS 133, $22.0 million was reversed during the year ended December 31, 2001 with gains and losses from the underlying transactions recognized through operating income. The remaining $500,000 of this transition entry is currently anticipated to be recognized through operating income during 2002.

The non-cash impact to our results of operations in the year ended December 31, 2001, from the adoption of mark-to-market accounting for our marketing activities, resulted in additional pre-tax income of $19.9 million.

Western Gas Resources, Inc.'s Consolidated Financial Statements as of December 31, 2001 and 2000 and for each of the three years in the period ended December 31, 2001:


Report of Management
Report of Independent Accountants
Consolidated Balance Sheet
Consolidated Statement of Cash Flows
Consolidated Statement of Operations
Consolidated Statement of Changes in Stockholders' Equity
Notes to Consolidated Financial Statements

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.

The Company's financial statements are audited by PricewaterhouseCoopers LLP, independent accountants. Their report states that they have conducted their audit in accordance with generally accepted auditing standards. These standards include an evaluation of the system of internal accounting controls for the purpose of establishing the scope of audit testing necessary to allow them to render an independent professional opinion on the fairness of the Company's financial statements.

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 accountants to review how each is carrying out its responsibilities and to discuss matters concerning auditing, internal accounting control and financial reporting. The independent accountants and the Company's internal audit department have free access to meet with the Audit Committee without Management present.

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, 2001 and 2000, and the results of their cash flows and their operations for each of the three years in the period ended December 31, 2001, 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.

WESTERN GAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(000s, except share data)

The accompanying notes are an integral part of the consolidated financial statements.

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF OPERATIONS

(000s, except share and per share amounts)

The accompanying notes are an integral part of the consolidated financial statements.

Western Gas Resources, Inc. (the "Company") explores for, develops and produces, gathers, processes and treats, transports and markets natural gas and natural gas liquids ('NGLs'). In its upstream operations, the Company explores for, develops and produces natural gas reserves primarily in the Rocky Mountain region. In its midstream operations the Company designs, constructs, owns and operates natural gas gathering, processing and treating facilities and owns and operates regulated transportation facilities and offers marketing services in order to provide its customers with a broad range of services from the wellhead to the sales delivery point. The Company's midstream operations are conducted in major gas-producing basins in the Rocky Mountain, Mid-Continent, Gulf Coast and Southwestern regions of the United States.

Western Gas Resources, Inc. was formed in October 1989 to acquire a majority interest in Western Gas Processors, Ltd. (the "Partnership") and to assume the duties of WGP Company, the general partner of the Partnership. The reorganization was accomplished in December 1989 through an exchange for common stock of partnership units held by the former general partners of WGP Company and an initial public offering of Western Gas Resources, Inc. Common Stock. On May 1, 1991, a further restructuring ("Restructuring") of the Partnership and Western Gas Resources, Inc. (together with its predecessor, WGP Company, collectively, the "Company") was approved by a vote of the security holders. The combinations were reorganizations of entities under common control and were accounted for at historical cost in a manner similar to poolings of interests.

The Company has completed three public offerings of Common Stock. In December 1989, the Company issued 3,527,500 shares of Common Stock at a public offering price of $11.50. In November 1991, the Company issued 4,115,000 shares of Common Stock at a public offering price of $18.375 per share. In November 1996, the Company issued 6,325,000 shares of Common Stock at a public offering price of $16.25 per share.

The Company has also completed two public offerings of preferred stock. In November 1992, the Company issued 1,400,000 shares of $2.28 Cumulative Preferred Stock with a liquidation preference of $25 per share, at a public offering price of $25 per share, redeemable at the Company's option on or after November 15, 1997. In order to reduce its fixed charges, the Company has implemented a re-purchase and redemption program for its $2.28 Cumulative Preferred Stock. In 2000, the Company re-purchased 39,190 of the $2.28 Cumulative Preferred Stock for a total consideration of approximately $1.0 million. In 2001, The Company purchased in open market transactions an additional 5,100 shares of this preferred stock for a total cost, including broker commissions, of approximately $129,000, or an average of $25.29 per share of preferred stock. On November 12, 2001, the Company issued a notice of redemption of its $2.28 Cumulative Preferred Stock at the liquidation preference totaling $20.6 million including accrued and unpaid dividends. The redemption date was December 10, 2001 and was funded with amounts available under the Revolving Credit Facility. The pro rata capitalized offering costs of $900,000 associated with the redeemed preferred stock were reflected as a special dividend to preferred shareholders in the fourth quarter of 2001.

In February 1994, the Company issued 2,760,000 shares of $2.625 Cumulative Convertible Preferred Stock with a liquidation preference of $50 per share, at a public offering price of $50 per share, redeemable at the Company's option on or after February 16, 1997 and convertible at the option of the holder into Common Stock at a conversion price of $39.75.

In the first quarter of 2001, the Company adopted a Stockholder Rights Plan under which rights were distributed as a dividend at the rate of one right for each share of its common stock held by stockholders of record as of the close of business on April 9, 2001. Each right initially will entitle stockholders to buy one unit consisting of 1/100^th of a share of a new series of preferred stock for $180 per unit. The right generally will be exercisable only if a person or group acquires beneficial ownership of 15% or more of the Company's then outstanding common stock or commences a tender or exchange offer upon consummation of which a person or group would beneficially own 15% or more of its then outstanding common stock. The rights will expire on March 22, 2011.

Powder River Basin Coal Bed Methane. The Company continues to expand its Powder River Basin coal bed methane natural gas gathering system and develop its own coal seam gas reserves in Wyoming. During the years ended December 31, 2001, 2000 and 1999, the Company expended approximately $82.1 million, $59.1 million and $51.4 million, respectively, on this project.

In December 1998, the Company joined with other industry participants to form the Fort Union Gas Gathering, L.L.C. ("Fort Union"), to construct a gathering pipeline and treater in the Powder River Basin in northeast Wyoming. The Company owns an approximate 13% interest in Fort Union and is the construction manager and field operator. The gathering pipeline went into service in the third quarter of 1999. Construction of the gathering header and treating system was project financed by Fort Union and required a cash investment by the Company of approximately $900,000. In conjunction with the project financing, the Company entered into a ten year agreement for firm gathering services on 60 MMcf per day of capacity for $0.14 per Mcf on Fort Union beginning in December 1999. In the fourth quarter of 2000, the Company and other participants in the Fort Union Gas Gathering, L.L.C. approved an expansion of the system. Construction of the expansion was completed in the third quarter of 2001. The expansion costs totaled approximately $22.0 million and were project financed by Fort Union. In the fourth quarter of 2001, the Company made an additional equity contribution to Fort Union of approximately $500,000. Also in connection with the expansion, the Company increased its commitment for firm gathering services to a total of 83 MMcf per day of capacity at $0.14 per Mcf. All participants in Fort Union have guaranteed the project financing on a proportional basis resulting in the Company's guarantee of $7.3 million of the debt of Fort Union. This guarantee is not reflected on the Consolidated Balance Sheet.

Southwest Wyoming. The Company's assets in southwest Wyoming are comprised of the Granger and Lincoln Road facilities (collectively the "Granger Complex"), the Red Desert facility and production from the Jonah Field and Pinedale Anticline areas. During the years ended December 31, 2001, 2000 and 1999, the Company expended approximately $27.2 million, $8.0 million and $12.4 million, respectively, in this area.

In September 2001, the Company signed an agreement with Questar Gas Management Company ("Questar") for the sale of a 50% interest in a segment of the Bird Canyon gathering system along with associated field compression for $5.2 million. This sale closed in October 2001. Also in October 2001, both Questar and the Company contributed their respective interests in the Bird Canyon system along with additional field compression and gathering dedications for gas produced along the Pinedale Anticline to a newly formed joint venture named Rendezvous Gas Services, L.L.C. Each company owns a 50% interest in Rendezvous and the Company serves as field operator of its systems. In the fourth quarter of 2001, Rendezvous began construction of additional gas gathering and compression facilities. This expansion will deliver gas for blending or processing at either the Company's Granger Complex or at a Questar processing facility. The total estimated construction cost of the new gathering pipeline and compression facilities is $44.0 million, of which the Company's share will be $22.0 million.

Pinnacle Gas Treating, Inc. During 1996 and 1997, the Company, through its wholly-owned subsidiary Pinnacle Gas Treating, Inc. ("Pinnacle"), constructed the Bethel treating facility for a total cost of approximately $102.8 million. In the fourth quarter of 1998, because of uncertainties related to the pace and success of third-party drilling programs, declines in volumes produced at certain wells and other conditions outside of the Company's control, the Company determined that a pre-tax, non-cash impairment charge of $77.8 million was required.

In December 2000, the Company signed an agreement with Anadarko Petroleum Corporation for the sale of the stock of Pinnacle for approximately $38.0 million. The sale closed in January 2001 and resulted in an approximate pre-tax gain for financial reporting purposes of $12.1 million in the first quarter of 2001. The assets of Pinnacle are reflected on the Consolidated Balance Sheet at December 31, 2000 as Assets held for sale. The proceeds from this transaction were used to reduce amounts outstanding under the Company's Revolving Credit Facility.

Arkoma. In August 2000, the Company sold its Arkoma Gathering System in Oklahoma for gross proceeds of $10.5 million. This sale resulted in an approximate pre-tax gain of $3.9 million.

Westana Gathering Company. In February 2000, the Company acquired the remaining 50% interest in the Westana Gathering Company ("Westana") for a net purchase price of $9.8 million. The results from our ownership through February 2000 of a 50% equity interest in Westana are reflected in revenues in Other on the Consolidated Statement of Operations. Beginning in March 2000, the results of these operations are fully consolidated and are included in Revenues and Costs and Expenses.

Western Gas Resources—California, Inc. In January 2000, the Company sold all of the outstanding stock of its wholly-owned subsidiary Western Gas Resources—California, Inc. ("WGR California") for $14.9 million. The only asset of this subsidiary was a 162 mile pipeline in the Sacramento Basin of California. The pipeline was acquired through the exercise of an option by the Company in a transaction which closed simultaneously with the sale of WGR California. The Company recognized a pre-tax gain on the sale of approximately $5.4 million in the first quarter of 2000.

Black Lake. In December 1999, the Company entered into an agreement for the sale of its Black Lake facility and related reserves for gross proceeds of $7.8 million. This sale closed in January 2000. This transaction resulted in an approximate pre-tax loss of $7.3 million, which was recognized in the fourth quarter of 1999.

MiVida. In June 1999, the Company sold its MiVida treating facility for gross proceeds of $12.0 million, which resulted in an approximate pre-tax gain of $1.2 million.

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

Katy. In April 1999, the Company sold all of the outstanding common stock of its wholly-owned subsidiary, Western Gas Resources Storage, Inc., for gross proceeds of $100.0 million, which resulted in an approximate pre-tax loss of $17.7 million. The only asset of this subsidiary was the Katy facility. The Company also sold approximately 5.1 Bcf of stored gas in the Katy facility to the same purchaser for total sales proceeds of approximately $11.7 million, which approximated the cost of the inventory. To meet the needs of its marketing operations, the Company will continue to contract for storage capacity. Accordingly, the Company entered into a long-term agreement with the purchaser for 3 Bcf of storage capacity at market rates. This contract expires in March 2002.

The significant accounting policies followed by the Company and its wholly-owned subsidiaries are presented here to assist the reader in evaluating the financial information contained herein. The Company's accounting policies are in accordance with generally accepted accounting principles.

Principles of Consolidation. The consolidated financial statements include the accounts of the Company and the Company's wholly-owned subsidiaries. All material inter-company transactions have been eliminated in consolidation. The Company's interest in certain investments is accounted for by the equity method.

Inventories. The cost of gas and NGL inventories are determined by the weighted average cost method on a location-by-location basis. Residue and NGL inventory covered by hedging contracts is accounted for on a specific identification basis. Product inventory include $48.3 million and $42.4 million of gas and $2.5 million and $2.5 million of NGLs at December 31, 2001 and 2000, respectively.

Property and Equipment. Property and equipment is recorded at the lower of cost, including capitalized interest, or estimated realizable value. Interest incurred during the construction period of new projects is capitalized and amortized over the life of the associated assets. Repair and maintenance of property and equipment is expensed as incurred.

Depreciation 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 the life of the equipment or the reserves serviced by the equipment. The cost of acquired gas purchase contracts is amortized using the straight-line method or units of production.

Oil and Gas Properties and Equipment. The Company follows the successful efforts method of accounting for oil and gas exploration and production activities. Acquisition costs, development costs and successful exploration costs are capitalized. Exploratory dry hole costs, lease rentals and geological and geophysical costs are charged to expense as incurred. Upon surrender of undeveloped properties, the original cost is charged against income. Producing properties and related equipment are depleted and depreciated by the units-of-production method based on estimated proved reserves.

Income Taxes. Deferred income taxes reflect the impact of temporary differences between amounts of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws. These temporary differences are determined and accounted for in accordance with SFAS No. 109, "Accounting for Income Taxes."

Foreign Currency Adjustments. The Company has a subsidiary in Canada. The assets and liabilities associated with this subsidiary are translated into U.S. dollars at the exchange rate as of the balance sheet date and revenues and expenses at the weighted-average of exchange rates in effect during each reporting period. SFAS No. 52, "Foreign Currency Translation," requires that cumulative translation adjustments be reported as a separate component of stockholders' equity. The translation adjustments for the years ended December 31, 2001, 2000 and 1999 were $(440,000), $(300,000) and $(1.7) million, respectively, net of tax.

Revenue Recognition. Revenue for sales or services is recognized at the time the gas or NGLs are delivered or at the time the service is performed. Additionally, for our marketing activities, we adopted mark-to-market accounting on January 1, 2001. Under mark-to-market accounting, the margin to be realized over the term of the transaction is recorded in the month of origination.

Accounting for Derivative Instruments and Hedging Activities. Prior to January 1, 2001 and the implementation of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133"), gains and losses on hedges of product inventory were included in the carrying amount of the inventory and were ultimately recognized in gas and NGL sales when the related inventory was sold. Gains and losses related to qualifying hedges, as defined by SFAS No. 80, "Accounting for Futures Contracts," of firm commitments or anticipated transactions (including hedges of equity production) were recognized in gas and NGL sales, as reported on the Consolidated Statement of Operations, when the hedged physical transaction occurred. For purposes of the Consolidated Statement of Cash Flows, all hedging gains and losses were classified in net cash provided by operating activities. To the extent the Company engaged in speculative transactions, they were marked to market at the end of each accounting period and any gain or loss was recognized in income for that period. Such amounts were negligible in 2000 and 1999.

In June 1998, the Financial Accounting Standards Board, the FASB, issued SFAS No. 133 effective for fiscal years beginning after June 15, 2000. Under SFAS No. 133, which was subsequently amended by SFAS No. 138, the Company is required to recognize the change in the market value of all derivatives, including storage contracts and firm transportation to the extent utilized, as either assets or liabilities in the statement of financial position and measure those instruments at fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income depending upon the nature of the underlying transaction. Upon adoption of SFAS No. 133 and mark-to-market accounting on January 1, 2001, the impact was a decrease in a component of stockholders' equity through Accumulated other comprehensive income of $22.5 million, an increase to Current assets of $52.6 million, an increase to Current liabilities of $86.9 million, an increase in Other long-term liabilities of $1.1 million and a decrease in Deferred income taxes payable of $12.9 million.

Of the $22.5 million decrease to Accumulated other comprehensive income resulting from the January 1, 2001 adoption of SFAS No. 133, $22.0 million was reversed during the year ended December 31, 2001 with gains and losses from the underlying transactions recognized through operating income. The remaining $500,000 of this transition entry is currently anticipated to be recognized through operating income during 2002. The non-cash impact to the Company's results of operations in the year ended December 31, 2001 resulting from the adoption of mark-to-market accounting for its marketing activities resulted in additional pre-tax income of $19.9 million.

Comprehensive Income. Accumulated other comprehensive income is reported as a separate component of stockholders' equity. Accumulated other comprehensive income includes cumulative translation adjustments for foreign currency transactions and the change in fair market value of cash flow hedges. The Company's cumulative translation adjustments totaled $(440,000), $(300,000) and $(1.7) million for the years ended December 31, 2001, 2000 and 1999, respectively, net of tax. The Company's accumulated derivative gains at December 31, 2001 total $17.1 million and are expected to be reclassified into earnings during 2002. These items are separately reported on the Consolidated Statement of Changes in Stockholders' Equity.

Impairment of Long-Lived Assets. SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" ("SFAS No. 121") requires that long-lived assets be reviewed whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company reviews its assets at the plant facility and oil and gas producing property levels. In order to determine whether an impairment exists, the Company compares its 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 reserves supporting the facilities. 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. The Company has written down property and equipment of $1.2 million in accordance with SFAS No. 121 during the year ended December 31, 1999. There were no write-downs in 2001 or 2000. Effective for the Company's quarter ending March 31, 2002, SFAS No. 121 will be superceded by SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." The Company does not believe SFAS No. 144 will have a significant impact on its results of operations.

Earnings (Loss) Per Share of Common Stock. The Company follows SFAS No. 128, "Earnings per Share" ("SFAS No. 128") which requires that earnings per share and earnings per share—assuming dilution be calculated and presented on the Consolidated Statement of Operations. In accordance with SFAS No. 128, earnings (loss) per share of common stock is computed by dividing income (loss) attributable to common stock by the weighted average shares of common stock outstanding. In addition, earnings (loss) per share of common stock - assuming dilution is computed by dividing income (loss) attributable to common stock by the weighted average shares of common stock outstanding as adjusted for potential common shares. Income (loss) attributable to common stock is income (loss) less preferred stock dividends. The Company declared preferred stock dividends of $11.2 million, $10.4 million and $10.4 million for each of the years ended December 31, 2001, 2000 and 1999, respectively. SFAS No. 128 dictates that the computation of earnings per share shall not assume conversion, exercise or contingent issuance of securities that would have an antidilutive effect on earnings (loss) per share. Common stock options, which are potential common shares, were anti-dilutive in 1999, and therefore were excluded from the computation. Common stock options, which are potential common shares, increased the number of common shares used in the computation by 593,886 in 2000. The computations for the years ended December 31, 2000 and 1999 were not adjusted to reflect the conversion of the Company's $2.625 Cumulative Convertible Preferred Stock outstanding. In those years, the shares are antidilutive as the incremental shares result in an increase in earnings per share, or a reduction of loss per share, after giving affect to the preferred dividend requirements. The computation for the year ended December 31, 2001 reflects the conversion of the Company's $2.625 Cumulative Convertible Preferred Stock and dilutive stock options totaling 4,442,556.

Concentration of Credit Risk. Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of trade accounts receivable and over-the-counter ("OTC") swaps and options. The risk is limited due to the large number of entities comprising the Company's customer base and their dispersion across industries and geographic locations.

The Company continually monitors and reviews the credit exposure to its marketing counter parties. This review has resulted in a temporary reduction in sales volumes with various counter parties in order to maintain acceptable credit exposures. During 2001 and 2000, the Company reserved approximately $2.7 million and $1.6 million for doubtful accounts. During the years ended December 31, 2001 and 2000, the Company sold gas to a variety of customers including end-users, pipelines, LDCs and others. One customer accounted for approximately 5% of the Company's consolidated revenues from the sale of gas, or 4% of total consolidated revenue, for the year ended December 31, 2001. This customer is a wholly-owned subsidiary of a major integrated oil company.

On December 2, 2001, Enron Corp. and many of its affiliates and subsidiaries filed a petition for bankruptcy protection under Chapter 11 of the Bankruptcy code in the Southern District of New York. At the time of Enron's filing, the Company's exposure to them totaled approximately $2.7 million. This amount includes the net exposure from physical gas transactions of $100,000, which is comprised of physical gas sales of $8.4 million and physical gas purchases of $8.3 million. The Company has in place a netting agreement with Enron for the purchase and sale of physical gas. Although similar netting agreements have been upheld by bankruptcy courts in the past, the Company can provide no assurance that its agreement will not be challenged or the outcome of any challenge. The remaining $2.6 million of its net exposure is under a Master Swap Agreement related to derivative transactions, including approximately $180,000 which was related to discontinued hedges and will be relieved from Accumulated other comprehensive earnings as the hedged transactions occur. As a result, the Company incurred an additional charge to income of $2.7 million in 2001.

During the year ended December 31, 2000, the Company sold NGLs to a variety of customers. These customers are end-users, fractionators, chemical companies and other customers. Three customers accounted for approximately 14%, 13% and 10%, respectively, of the Company's consolidated revenues from the sale of NGLs, or a combined total of 5% of total consolidated revenue, for the year ended December 31, 2001. These customers are all large integrated energy companies.

Cash and Cash Equivalents. Cash and cash equivalents includes all cash balances and highly liquid investments with an original maturity of three months or less.

Supplementary Cash Flow Information. Interest paid was $30.2 million, $36.5 million and $34.1 million, respectively, for the years ended December 31, 2001, 2000 and 1999. Capitalized interest associated with construction of new projects was $4.7 million, $3.4 million and $2.0 million, respectively, for the years ended December 31, 2001, 2000 and 1999. Income taxes paid or (refunded) were $18.7 million, $400,000 and $(2.9) million, respectively, for the years ended December 31, 2001, 2000 and 1999.

Stock Compensation. As permitted under SFAS No. 123, "Accounting for Stock-Based Compensation" ("SFAS No. 123"), the Company has elected to continue to measure compensation costs for stock-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." The Company has complied with the pro forma disclosure requirements of SFAS No. 123 as required under the pronouncement. The Company realizes an income tax benefit from the exercise of non-qualified stock options related to the difference between the market price at the date of exercise and the option price. This difference is credited to additional paid-in capital.

In March 2000, the FASB issued Interpretation No. 44, an interpretation of APB Opinion No. 25, "Accounting for Certain Transactions Involving Stock Compensation," regarding the accounting treatment of re-priced stock options. This interpretation became effective July 1, 2000. Under this interpretation, the Company is required to record compensation expense (if not previously accrued) equal to the number of unexercised re-priced options multiplied by the amount by which its stock price at the end of any quarter exceeds $21 per share. The Company had options covering 118,028 and 148,133 common shares outstanding at December 31, 2001 and 2000, respectively, which were treated as re-priced options. Based on the Company's stock price at December 31, 2001 and 2000 of $32.32 and $33.69 per share, respectively, additional compensation income of $(170,000) and expense of $1.9 million was recorded in the years ended December 31, 2001 and 2000.

Use of Estimates and Significant Risks. The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management 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. Therefore, the reported amounts of our assets and liabilities, revenues and expenses and associated disclosures with respect to contingent assets and obligations are necessarily affected by these estimates. These estimates are evaluated on an ongoing basis, utilizing historical experience, consultation with experts and other methods considered reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the estimates used. Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

The Company is subject to a number of risks inherent in the industry in which it operates, primarily fluctuating prices, success of its drilling programs and other gas supply. The Company's financial condition and results of operations will depend significantly upon the prices received for gas and NGLs. These prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond the control of the Company. In addition, the Company must continually connect new wells to its gathering systems in order to maintain or increase throughput levels to offset natural declines in dedicated volumes. The number of new wells drilled will depend upon, among other factors, prices for gas and oil, the drilling budgets of third-party producers, the energy policy of the federal government and the availability of foreign oil and gas, none of which are within the Company's control.

Recently Issued Accounting Pronouncements. In June 2001, the Financial Accounting Standards Board, the FASB, issued SFAS No. 141, "Business Combinations", SFAS No. 142, "Goodwill and Other Intangible Assets" and SFAS No. 143 "Accounting for Asset Retirement Obligations." As it applies to the Company, SFAS No. 141 was effective for the quarter ended September 30, 2001. SFAS No. 141 changed the method in which companies account for business combinations. SFAS No. 141 did not have an immediate impact on the Company as the Company had not entered into any business combinations since its effective date. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001. SFAS No. 142 changes the method in which goodwill and other intangible assets are recorded and amortized. SFAS No. 142 did not have an immediate impact on the Company as it does not currently have any goodwill recorded in its financial statements. SFAS No. 143 is effective for fiscal years beginning after June 30, 2002. SFAS No. 143 establishes accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement cost. The Company has not yet determined the impact that the adoption of SFAS No. 143 will have on its earnings or financial position.

Reclassifications. Certain prior years' amounts in the consolidated financial statements and related notes have been reclassified to conform to the presentation used in 2001.

From time to time, the Company enters into joint ventures and partnerships in order to reduce risk, create strategic alliances and to establish itself in oil and gas producing basins in the United States. At December 31, 2001, the Company held a 13% interest in Fort Union and a 50% interest in Rendezvous. In prior years, the Company had a 50% ownership interest in Westana and a 49% ownership interest in Sandia Energy Resources Joint Venture. Westana was dissolved in February 2000 and Sandia was dissolved in 1999. All transactions entered into by the Company with its related parties were consummated in the ordinary course of business and on terms that would be comparable to those obtained from third parties.

The Company acts as field operator of both Fort Union and Rendezvous and charges a monthly overhead fee to cover such services. In 2001 and 2000, the Company received overhead fees from Fort Union totaling $483,000 and $72,000, respectively. In 2001, the Company also received overhead fees totaling $25,000 from Rendezvous.

The Company acted as operator for Westana and charged a monthly overhead fee to cover such services. The Company provided substantially all of the natural gas that Sandia marketed and also provided it with various administrative services. In addition, the Company purchased gas from Sandia.

The Company has entered into agreements committing the Company to loan to certain key employees an amount sufficient to exercise their options as each portion of their options vests under the Key Employees' Incentive Stock Option Plan. The loan and accrued interest will be forgiven if the employee is continually employed by the Company and upon a resolution of the board of directors. As of December 31, 2001 and 2000, loans related to 75,000 shares of Common Stock totaling $803,000, respectively, were outstanding to certain current and past employees under these programs. Certain of the loans are secured by a portion of the Common Stock issued upon exercise of the options and are accounted for as a reduction of stockholders' equity. There were no loans forgiven in 2001 or 2000.

In October 2001, Mr. Lanny Outlaw, our former Chief Executive Officer and President, retired. The Company has entered into a consulting agreement with Mr. Outlaw providing for payments of $167,000 in May 2002 and $175,000 in May 2003.

Risk Management Activities. The Company's commodity price risk management program has two primary objectives. The first goal is to preserve and enhance the value of the Company's equity volumes of gas and NGLs with regard to the impact of commodity price movements on cash flow, net income and earnings per share in relation to those anticipated by the Company's operating budget. The second goal is to manage price risk related to the Company's physical gas, crude oil and NGL 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.

The Company utilizes 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 ("OTC") market to accomplish these objectives. These instruments allow the Company to preserve value and protect margins because gains or losses in the physical market are offset by corresponding losses or gains in the value of the financial instruments.

The Company uses futures, swaps and options to reduce price risk and 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.

The Company enters into futures transactions on the New York Mercantile Exchange ("NYMEX") and the Kansas City Board of Trade and through OTC swaps and options with various counterparties, consisting primarily of financial institutions and other natural gas companies. The Company conducts its standard credit review of OTC counterparties and has agreements with such parties that contain collateral requirements. The Company generally uses standardized swap agreements that allow for offset of positive and negative exposures. OTC exposure is marked to market daily for the credit review process. The Company's OTC credit risk exposure is partially limited by its ability to require a margin deposit from its major counterparties based upon the mark-to-market value of their net exposure. The Company is subject to margin deposit requirements under these same agreements. In addition, the Company is subject to similar margin deposit requirements for its NYMEX counterparties related to its net exposures.

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

For 2002, the Company has hedged approximately 58% of its projected equity natural gas volumes and approximately 59% of its estimated equity production of crude oil, condensate, and NGLs. 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. Any gains or losses on these cash flow hedges are recognized in the Consolidated Statement of Operations through Product purchases when the transaction underlying the hedge occurs. Gains or losses from the ineffective portions of changes in the fair value of cash flow hedges are recognized currently in earnings through Non-cash change in the fair value of derivatives and were immaterial in the year ended 2001.

To qualify as cash flow hedges, the hedge instruments must be designated as cash flow hedges and changes in their fair value must correlate with changes in the price of the forecasted transaction being hedged so that the Company's exposure to the risk of commodity price changes is reduced. To meet this requirement, the Company hedges both the price of the commodity and 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.

The table below details the hedged position of the Company as of December 31, 2001. The prices are NYMEX-equivalent and do not include the transaction cost of the hedges. The Company does not have any hedges in place beyond 2002.

	1^st Half of 2002	2^nd Half of 2002
Natural gas	80,000 MMbtu per day with an average minimum and maximum price of $3.81 and $5.87 per MMbtu, respectively.
Crude, Condensate, Natural Gasoline and Butanes	75,000 Barrels per month Fixed price of $20.20 per barrel	75,000 Barrels per month Fixed price of $20.20 per barrel with right to participate in price increases above $22.50 per barrel
	55,000 Barrels per month Fixed price of $21.15 per barrel	55,000 Barrels per month Floor at $20.00 per barrel
Propane	75,000 Barrels per month Fixed price of $0.32 per gallon	120,000 Barrels per month Floor at $0.32 per gallon
Ethane	50,000 Barrels per month Fixed price of $0.21 per gallon	50,000 Barrels per month Floor at $0.21 per gallon
	20,000 Barrels per month Sold at $0.21 per gallon	20,000 Barrels per month Sold at $0.21 per gallon with right to participate in price increases above $0.25 per gallon

Natural Gas Derivative Market Risk. As of December 31, 2001, the Company held a notional quantity of approximately 439 Bcf of natural gas futures, swaps and options extending from January 2002 to October 2006 with a weighted average duration of approximately six months. This was comprised of approximately 199 Bcf of long positions and 240 Bcf of short positions in these instruments. As of December 31, 2000, the Company held a notional quantity of approximately 291Bcf of natural gas futures, swaps and options extending from January 2001 to December 2002 with a weighted average duration of approximately 4.4 months. This was comprised of approximately 116 Bcf of long positions and 175 Bcf of short positions in these instruments.

Crude Oil and NGL Derivative Market Risk. As of December 31, 2001, the Company held a notional quantity of approximately 131,124 MGal of NGL futures, swaps and options extending from January 2002 to December 2002 with a weighted average duration of approximately six months. This was comprised of approximately 61,824 MGal of long positions and 69,300 MGal of short positions in these instruments. As of December 31, 2000, the Company held a notional quantity of approximately 156,240 MGal of NGL futures, swaps and options extending from January 2001 to December 2002 with a weighted average duration of approximately 6.5 months. This was comprised of approximately 156,240 MGal of long positions in these instruments.

As of December 31, 2001, the Company did not hold any NGL futures, swaps or options for settlement beyond 2002. As of December 31, 2001, the estimated fair value of the aforementioned crude oil and NGL options held by the Company was approximately $229,000.

Foreign Currency Derivative Market Risk. As a normal part of our business, the Company enters into physical gas transactions which are payable in Canadian dollars. The Company enters into forward purchases and sales of Canadian dollars from time to time to fix the cost of its 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, 2001, the net notional value of such contracts was approximately $12.7 million in Canadian dollars, which approximates its fair market value. As of December 31, 2000, the net notional value of such contracts was approximately $17.9 million in Canadian dollars, which approximated its fair market value.

The following summarizes the Company's consolidated debt at the dates indicated (000s):

		December 31,
		2001		2000
Master Shelf, Senior and Subordinated Notes		$	271,666	$	305,000
Variable Rate Revolving Credit Facility			95,001		53,700

	Total long-term debt	$	366,667	$	358,700

Revolving Credit Facility. The Revolving Credit Facility is with a syndicate of banks and provides for a maximum borrowing commitment of $250 million consisting of an $83 million 364-day Revolving Credit Facility, or Tranche A, and a $167 million Revolving Credit Facility, or Tranche B, which matures on April 30, 2004. At December 31, 2001, $95.0 million was outstanding under this facility. The Revolving Credit Facility bears interest at certain spreads over the Eurodollar rate, or the greater of the Federal Funds rate or the agent bank's prime rate. The Company has the option to determine which rate will be used. The Company also pays a facility fee on the commitment. The interest rate spreads and facility fee are adjusted based on its debt to capitalization ratio and range from .75% to 2.00%. At December 31, 2001, the interest rate payable on borrowings under this facility was 3.0%. The Company is required to maintain a total debt to capitalization ratio of not more than 55%, and a senior debt to capitalization ratio of not more than 40% at December 31, 2001 and of not more than 35% thereafter. The agreement also requires a quarterly test of the ratio of EBITDA (excluding some non-recurring items) for the last four quarters, to interest and dividends on preferred stock for the same period. The ratio must exceed 2.5 to 1.0 through September 30, 2002 and increases to 3.25 to 1.0 at December 31, 2002. This facility also limits the Company's ability to enter into operating and sale leaseback transactions. This facility is guaranteed and secured via a pledge of the stock of all of its material subsidiaries.

Master Shelf Agreement. In December 1991, the Company entered into a Master Shelf Agreement with The Prudential Insurance Company of America. Amounts outstanding under the Master Shelf Agreement at December 31, 2001 are as indicated in the following table (000s):

Under the Company's agreement with Prudential, it is required to maintain a current ratio, as defined therein, of at least .9 to 1.0, 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, a total debt to capitalization ratio of not more than 60% at December 31, 2001 and of not more than 55% thereafter and a senior debt to capitalization ratio of not more than 40% through March 2002 and not more than 35% thereafter. This agreement also requires an EBITDA to interest ratio of not less than 3.50 to 1.0 increasing to a ratio of not less than 3.75 to 1.0 by March 31, 2002 and an EBITDA to interest on senior debt ratio of not less than 5.25 to 1.0 increasing to a ratio of not less than 5.50 to 1.0 by March 31, 2002. EBITDA in these calculations excludes certain non-recurring items. In addition, this agreement contains a calculation limiting dividends under which approximately $70.0 million was available at December 31, 2001. This facility also limits the Company's ability to enter into operating and sale leaseback transactions. The Company is currently paying an annual fee of 0.50% on the amounts outstanding on the Master Shelf Agreement. This fee will continue until it receives an implied investment grade rating on its senior secured debt from Moody's Investors Service or Standard & Poor's. Borrowings under the Master Shelf Agreement are guaranteed and secured via a pledge of the stock of all of its material subsidiaries.

In October 2001, the Company made scheduled principal repayments to Prudential totaling $33.3 million. The Company intends to finance the $8.3 million payment due in October 2002 with funds available on the Revolving Credit Facility.

Senior Subordinated Notes. In 1999, the company 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 tradeable notes under the same terms and conditions. The Senior Subordinated Notes bear interest at 10% per annum and were priced at 99.225% to yield 10.125%. These notes contain maintenance covenants which include limitations on debt incurrence, restricted payments, liens and sales of assets. Under the calculation limiting restricted payments, including common dividends, approximately $41.1 million was available at December 31, 2001. The Senior Subordinated Notes are unsecured and are guaranteed on a subordinated basis by some of its subsidiaries. The Company incurred approximately $5.0 million in offering commissions and expenses which have been capitalized and are being amortized over the term of the notes.

Covenant Compliance. The Company was in compliance with all covenants in its debt agreements at December 31, 2001. Taking into account all the covenants contained in these agreements, the Company had approximately $122 million of available borrowing capacity at December 31, 2001.

Approximate future maturities of long-term debt in the year indicated are as follows at December 31, 2001 (000s):

The estimated fair values of the Company's financial instruments have been determined by the Company using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided herein are not necessarily indicative of the amount that the Company could realize upon the sale or refinancing of such financial instruments.

The following methods and assumptions were used by the Company in estimating the fair value of its financial instruments:

Cash and cash equivalents, trade accounts receivable and accounts payable. Due to the short-term nature of these instruments, the carrying value approximates the fair value.

Long-term debt. The Company's long-term debt was primarily comprised of fixed rate facilities. Fair market value for this debt was estimated using discounted cash flows based upon the Company's current borrowing rates for debt with similar maturities. The remaining portion of the long-term debt was borrowed on a revolving basis which accrues interest at current rates; as a result, carrying value approximates fair value of this outstanding debt.

Derivative Contracts. Fair value represents the amount at which the instrument could be exchanged in a current arms-length transaction.

The provision (benefit) for income taxes for the years ended December 31, 2001, 2000 and 1999, excluding the tax effect of the extraordinary items, is comprised of (000s):

			2001			2000		1999
Current:
	Federal		$	14,074		$	250	$	2,261
	State			(400	)		600		—

	Total Current			13,674			850		2,261

Deferred:
	Federal			41,225			31,497		(11,004	)
	State			1,590			1,215		(424	)

	Total Deferred			42,815			32,712		(11,428	)

		Total tax provision (benefit)	$	56,489		$	33,562	$	(9,167	)

The tax benefit allocated to the extraordinary charges were $997,000 and $628,000 for the years ended December 31, 2000 and 1999, respectively.

Temporary differences and carry-forwards which give rise to the deferred tax liabilities (assets) at December 31, 2001 and 2000, net of the tax effect of the extraordinary items, are as follows (000s):

		2001			2000
Property and equipment		$	167,663		$	137,042
Differences between the book and tax basis of acquired assets			11,560			12,509
Hedging derivatives			9,835			—

	Total deferred income tax liabilities		189,058			149,551

Alternative Minimum Tax ("AMT") credit carry-forwards			(36,672	)		(23,640	)
Net Operating Loss ("NOL") carry-forwards			(33,640	)		(58,231	)

	Total deferred income tax assets		(70,312	)		(81,871	)

	Net deferred income taxes payable	$	118,746		$	67,680

The change in the net deferred income taxes in 2001 includes a $1.6 million tax benefit associated with the disqualifying dispositions of incentive stock options. The Company expects to realize such tax benefit.

The differences between the provision (benefit) for income taxes at the statutory rate and the actual provision (benefit) for income taxes, before the tax effect of extraordinary items, for the years ended December 31, 2001, 2000 and 1999 are summarized as follows (000s):

At December 31, 2001, the Company had NOL carry-forwards for federal and state income tax purposes and AMT credit carry-forwards for federal income tax purposes of approximately $92.4 million and $36.7 million, respectively. These carry-forwards expire as follows (000s):

Expiration Dates		NOL		AMT
2007		$	180	$	—
2011			4,206		—
2012			39,210		—
2018			48,833		—
No expiration			—		36,672

	Total	$	92,429	$	36,672

The Company believes that the NOL carry-forwards and AMT credit carry-forwards will be utilized prior to their expiration because they are substantially offset by existing taxable temporary differences reversing within the carry-forward period or are expected to be realized by achieving future profitable operations based on the Company's dedicated and owned reserves, past earnings history and projections of future earnings.

Western Gas Resources, Inc., v. Amerada Hess Corporation, District Court, Denver County, Colorado, Civil Action No. 00-CV-1433. The Company was a defendant in prior litigation, styled as Berco Resources, Inc. v. Amerada Hess Corporation and Western Gas Resources, Inc., United States District Court, District of Colorado, Civil Action No. 97-WM-1332, which was settled in 2000 for an amount which did not have a material impact on its results of operations or financial position. The company is seeking reimbursement from Amerada Hess under a contractual indemnity. The Company amended its original complaint and requested a jury trial in this case. Amerada Hess filed a new complaint based upon the same factual issues as the original complaint and these cases were consolidated and are set for trial in June 2002. Both parties filed cross motions for summary judgment.

Barrett Resources Corporation and Lance Oil & Gas Company, Inc. (together the Plaintiffs) v. Westport Oil and Gas Company, Inc., (Defendant) Civil Action No. 00CV6973, District Court, City and County of Denver, Colorado. On September 15, 2000 Plaintiffs, including The Company's subsidiary Lance Oil & Gas Company, filed a complaint for damages and declaratory relief related to a dispute arising under a Farmout Agreement between the parties dated September 26, 1995, as amended. The dispute centers on Plaintiffs' alleged delay of drilling of wells on a portion of the acreage covered by the Farmout Agreement. In October 2000, Defendant counterclaimed that the Farmout Agreement was terminated due to Plaintiffs' alleged delay of drilling. In July 2001, Plaintiffs notified Defendant of the commencement of drilling eleven wells on the acreage covered by the Farmout Agreement. In August 2001, Defendant filed supplemental counterclaims which included claims for trespass, conversion, accounting and constructive trust on the eleven wells drilled by Plaintiff and compensatory and exemplary damages in connection with these wells. In December 2001, the parties entered into a settlement of this case, whereby the parties will jointly develop the acreage. In December 2001, the District Court dismissed the case with prejudice.

Other Litigation. The Company is involved in various other litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims will not, individually or in the aggregate have a material adverse effect on its financial position or results of operations.

Lease Commitments. The Company has entered into leasing arrangements primarily for compression equipment in the Powder River coal bed development. These leases are classified as operating leases and have terms ranging from two to ten years. Rental payments under operating leases have totaled $3.1 million, $3.4 million and $4.5 million in 2001, 2000 and 1999, respectively. The majority of the leases have purchase options at various times throughout the primary terms of the agreements and have renewal provisions. Future operating lease payments by year under these leases are as follows (in 000s):

Firm Transportation Capacity. The Company enters into firm transportation agreements with interstate pipeline companies as parts of its marketing operations and to ensure that its equity production has access to downstream markets. To the extent that these contracts are in support of its marketing operations, the agreements are classified as derivatives in accordance with SFAS No. 133 and the difference between fair value and cost is included in income. These agreements have terms ranging from three months to fifteen years. Payments under these agreements have totaled $8.8 million, $15.7 million and $18.1 million in 2001, 2000 and 1999, respectively. In addition, some of these contracts contain provisions requiring us to pay the fees associated with the contract whether or not the service is used. Future payments by year under these agreements are as follows (in 000s):

Storage Capacity. The Company enters into storage agreements with various third-parties primarily as part of its marketing operations. To the extent that these contracts are in support of its marketing operations, the agreements are classified as derivatives in accordance with SFAS No. 133 and the difference between fair value and cost is included in income. Payments under these agreements have totaled $3.9 million, $6.2 million and $6.2 million in 2001, 2000 and 1999, respectively. As of December 31, 2001, we had contracts in place for approximately 16.3 Bcf of storage capacity at various third-party facilities. The fees associated with these contracts at December 31, 2001 do not exceed $0.61 per Mcf of annual capacity and the associated contract periods range from three months to three years. These agreements have terms ranging from three months to three years. Future payments by year under these agreements are as follows (in 000s):

The Company operates in four principal business segments, as follows: Gas Gathering, Processing and Treating, Exploration and Production, Marketing and Transportation. These segments are separately monitored by management for performance against its internal forecast and are consistent with the Company's internal financial reporting package. These segments have been identified based upon the differing products and services, regulatory environment and the expertise required for these operations.

In the Gas Gathering, Processing and Treating segment, the Company connects producers' wells (including those of the Exploration and Production segment) to its gathering systems for delivery to its processing or treating plants, process the natural gas to extract NGLs and treat the natural gas in order to meet pipeline specifications. The Marketing segment sells the residue gas and NGLs extracted at its processing facilities.

The activities of the Exploration and Production segment include the exploration and development of gas properties primarily in basins where the Company's gathering and processing facilities are located. The majority of the production from these properties is sold by the Marketing segment.

The Company's Marketing segment buys and sells gas and NGLs nationwide and in Canada from or to a variety of customers. In addition, this segment also markets gas and NGLs produced by the Company's gathering, processing and production assets. Also included in this segment are the Company's Canadian marketing operations (which are immaterial for separate presentation). The Marketing segment also includes gains and losses associated with the Company's equity gas and NGL hedging program of $11.4 million, $(38.9) million and $(10.9) million for the years ended December 31, 2001, 2000 and 1999, respectively.

The Transportation segment reflects the operations of the Company's MIGC and MGTC pipelines. The majority of the revenue presented in this segment is derived from transportation of residue gas.

The following table sets forth the Company's segment information as of and for the years ended December 31, 2001, 2000 and 1999 (in 000s). Due to the Company's integrated operations, the use of allocations in the determination of business segment information is necessary. Inter-segment revenues are valued at prices comparable to those of unaffiliated customers.

Retirement Plan. A discretionary retirement plan (a defined contribution plan) exists for all Company employees meeting certain service requirements. The Company may make annual discretionary contributions to the plan as determined by the board of directors and, in 2000, provided for a match of 50% of employee contributions on the first 4% of employee compensation contributed. Effective January 2001, the match of employee contributions has been increased to a sliding scale of 60% to 100% of the first 5% of employee compensation based upon years of service. Contributions are made to mutual funds and to purchase Company stock for which Fidelity Management Trust Company acts as trustee. The discretionary contributions made by the Company were $2.3 million, $2.3 million and $1.7 million, for the years ended December 31, 2001, 2000 and 1999, respectively. The matching contributions were approximately $1.3 million, $470,000 and $541,000 for the years ended December 31, 2001, 2000 and 1999, respectively.

Key Employees' Incentive Stock Option Plan and 1987 Non-Employee Directors Stock Option Plan. Effective April 1987, the board of directors of the Company adopted a Key Employees' Incentive Stock Option Plan ("Key Employee Plan") and a Non-Employee Director Stock Option Plan ("1987 Directors Plan") that authorized the granting of options to purchase 250,000 and 20,000 shares of the Company's Common Stock, respectively. Each of these plans have terminated. The Company loaned to certain employees, an amount sufficient to exercise their options under these plans. The loan and accrued interest will be forgiven if the employee is continually employed by the Company and upon a resolution of the board of directors. As of December 31, 2001 and 2000, loans related to 75,000 shares of Common Stock totaling $803,000, respectively, were outstanding under these terms.

1999 Non-Employee Directors Stock Option Plan. Effective March 1999, the board of directors of the Company adopted a 1999 Non-Employee Directors' Stock Option Plan ("1999 Directors Plan") that authorized the granting of options to purchase 15,000 shares of the Company's Common Stock. During 1999, the board approved grants totaling 15,000 options to several board members. Under this plan, each of these options becomes exercisable as to 33¹/3% of the shares covered by it on each anniversary from the date of grant. 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.

1993, 1997 and 1999 Stock Option Plans. The 1993 Stock Option Plan ("1993 Plan"), the 1997 Stock Option Plan ("1997 Plan"), and the 1999 Stock Option Plan ("1999 Plan") became effective on March 29, 1993, May 21, 1997, and May 21, 1999, respectively, after approvals by the Company's stockholders. Each plan is intended to be an incentive stock option plan in accordance with the provisions of Section 422 of the Internal Revenue Code of 1986, as amended. The Company has reserved 1,000,000 shares of Common Stock for issuance upon exercise of options under each of the 1993 Plan and the 1997 Plan and 750,000 shares of Common Stock for issuance upon exercise of options under the 1999 Plan. The 1993 Plan, the 1997 Plan and the 1999 Plan will terminate on the earlier of March 29, 2003, May 21, 2007 and May 21, 2009, respectively, or the date on which all options granted under each of the plans have been exercised in full.

Effective January 1, 2001, these plans were amended to allow for the exercise of stock options granted under these plans by the surrender to the Company of previously acquired shares of the Company's common stock. This amendment allows for the constructive exchange of Company stock already owned in payment for shares to be received under the option exercise. The price for the exchanged shares is the average closing price of the Company common stock for the ten days preceding the granting of an option.

Chief Executive Officer's Plan. Pursuant to the Employment Agreement, dated October 15, 2001, and the Stock Option Agreement, dated as of November 1, 2001, between the Company and Peter A. Dea, non-qualified stock options were granted for the purchase of 300,000 shares of the Company's common stock. The exercise price of the options was equal to $5.00 below the closing price per share on the effective date of the Employment Agreement. The stock options are subject to the conditions of the Agreements and vest equally over four years. The difference between the closing price on the effective date and the exercise price is being amortized over four years as compensation expense.

Under each of the plans, the board of directors of the Company determines and designates from time to time those employees of the Company to whom options are to be granted. If any option terminates or expires prior to being exercised, the shares relating to such option are released and may be subject to re-issuance pursuant to a new option. The board of directors has the right to, among other things, fix the method by which the price is determined and the terms and conditions for the grant or exercise of any option. The purchase price of the stock under each option shall be the average closing price for the ten days prior to the grant. Under the 1993 Plan, options granted vest 20% each year on the anniversary of the date of grant. Under the 1997 and 1999 Plans, the board of directors has the authority to set the vesting schedule from 20% per year to 33¹/3% per year. Under each of the plans, the employee must exercise the option within five years of the date each portion vests.

In March 1999, certain officers of the Company were granted a total of 300,000 options, which vest ratably over the next three years, under the 1997 Plan. The exercise price of $5.51 per share was determined by using the average stock price for the ten trading days prior to the grant date. In exchange, these officers were required to relinquish a total of 246,200 vested and unvested options at prices ranging from $18.63 to $34.00 per share.

The following table summarizes the number of stock options exercisable and available for grant under the Company's benefit plans:

The following table summarizes the stock option activity under the Company's benefit plans:

			Key Employee Plan		1987 Directors Plan		1999 Directors Plan		1993 Plan		1997 Plan		1999 Plan		Chief Executive Officer's Plan
Balance 12/31/98				75,000		13,500		—		892,476		236,600		—		—
	Granted	$	4.59-17.11		—		—		15,000		—		505,500		35,266		—
	Exercised	$	10.71-16.50		—		(8,500	)	—		(1,938	)	(3,300	)	—		—
	Forfeited or canceled	$	4.59-35.50		(75,000	)	(5,000	)	—		(324,664	)	(92,100	)	—		—
Balance 12/31/99				—		—		15,000		565,874		646,700		35,266		—
	Granted	$	12.58-23.45		—		—		—		—		—		115,300		—
	Exercised	$	4.59-20.69		—		—		(3,317	)	(59,621	)	(136,722	)	(1,000	)	—
	Forfeited or canceled	$	4.59-35.00		—		—		—		(38,592	)	(8,601	)	(9,500	)	—
Balance 12/31/00				—		—		11,683		468,021		501,377		140,966		—
	Granted	$	25.01-36.34		—		—		—		—		—		407,200		300,000
	Exercised	$	4.59-35.00		—		—		—		(201,940	)	(150,056	)	(16,740	)	—
	Forfeited or canceled	$	4.59-36.34		—		—		—		(37,891	)	(2,501	)	(19,600	)	—
Balance 12/31/01				—		—		11,683		228,190		348,820		511,826		300,000

The following table summarizes the weighted average option exercise price information under the Company's benefit plans:

SFAS No. 123 encourages companies to record compensation expense for stock-based compensation plans at fair value. As permitted under SFAS No. 123, the Company has elected to continue to measure compensation costs for such plans as prescribed by APB No. 25. SFAS No. 123 requires pro forma disclosures for each year that a statement of operations is presented. Such information was only calculated for the options granted under the 1993 Plan, the 1997 Plan, the 1999 Plan, and the 1999 Directors' Plan, as there were no grants under any other plans. The weighted average fair value of options granted under the 1997 Plan was $9.56 for the years ended December 31, 1999. There were no grants under the 1997 Plan during the years ended December 31, 2001 and 2000. The weighted average fair value of options granted under the 1999 Plan was $19.26, $21.20 and $6.82 for the years ended December 31, 2001, 2000 and 1999, respectively. The weighted average fair value of options granted under the 1999 Directors' Plan was $9.12 for the year ended December 31, 1999. The weighted average fair value of options granted under the Chief Executive Officer's Plan was $21.13 for the year ended December 31, 2001. The weighted average fair value of options granted was estimated using the Black-Scholes option-pricing model with the following assumptions:

											1999 Directors' Plan
	1999 Plan		1997 Plan
	Chief Executive Officers Plan 2001
	2001		2000		1999		1999		1998		1999
Risk-free interest rate	5.16	%	5.95	%	6.96	%	6.96	%	5.3	%	6.96	%	5.16	%
Expected life (in years)	5		5		5		5		6		5		5
Expected volatility	56	%	54	%	51	%	51	%	45	%	51	%	56	%
Expected dividends (quarterly)	$.05		$.05		$.05		$.05		$.05		$.05		$.05

Had compensation expense for the Company's 2000, 1999 and 1998 grants for stock-based compensation plans been determined consistent with the fair value method under SFAS No. 123, the Company's net income (loss), income (loss) attributable to common stock, earnings (loss) per share of common stock and earnings (loss) per share of common stock—assuming dilution would approximate the pro forma amounts below (000s, except per share amounts):

	2001		2000		1999
	As Reported		Pro forma		As Reported	Pro forma		As Reported		Pro forma
Net income (loss)	$	95,637		$	93,120	$	56,108		$	54,374	$	(17,124	)	$	(18,589	)
Net income (loss) attributable common stock		84,470			81,954		45,692			43,958		(27,563	)		(29,028	)
Earnings (loss) per share of common stock		2.59			2.52		1.42			1.36		(.86	)		(.90	)
Earnings (loss) per share of common stock—assuming dilution	$	2.48		$	2.41	$	1.39		$	1.34	$	(.86	)	$	(.90	)

The fair market value of the options at grant date is amortized over the appropriate vesting period for purposes of calculating compensation expense.

NOTE 11—SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED):

Costs. The following tables set forth capitalized costs at December 31, 2001, 2000 and 1999 and costs incurred for oil and gas producing activities for the years ended December 31, 2001, 2000 and 1999 (000s):

Results of Operations. The results of operations for oil and gas producing activities, excluding corporate overhead and interest costs, for the years ended December 31, 2001, 2000 and 1999 are as follows (000s):

Reserve Quantity Information. Reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and of future net cash flows expected therefrom 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. Further, the volumes considered to be commercially recoverable fluctuate with changes in commodity prices and operating costs. Any significant revision of reserve estimates could materially adversely affect the Company's financial condition and results of operations.

The following table sets forth information for the years ended December 31, 2001, 2000 and 1999 with respect to changes in the Company's proved developed and undeveloped reserves, all of which are in the United States.

Standardized Measures of Discounted Future Net Cash Flows. Estimated discounted future net cash flows and changes therein were determined in accordance with SFAS No. 69, "Disclosures about Oil and Gas Producing Activities." Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.

Future cash inflows are computed by applying year-end prices of oil and gas relating to the Company's proved reserves to the year-end quantities of those reserves.

The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company's expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company's control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company's proved oil and gas reserves. Permanent differences in oil and gas related tax credits and allowances are recognized.

An annual discount rate of 10% was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

Information with respect to the Company's estimated discounted future cash flows from its oil and gas properties for the years ended December 31, 2001, 2000 and 1999 is as follows (000s):

Principal changes in the Company's estimated discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows (000s):

The following summarizes certain quarterly results of operations (000s, except per share amounts):

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

Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12 and 13 are omitted because the Company will file a definitive proxy statement (the "Proxy Statement") pursuant to Regulation 14A under the Securities Exchange Act of 1934 not later than 120 days after the close of the fiscal year. The information required by such Items will be included in the Proxy Statement to be so filed for the Company's annual meeting of stockholders scheduled for May 17, 2002 and is hereby incorporated by reference.

A report on Form 8-K was filed on October 17, 2001 announcing the appointment of Mr. Peter A. Dea to the position of President, Chief Executive Officer and Director effective November 1, 2001 and the promotion of Mr. William J. Krysiak to the position of Chief Financial Officer effective October 15, 2001.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado on March 14, 2002.

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

	Year Ended December 31,
	2001		%	2000		%	1999		%
Sale of residue gas	$	2,844,580	84.8	$	2,624,409	80.0	$	1,501,066	78.6
Sale of natural gas liquids		424,082	12.6		590,936	18.0		346,819	18.1
Processing, transportation and storage revenue		55,398	1.7		53,156	1.6		48,994	2.6
Non-cash change in fair value of derivatives		19,906	0.6		—	—		—	—
Other, net		10,986	0.3		13,487	0.4		13,845	0.7

	$	3,354,952	100.0	$	3,281,988	100.0	$	1,910,724	100.0

		December 31,
		2001(1)		2000		1999
State/Basin		Gas (MMcf)	Oil (MBbl)	Gas (MMcf)	Oil (MBbl)	Gas (MMcf)	Oil (MBbl)
Colorado—Sand Wash Basin		11,693	51	6,658	30	6,452	40
Wyoming:
	Coal Bed Methane	392,950	7	350,512	—	236,277	—
	Green River Basin	65,594	603	51,324	409	29,089	289

Total		470,237	661	408,494	439	271,818	329

						Average for the Year Ended December 31, 2001
				Gas Gathering System Miles(2)	Gas Throughput Capacity (MMcfD)(3)	Average for the Year Ended December 31, 2001
Facilities(1)			Year Placed In Service	Gas Gathering System Miles(2)	Gas Throughput Capacity (MMcfD)(3)	Gas Throughput (MMcfD)(4)	Gas Production (MMcfD)(5)	NGL Production (MGalD)(5)
*Texas*
	Gomez Treating(6)		1971	386	280	100	92	—
	Midkiff/Benedum		1949	2,201	165	146	96	888
	Mitchell Puckett Gathering(6)		1972	93	120	72	46	1
*Louisiana*
	Toca(7)(8)		1958	—	160	137	131	108
*Wyoming*
	Coal Bed Methane Gathering		1990	1,240	223	282	149	—
	Fort Union Gas Gathering		1999	106	635	307	307	—
	Granger(7)(9)(10)		1987	499	235	157	134	269
	Hilight Complex(7)		1969	626	124	59	54	75
	Kitty/Amos Draw(7)		1969	314	17	9	6	37
	Lincoln Road(10)		1988	149	50	18	16	31
	Newcastle(7)		1981	146	5	3	2	19
	Red Desert(7)		1979	111	42	15	13	26
	Rendezvous Gas Services(14)
	Reno Junction(9)		1991	—	—	—	—	95
*Oklahoma*
	Chaney Dell		1966	2,076	130	71	56	221
	Westana		1981	994	45	66	61	18
*New Mexico*
	San Juan River(6)		1955	140	60	24	24	16
*Utah*
	Four Corners Gathering		1988	104	15	2	2	6

		Total		9,185	2,306	1,468	1,189	1,810

				Average for the Year Ended December 31, 2001
Transportation Facilities(1)		Year Placed In Service	Transportation Miles(2)	Pipeline Capacity (MMcfD)(2)	Gas Throughput (MMcfD)(4)
MIGC(11)(13)		1970	245	130	180
MGTC(12)		1963	252	18	13

	Total		497	148	193

	Year Ended December 31,
	2001		2000			1999			1998			1997
	(000s, Except Per Share Amounts And Operating Data)
Statement of Operations:
Revenues	$	3,354,952	$	3,281,988		$	1,910,724		$	2,117,088		$	2,380,545
Gross profit(a)		200,780		149,155			67,289			50,090			89,055
Income (loss) before income taxes		152,126		91,384			(25,184	)(b)		(105,623	)(b)		2,220	(b)
Provision (benefit) for income taxes		56,489		33,562			(9,167	)		(38,418	)		733
Income (loss) before extraordinary items		95,637		57,822			(16,017	)(b)		(67,205	)(b)		1,487	(b)
Extraordinary charge for early extinguishment of debt		—		(1,714	)(c)		(1,107	)(c)		—			—
Net income (loss)		95,637		56,108			(17,124	)(b)		(67,205	)(b)		1,487	(b)
Earnings (loss) per share of common stock		2.59		1.42			(.86	)		(2.42	)		(.28	)
Earnings (loss) per share of common stock—assuming dilution		2.48		1.39			(.86	)		(2.42	)		(.28	)
Other financial data:
Net cash provided by operating activities		153,267		116,262			95,184			(35,570	)		114,755
EBITDA, as adjusted(d)		230,670		173,357			89,913			79,291			118,404
Capital expenditures		163,977		108,536			80,089			105,216			198,901
Balance Sheet Data (at year end):
Total assets		1,267,942		1,431,422			1,049,486			1,219,377			1,348,276
Long-term debt		366,667		358,700			378,250			504,881			441,357
Stockholders' equity		473,352		391,534			349,743			385,216			468,112
Dividends on preferred stock		11,167		10,416			10,439			10,439			10,439
Dividends on common stock		6,524		6,448			6,426			6,430			6,427
Dividends per share of common stock		.20		.20			.20			.20			.20
Operating Data:
Average gas sales (MMcf/D)		1,960		1,835			1,900			2,200			1,975
Average NGL sales (MGal/D)		2,350		3,085			2,885			4,730			4,585
Average gas volumes gathered (MMcf/D)		1,161		1,248			1,168			1,162			1,229
Facility capacity (MMcf/D)		2,574		2,374			2,485			2,237			2,302
Average gas prices ($/Mcf)	$	3.97	$	3.90		$	2.17		$	2.01		$	2.30
Average NGL prices ($/Gal)	$	.49	$	.52		$	.33		$	.26		$	.36

Part	Item(s)
I.	1 and 2.	Business and Properties
		General
		Business Strategy
		2002 Capital Budget
		Upstream Operations
		Powder River Basin Coal Bed Methane
		Green River Basin
		Sand Wash Basin
		Production Information
		Midstream Operations
		Gas Gathering, Processing and Treating
		West Texas
		Oklahoma
		Principal Facilities
		Marketing
		Transportation
		Environmental
		Competition
		Regulation
		Employees
	3.	Legal Proceedings
	4.	Submission of Matters to a Vote of Security Holders
II.	5.	Market for the Registrant's Common Equity and Related Stockholder Matters
	6.	Selected Financial Data
	7.	Management's Discussion and Analysis of Financial Condition and Results of Operations
	7.a	Quantitative and Qualitative Disclosures About Market Risk
	8.	Financial Statements and Supplementary Data
	9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
III.	10.	Directors and Executive Officers of the Registrant
	11.	Executive Compensation
	12.	Security Ownership of Certain Beneficial Owners and Management
	13.	Certain Relationships and Related Transactions
IV.	14.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K

	Year Ended December 31,
	Year Ended December 31,				Percent Change
	2001		2000		Percent Change
Financial results:
Revenues	$	3,354,952	$	3,281,988	2
Gross profit		200,780		149,155	35
Net income (loss)		95,637		56,108	70
Income (loss) per share of common stock		2.59		1.42	82
Income (loss) per share of common stock—assuming dilution		2.48		1.39	78
Net cash provided by operating activities	$	153,267	$	116,262	32
Operating data:
Average gas sales (MMcf/D)		1,960		1,835	7
Average NGL sales (MGal/D)		2,350		3,085	(24	)
Average gas prices ($/Mcf)	$	3.97	$	3.90	2
Average NGL prices ($/Gal)	$	.49	$	.52	(6	)

	Payments by Period
Type of Obligation	Total Obligation		Due in 2002		Due in 2003-2004		Due in 2005-2006		Due Thereafter
Long-term Debt	$	366,667	$	8,333	$	173,334	$	20,000	$	165,000
Guarantee of Fort Union Project Financing		7,342		—		—		—		7,342
Operating Leases		22,220		5,611		6,696		6,113		3,800
Firm Transportation Capacity Agreements		218,706		29,207		45,732		44,513		99,254
Firm Storage Capacity Agreements		11,193		5,129		3,750		658		1,656

Total Contractual Cash Obligations	$	626,128	$	48,280	$	229,512	$	71,284	$	277,052

Issue Date	Amount		Interest Rate		Final Maturity	Principal Payments Due
October 27, 1992	$	16,666	7.99	%	October 27, 2003	$8,333 on October 27, 2002 and 2003
December 27, 1993		25,000	7.23	%	December 27, 2003	single payment at maturity
October 27, 1994		25,000	9.24	%	October 27, 2004	single payment at maturity
July 28, 1995		50,000	7.61	%	July 28, 2007	$10,000 on each of July 28, 2003 through 2007

	$	116,666

		/s/ PETER A. DEA Peter A. Dea Chief Executive Officer and President
		/s/ WILLIAM J. KRYSIAK William J. Krysiak Chief Financial Officer (Principal Financial and Accounting Officer)

			December 31,
			2001			2000
ASSETS
Current assets:
	Cash and cash equivalents		$	10,032		$	12,927
	Trade accounts receivable, net			231,724			546,791
	Product inventory			50,773			44,822
	Parts inventory			3,049			3,489
	Assets held for sale			—			25,001
	Assets from price risk management activities			66,271			—
	Other			4,114			2,654

		Total current assets		365,963			635,684

Property and equipment:
	Gas gathering, processing, storage and transportation			912,003			856,982
	Oil and gas properties and equipment (successful efforts method)			193,656			139,084
	Construction in progress			106,385			58,319

				1,212,044			1,054,385
Less: Accumulated depreciation, depletion and amortization				(363,737	)		(306,651	)

Total property and equipment, net				848,307			747,734

Other assets:
	Gas purchase contracts (net of accumulated amortization of $35,329 and $33,357, respectively)			32,826			34,798
	Assets from price risk management activities			2,934			—
	Other			17,912			13,206

	Total other assets			53,672			48,004

Total assets			$	1,267,942		$	1,431,422

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	260,208		$	581,563
	Accrued expenses			23,123			25,094
	Liabilities from price risk management activities			18,075			—
	Dividends payable			3,767			4,205

		Total current liabilities		305,173			610,862
Long-term debt				366,667			358,700
Other long-term liabilities				2,284			2,646
Liabilities from price risk management activities				1,720			—
Deferred income taxes payable				118,746			67,680

Total liabilities				794,590			1,039,888

Commitments and contingent liabilities (Note 8)				—			—
Stockholders' equity:
	Preferred Stock; 10,000,000 shares authorized:
		$2.28 cumulative preferred stock, par value $.10; 591,136 and 1,400,000 shares issued, respectively ($15,885,650 aggregate liquidation preference)		59			140
		$2.625 cumulative convertible preferred stock, par value $.10; 2,760,000 issued ($138,000,000 aggregate liquidation preference)		276			276
	Common stock, par value $.10; 100,000,000 shares authorized; 32,689,009 and 32,361,131 shares issued, respectively			3,293			3,265
	Treasury stock, at cost; 25,016 common shares and 44,290 $2.28 cumulative preferred shares in treasury			(1,907	)		(1,778	)
	Additional paid-in capital			387,505			400,157
	Retained earnings (deficit)			66,128			(11,820	)
	Accumulated other comprehensive income			18,882			2,178
	Notes receivable from key employees secured by common stock			(884	)		(884	)

		Total stockholders' equity		473,352			391,534

Total liabilities and stockholders' equity			$	1,267,942		$	1,431,422

		Shares of $2.28 Cumulative Preferred Stock	$2.625 Cumulative Convertible Preferred Stock	Shares of Common Stock	Shares of Common Stock in Treasury	Shares of $2.28 Cumulative Preferred Stock in Treasury	$2.28 Cumulative Preferred Stock	$2.625 Cumulative Convertible Preferred Stock	Common Stock	Treasury Stock		Additional Paid-In Capital	Retained (Deficit) Earnings		Accumulated Other Compre- hensive Income Net of Tax		Notes Receivable from Key Employees		Total Stock- holders' Equity
Balance at December 31, 1998		1,400,000	2,760,000	32,147,993	25,016	—	140	276	3,217	(788	)	397,344	(17,075	)	3,053		(951	)	385,216
Comprehensive income:
	Net income, 1999	—	—	—	—	—	—	—	—	—		—	(17,124	)	—		—		(17,124	)
	Translation adjustments	—	—	—	—	—	—	—	—	—		—	—		(1,732	)	—		(1,732	)
Stock options exercised		—	—	13,738	—	—	—	—	3	—		155	—		—		—		158
Tax benefit related to stock options		—	—	—	—	—	—	—	—	—		23	—		—		—		23
Loans forgiven		—	—	—	—	—	—	—	—	—		—	—		—		67		67
Dividends declared on common stock		—	—	—	—	—	—	—	—	—		—	(6,426	)	—		—		(6,426	)
Dividends declared on $2.28 cumulative preferred stock		—	—	—	—	—	—	—	—	—		—	(3,194	)	—		—		(3,194	)
Dividends declared on $2.625 cumulative convertible preferred stock		—	—	—	—	—	—	—	—	—		—	(7,245	)	—		—		(7,245	)

Balance at December 31, 1999		1,400,000	2,760,000	32,161,731	25,016	—	140	276	3,220	(788	)	397,522	(51,064	)	1,321		(884	)	349,743
Comprehensive income:
	Net income, 2000	—	—	—	—	—	—	—	—	—		—	56,108		—		—		56,108
	Translation adjustments	—	—	—	—	—	—	—	—	—		—	—		857		—		857
Stock options exercised		—	—	199,400	—	—	—	—	45	—		2,635	—		—		—		2,680
Tax benefit related to stock options		—	—	—	—	—	—	—	—	—		—	—		—		—		—
Loans forgiven		—	—	—	—	—	—	—	—	—		—	—		—		—		—
Dividends declared on common stock		—	—	—	—	—	—	—	—	—		—	(6,448	)	—		—		(6,448	)
Dividends declared on $2.28 cumulative preferred stock		—	—	—	—	—	—	—	—	—		—	(3,171	)	—		—		(3,171	)
Dividends declared on $2.625 cumulative convertible preferred stock		—	—	—	—	—	—	—	—	—		—	(7,245	)	—		—		(7,245	)
Repurchase of $2.28 cumulative preferred stock		—	—	—	—	39,190	—	—	—	(990	)	—	—		—		—		(990	)

				Shares of $2.28 Cumulative Preferred Stock		$2.625 Cumulative Convertible Preferred Stock	Shares of Common Stock	Shares of Common Stock in Treasury	Shares of $2.28 Cumulative Preferred Stock in Treasury	$2.28 Cumulative Preferred Stock			$2.625 Cumulative Convertible Preferred Stock		Common Stock		Treasury Stock			Additional Paid-In Capital			Retained (Deficit) Earnings			Accumulated Other Compre- hensive Income Net of Tax			Notes Receivable from Key Employees			Total Stock- holders' Equity
Balance at December 31, 2000				1,400,000		2,760,000	32,361,131	25,016	39,190	$	140		$	276	$	3,265	$	(1,778	)	$	400,157		$	(11,820	)	$	2,178		$	(884	)	$	391,534
Comprehensive income:
	Net income, 2001			—		—	—	—	—		—			—		—		—			—			95,637			—			—			95,637
	Translation adjustments			—		—	—	—	—		—			—		—		—			—			—			(440	)		—			(440	)

		Cumulative effect of change in accounting principal		—		—	—	—	—		—			—		—		—			—			—			(22,527	)		—			(22,527	)
		Reclassification adjustment for settled contracts		—		—	—	—	—		—			—		—		—			—			—			21,988			—			21,988
		Changes in fair value of outstanding hedge positions		—		—	—	—	—		—			—		—		—			—			—			5,772			—			5,772
		Fair value of new hedge positions		—		—	—	—	—		—			—		—		—			—			—			11,911			—			11,911

		Ending accumulated derivative gain		—		—	—	—	—		—			—		—		—			—			—			17,144			—			17,144

			Total comprehensive income, net of tax																														112,341
Stock options exercised				—		—	327,878	—	—		—			—		28		—			5,163			—			—			—			5,191
Effect of re-priced options				—		—	—	—	—		—			—		—		—			(170	)		—			—			—			(170	)
Tax benefit related to stock options				—		—	—	—	—		—			—		—		—			1,584			—			—			—			1,584
Dividends declared on common stock				—		—	—	—	—		—			—		—		—			—			(6,524	)		—			—			(6,524	)
Dividends declared on $2.28 cumulative preferred stock				—		—	—	—	—		—			—		—		—			—			(2,640	)		—			—			(2,640	)
Dividends declared on $2.625 cumulative convertible preferred stock				—		—	—	—	—		—			—		—		—			—			(7,244	)		—			—			(7,244	)
Redemption of $2.28 cumulative preferred stock				(808,864	)	—	—	—	—		(81	)		—		—		—			(19,229	)		(1,281	)		—			—			(20,591	)
Repurchase of $2.28 cumulative preferred stock				—		—	—	—	5,100		—			—		—		(129	)		—			—			—			—			(129	)

Balance at December 31, 2001				591,136		2,760,000	32,689,009	25,016	44,290	$	59		$	276	$	3,293	$	(1,907	)	$	387,505		$	66,128		$	18,882		$	(884	)	$	473,352

2002		$	8,333
2003			43,334
2004			130,000
2005			10,000
2006			10,000
Thereafter			165,000

	Total	$	366,667

	December 31, 2001				December 31, 2000
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(000s)				(000s)
Cash and cash equivalents	$	10,032	$	10,032	$	12,927	$	12,927
Trade accounts receivable		231,724		231,724		546,791		546,791
Accounts payable		260,208		260,208		581,563		581,563
Long-term debt		366,667		370,329		358,700		359,011
Derivative contracts		49,411		49,411		—		5,107

		2001		%	2000		%	1999			%
Income tax (benefit) before effect of extraordinary item at statutory rate		$	53,245	35.0	$	31,984	35.0	$	(8,814	)	35.0
State income taxes (benefit), net of federal benefit			2,130	1.4		1,280	1.4		(353	)	1.4
Effect of disallowed loss on sale of stock and other miscellaneous items			1,114	.7		298	.3		—		—

	Total	$	56,489	37.1	$	33,562	36.7	$	(9,167	)	36.4

	Gas Gathering, Treating and Processing		Exploration and Production		Marketing		Transmission		Corporate			Eliminating Entries			Total
Year ended December 31, 2001
Revenues from unaffiliated customers	$	75,629	$	2,381	$	3,233,271	$	8,578	$	1,001		$	—		$	3,320,860
Interest income		1		12		—		—		13,683			(12,860	)		836
Other, net		940		31		31,555		1		729			—			33,256
Inter-segment sales		789,725		117,648		49,309		18,220		(545	)		(974,357	)		—

Total revenues		866,295		120,072		3,314,135		26,799		14,868			(987,217	)		3,354,952

Product purchases		674,296		7,688		3,254,677		—		210			(949,921	)		2,986,950
Plant operating expense		68,468		—		426		9,033		(328	)		(2,066	)		75,533
Oil and gas exploration and production expense		—		49,277		—		—		—			(21,750	)		27,527

Operating margin	$	123,531	$	63,107	$	59,032	$	17,766	$	14,986		$	(13,480	)	$	264,942

Depreciation, depletion and amortization		39,579		17,254		161		1,646		5,522			—			64,162
Interest expense																25,130
Impairment of property & plant																—
Gain on sale of assets																(10,748	)
Selling and administrative expense																34,272

Income before income taxes															$	152,126

Identifiable assets	$	609,699	$	181,814	$	79	$	46,602	$	65,156		$	—		$	903,350

	Gas Gathering, Treating and Processing		Exploration and Production		Marketing			Transmission			Corporate			Eliminating Entries			Total
Year ended December 31, 2000
Revenues from unaffiliated customers	$	59,687	$	865	$	3,271,424		$	8,619		$	103		$	—		$	3,340,698
Interest income		98		6		27			—			27,505			(26,987	)		649
Other, net		1,734		137		(63,226	)		—			1,957			39			(59,359	)
Inter-segment sales		813,802		87,558		94,858			16,484			44			(1,012,746	)		—

Total revenues		875,321		88,566		3,303,083			25,103			29,609			(1,039,694	)		3,281,988

Product purchases		662,319		4,677		3,322,458			(1,021	)		(184	)		(1,002,748	)		2,985,501
Plant operating expense		62,507		451		69			8,856			(264	)		(1,727	)		69,892
Oil and gas exploration and production expense		32		28,613		—			—			—			(9,124	)		19,521

Operating margin	$	150,463	$	54,825	$	(19,444	)	$	17,268		$	30,057		$	(26,095	)	$	207,074

Depreciation, depletion and amortization		36,284		14,161		161			1,645			5,668			—			57,919
Interest expense																		33,460
Impairment of property & plant																		—
Gain on sale of assets																		(9,406	)
Selling and administrative expense																		33,717

Income before income taxes																	$	91,384

Identifiable assets	$	537,729	$	129,807	$	55		$	43,111		$	42,441		$	—		$	753,143

	Gas Gathering, Treating and Processing		Exploration and Production		Marketing			Transmission		Corporate			Eliminating Entries			Total
Year ended December 31, 1999
Revenues from unaffiliated customers	$	43,257	$	2,895	$	1,858,776		$	7,498	$	554		$	—		$	1,912,980
Interest income		2		1		100			—		25,715			(25,435	)		383
Other, net		1,483		—		(7,078	)		413		2,543			—			(2,639	)
Inter-segment sales		389,928		26,137		88,379			16,235		56			(520,735	)		—

Total revenues		434,670		29,033		1,940,177			24,146		28,868			(546,170	)		1,910,724

Product purchases		288,668		2,029		1,939,400			—		—			(514,258	)		1,715,839
Plant operating expense		62,301		68		1,718			11,237		(1,478	)		(6,427	)		67,419
Oil and gas exploration and production expense		535		8,705		(44	)		—		—			—			9,196

Operating margin	$	83,166	$	18,231	$	(897	)	$	12,909	$	30,346		$	(25,485	)	$	118,270

Depreciation, depletion and amortization		35,763		8,181		1,226			1,166		4,645			—			50,981
Interest expense																	33,156
Impairment of property & plant																	1,158
Loss on sale of assets																	29,802
Selling and administrative expense																	28,357

Loss before income taxes																$	(25,184	)

Identifiable assets	$	606,424	$	104,470	$	73		$	70,354	$	18,837		$	—		$	800,158

		Per Share Price Range		Key Employee Plan	1987 Directors Plan	1999 Directors Plan	1993 Plan	1997 Plan	1999 Plan	Chief Executive Officer's Plan
Exercisable:
	December 31, 2001	$	4.59-36.34	—	—	7,789	210,119	211,635	38,837	—
	December 31, 2000	$	4.59-35.00	—	—	1,683	389,806	131,431	11,255	—
	December 31, 1999	$	4.59-35.50	—	—	—	407,787	47,240	—	—
Available for Grant:
	December 31, 2001		—	—	—	—	—	—	287,634	—
	December 31, 2000		—	—	—	—	—	—	608,934	—
	December 31, 1999		—	—	—	—	—	—	714,734	—

		Key Employee Plan			1987 Directors Plan			1999 Directors Plan			1993 Plan			1997 Plan			1999 Plan			Chief Executive Officer's Plan
Balance 12/31/98		$	30.23		$	14.13		$	—		$	20.71		$	16.15		$	—		$	—
	Granted		—			—			5.51			—			5.15			13.58			—
	Excercised		—			(10.71	)		—			(14.53	)		(11.64	)		—			—
	Forfeited or canceled		(30.23	)		(19.94	)		—			(22.79	)		(15.11	)		—			—

Balance 12/31/99			—			—			5.51			19.54			7.72			13.58			—
	Granted		—			—			—			—			—			23.11			—
	Excercised		—			—			(5.51	)		(16.17	)		(7.33	)		(16.21	)		—
	Forfeited or canceled		—			—			—			(26.97	)		(8.66	)		(22.25	)		—

Balance 12/31/00			—			—			5.51			19.35			7.81			20.79			—
	Granted		—			—			—			—			—			34.72			25.01
	Excercised		—			—			—			(19.55	)		(7.22	)		(18.30	)		—
	Forfeited or canceled		—			—			—			(25.50	)		(4.59	)		(29.76	)		—

Balance 12/31/01		$	—		$	—		$	5.51		$	18.15		$	8.08		$	31.61		$	25.01

		2001			2000			1999
Capitalized costs:
	Proved properties	$	194,596		$	119,124		$	74,594
	Unproved properties		40,137			46,890			42,928

Total			234,733			166,014			117,522
	Less accumulated depreciation and depletion		(53,359	)		(36,367	)		(23,003	)

Net capitalized costs		$	181,374		$	129,647		$	94,519

Costs incurred:
Acquisition of properties
	Proved	$	1,624		$	1,571		$	—
	Unproved		5,332			7,203			11,675
Development costs			63,263			35,807			20,973
Exploration costs			2,141			8,397			5,148

Total costs incurred		$	72,360		$	52,978		$	37,796

			2001			2000			1999
Revenues from sale of oil and gas:
	Sales		$	4,517		$	4,658		$	2,081
	Transfers			110,532			80,353			30,537

		Total		115,049			85,011			32,618
Production costs				(49,421	)		(27,108	)		(8,002	)
Exploration costs				(3,234	)		(2,213	)		(1,492	)
Depreciation, depletion and amortization				(17,175	)		(13,423	)		(11,536	)
Impairment of oil and gas properties				—			—			—
Income tax benefit (expense)				(15,827	)		(14,793	)		(3,921	)

Results of operations			$	29,392		$	27,474		$	7,667

		Natural Gas (MMcf)		Crude Oil (MBbls)
Proved reserves:
	December 31, 1998	238,930		555
	Revisions of previous estimates	13,152		(2	)
	Extensions and discoveries	45,688		14
	(Sales) Purchases of reserves in place	(7,964	)	(126	)
	Production	(17,988	)	(112	)

	December 31, 1999	271,818		329
	Revisions of previous estimates	(11,889	)	(194	)
	Extensions and discoveries	176,584		332
	(Sales) Purchases of reserves in place	—		—
	Production	(28,019	)	(28	)

	December 31, 2000	408,494		439
	Revisions of previous estimates	(18,415	)	(110	)
	Extensions and discoveries	115,672		377
	(Sales) Purchases of reserves in place	—		—
	Production	(35,514	)	(45	)

	December 31, 2001	470,237		661

	Proved developed reserves, included above:
	December 31, 1998	65,733		393
	December 31, 1999	106,626		161
	December 31, 2000	208,218		147
	December 31, 2001	252,266		262

	2001			2000			1999
Future cash inflows	$	691,188		$	2,682,435		$	419,104
Future production costs		(210,242	)		(462,065	)		(121,129	)
Future development costs		(110,365	)		(87,251	)		(57,999	)
Future income tax expense		(108,270	)		(732,327	)		(67,429	)

Future net cash flows		262,311			1,400,792			172,547
10% annual discount for estimated timing of cash flows		(90,941	)		(432,881	)		(59,620	)

Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	171,370		$	967,911		$	112,927

		2001			2000			1999
January 1		$	967,911		$	112,927		$	97,877
	Sales and transfers of oil and gas produced, net of production costs		(65,628	)		(57,903	)		(24,616	)
	Net changes in prices and production costs related to future production		(1,349,674	)		768,840			19,569
	Development costs incurred during the period		50,494			35,807			20,973
	Changes in estimated future development costs		(37,115	)		(21,369	)		(29,725	)
	Changes in extensions and discoveries		57,300			640,501			26,257
	Revisions of previous quantity estimates		(34,596	)		(64,710	)		5,653
	Purchases (sales) of reserves in place		—			—			(5,842	)
	Accretion of discount		147,393			15,706			13,162
	Net change in income taxes		435,285			(461,888	)		(10,381	)

December 31		$	171,370		$	967,911		$	112,927

		Operating Revenues		Gross Profit (a)		Net Income		Earnings Per Share of Common Stock		Earnings Per Share of Common Stock— Assuming Dilution (b)
2001 quarter ended:
	March 31	$	1,197,276	$	69,556	$	40,590	$	1.17	$	1.08
	June 30		887,024		59,853		29,453		.82		.77
	September 30		670,885		37,687		14,773		.37		.36
	December 31		599,767		33,684		10,821		.23		.22

		$	3,354,952	$	200,780	$	95,637	$	2.59	$	2.48

2000 quarter ended:
	March 31	$	565,152	$	31,292	$	13,006	$	.32	$	.32
	June 30		641,816		31,975		10,580		.25		.24
	September 30		909,836		38,816		14,457		.37		.36
	December 31		1,165,184		47,072		18,065		.48		.47

		$	3,281,988	$	149,155	$	56,108	$	1.42	$	1.39

		WESTERN GAS RESOURCES, INC. (Registrant)
		By:		/s/ PETER A. DEA Peter A. Dea Chief Executive Officer, President and Director

/s/ BRION G. WISE Brion G. Wise	Chairman of the Board	March 14, 2002
/s/ WALTER L. STONEHOCKER Walter L. Stonehocker	Vice Chairman of the Board	March 14, 2002
/s/ BILL M. SANDERSON Bill M. Sanderson	Director	March 14, 2002
/s/ LANNY F. OUTLAW Lanny F. Outlaw	Director	March 14, 2002
/s/ RICHARD B. ROBINSON Richard B. Robinson	Director	March 14, 2002
/s/ DEAN PHILLIPS Dean Phillips	Director	March 14, 2002
/s/ WARD SAUVAGE Ward Sauvage	Director	March 14, 2002
/s/ JAMES A. SENTY James A. Senty	Director	March 14, 2002
/s/ JOSEPH E. REID Joseph E. Reid	Director	March 14, 2002
/s/ WILLIAM J. KRYSIAK William J. Krysiak	Chief Financial Officer (Principal Financial and Accounting Officer)	March 14, 2002